UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
x | Annual Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
For the Fiscal Year Ended December 31, 2003
¨ | Transition Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 |
Commission File No. 1-13726
Chesapeake Energy Corporation
(Exact Name of Registrant as Specified in Its Charter)
Oklahoma | 73-1395733 | |
(State or other jurisdiction of incorporation or organization) |
(I.R.S. Employer Identification No.) | |
6100 North Western Avenue Oklahoma City, Oklahoma |
73118 | |
(Address of principal executive offices) | (Zip Code) |
(405) 848-8000
Registrants telephone number, including area code
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class |
Name of Each Exchange on Which Registered | |
Common Stock, par value $.01 | New York Stock Exchange | |
7.875% Senior Notes due 2004 | New York Stock Exchange | |
8.375% Senior Notes due 2008 | New York Stock Exchange | |
8.125% Senior Notes due 2011 | New York Stock Exchange | |
8.5% Senior Notes due 2012 | New York Stock Exchange | |
9.0% Senior Notes due 2012 | New York Stock Exchange | |
7.5% Senior Notes due 2013 | New York Stock Exchange | |
7.75% Senior Notes due 2015 | New York Stock Exchange | |
6.75% Cumulative Convertible Preferred Stock | New York Stock Exchange | |
6.00% Cumulative Convertible Preferred Stock | New York Stock Exchange | |
5.00% Cumulative Convertible Preferred Stock | New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES x NO ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K x
Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). YES x NO ¨
The aggregate market value of our common stock held by non-affiliates on June 30, 2003 was $1,953,097,620. At March 10, 2004, there were 241,463,839 shares of common stock issued and outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
None
PART I
ITEM 1. Business
General
We are one of the six largest independent natural gas producers in the United States in terms of natural gas produced. Chesapeake began operations in 1989 and completed its initial public offering in 1993. Our common stock trades on the New York Stock Exchange under the symbol CHK. Our principal executive offices are located at 6100 North Western Avenue, Oklahoma City, Oklahoma 73118 and our main telephone number at that location is (405) 848-8000. We make available free of charge on our website at www.chkenergy.com our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission. References to us, we and our in this report refer to Chesapeake Energy Corporation together with its subsidiaries.
At the end of 2003, we owned interests in approximately 15,000 producing oil and gas wells. Our primary operating area is the Mid-Continent region of the United States, which includes Oklahoma, western Arkansas, southwestern Kansas and the Texas Panhandle. We are building secondary operating areas in the Permian Basin region of western Texas and eastern New Mexico and in the South Texas and Texas Gulf Coast regions. The following table highlights our growth since 1998:
Years Ended December 31, |
|||||||||||||||||||
2003 |
2002 |
2001 |
2000 |
1999 |
1998 |
||||||||||||||
Production (mmcfe) |
268,356 | 181,478 | 161,451 | 134,179 | 133,492 | 130,277 | |||||||||||||
Proved reserves (mmcfe) |
3,168,575 | 2,205,125 | 1,779,946 | 1,354,813 | 1,205,595 | 1,091,348 | |||||||||||||
Net income (loss) ($ in 000s) |
$ | 312,981 | $ | 40,286 | $ | 217,406 | $ | 455,570 | $ | 33,266 | $ | (933,854 | ) |
Recent Developments
We completed an acquisition of Permian Basin and Mid-Continent oil and gas assets from Concho Resources Inc. in January 2004. We paid approximately $420 million in cash for these assets, $10 million of which was paid in 2003.
We also completed an acquisition of South Texas gas assets in January 2004. We paid $65 million for these assets, $3.3 million of which was paid in 2003.
On January 14, 2004, we issued 23,000,000 shares of common stock at a price to the public of $13.51 per share. We used the net proceeds of this offering of approximately $298.3 million to finance a portion of the acquisitions completed in January 2004.
On January 14, 2004, we completed a public exchange offer in which we retired $458.5 million of our 8.125% senior notes due 2011 and $10.8 million of accrued interest and issued $72.8 million of our 7.75% senior notes due 2015 and $2.8 million of accrued interest and $433.5 million of our 6.875% senior notes due 2016 and $4.1 million of accrued interest.
In January and February of 2004, we issued an additional $37.0 million of our 6.875% senior notes due 2016 and $0.5 million of accrued interest in exchange for $24.3 million of our 8.125% senior notes due 2011 and $0.7 million of accrued interest and $9.1 million of our 7.75% senior notes due 2015 and $0.1 million of accrued interest in four private exchange transactions.
2
Business Strategy
Since Chesapeakes inception in 1989, our goal has been to create value for our investors by building one of the largest onshore natural gas resource bases in the United States. For the past six years, our strategy to accomplish this goal has been to build the dominant operating position in the Mid-Continent region, the third largest gas supply region in the U.S. In building this industry-leading position in the Mid-Continent, we have integrated an aggressive and technologically advanced drilling program with an active property consolidation program focused on small to medium-sized corporate and property acquisitions of up to $500 million.
We have now started to build secondary regions of importance in the Permian Basin and in the South Texas and Texas Gulf Coast regions, areas to which we believe significant elements of our successful Mid-Continent strategy can be transferred. Key elements of this business strategy are further explained below:
| Consistently Making High-Quality Acquisitions. Our acquisition program is focused on small to medium-sized acquisitions of natural gas properties, primarily in the Mid-Continent, that provide high-quality, long-lived production and significant development and higher potential deeper drilling opportunities. Since January 1, 2000, we have acquired $2.8 billion of such properties (largely through 24 separate transactions of greater than $10 million each) at an estimated average cost of $1.31 per mcfe of proved reserves (pro forma for the Concho and South Texas acquisitions closed in January 2004). The vast majority of these acquisitions either increased our ownership in existing wells or fields or added additional drilling locations in our primary Mid-Continent operating area, and more recently in our secondary operating areas. We believe our recently completed acquisitions are significant steps in building a meaningful presence in these secondary operating areas. Because our primary and secondary operating areas contain many small companies seeking liquidity opportunities and larger companies seeking to divest of non-core assets, we expect to find additional attractive acquisition opportunities in the future. |
| Consistently Growing through the Drillbit. One of our most distinctive characteristics is our ability to increase reserves through the drillbit. We are currently conducting the second most active drilling program in the United States with a program focused on finding significant new gas reserves, primarily in the Mid-Continent. During 2004, we expect to use 45-50 drilling rigs to drill approximately 500 company-operated prospects and expect to participate with 40-50 additional rigs in the drilling of an additional 500 wells drilled on outside-operated prospects. In the Mid-Continent, our drilling program is the most active in the region and is supported by our ownership of the regions largest undeveloped leasehold and 3-D seismic inventories. In addition, we are continuing to increase our drilling activity in our secondary operating areas and we have recently increased drilling, land and seismic budgets to accommodate even greater activity in these areas. Across our operating areas, we seek a balanced approach to drilling with approximately one-third of our expenditures focused on targets located at depths shallower than 10,000 feet, one-third on medium depth drilling between 10-15,000 feet and one-third targeting deeper objectives below 15,000 feet. |
| Consistently Focusing on Building Regional Scale. We believe one of the keys to success in the natural gas exploration industry is focus: building significant operating scale in a limited number of core operating areas. Achieving such scale provides many benefits, the most important of which are higher per unit revenues, lower per unit operating costs, greater rates of drilling success, a lower likelihood of making unsuccessful acquisitions and higher returns on invested capital. The company first began pursuing this focused strategy in the Mid-Continent in 1997 and it now has become the largest natural gas producer, the most active driller and the most active acquirer of undeveloped leases and producing properties in the Mid-Continent. Chesapeake believes this region, which trails only the Gulf Coast and Rocky Mountain basins in current U.S. gas production, has many attractive characteristics. These characteristics include long-lived natural gas properties with predictable decline curves; multi-pay geological targets that decrease drilling risk and result in an impressive drilling success rate of 91% over the past eleven years; favorable basis differentials to benchmark commodity prices; generally lower service costs than in more competitive or more remote basins; and a favorable regulatory environment with virtually no federal land ownership. The company believes its secondary operating areas possess many of these same favorable characteristics. |
3
| Consistently Focusing on Low Costs. By minimizing lease operating costs and general and administrative expenses through focused activities and increased scale, we have been able to deliver attractive financial returns through all phases of the commodity price cycle. We believe our low cost structure is the result of managements effective cost-control programs, a high-quality asset base and the extensive and competitive services, gas processing and transportation infrastructures that exist in our key operating areas. |
| Consistently Improving the Companys Balance Sheet. We have made significant progress in improving our balance sheet since the beginning of 1999. After the completion of our recent (January 2004) common stock and debt exchange offerings, we will have increased our shareholders equity by $2.3 billion through a combination of earnings and common and preferred equity issuances since the beginning of 1999. During the past five years, our debt to total capitalization ratio has declined from 137% to 53% (pro forma for January and February 2004 securities transactions). We plan to continue improving our balance sheet in years ahead. |
Based on our view that natural gas has become the fuel of choice to meet the growing demand for a clean-burning, domestically-produced fuel, we believe our focused natural gas acquisition, exploitation and exploration strategy should provide substantial growth opportunities in the years ahead. Although U.S. gas production has been steadily declining during the past three years, we have increased our natural gas production in each of the 14 years since our companys inception in 1989. Our production goal is to increase our overall production by 15% to 20% per year, with an estimated one-third of this growth generated organically through the drillbit and the remainder through future acquisitions. We have reached or exceeded this overall production goal in 9 of our 11 years as a public company.
Company Strengths
We believe the following six characteristics highlight our most important company strengths, distinguish us from other independent natural gas producers and help explain our strong track record of delivering value to shareholders since our IPO in 1993:
| High-Quality Asset Base. Our producing properties are characterized by long-lived reserves, established production profiles and an emphasis on natural gas. Based upon current production and proved reserve levels (pro forma for the Concho and South Texas acquisitions closed in January 2004), our proved reserves-to-production ratio, or reserve life, is approximately 10.6 years. In each of our operating areas, our properties are concentrated in locations that enable us to establish substantial economies of scale in drilling and production operations and facilitate the application of more effective reservoir management practices. We intend to continue building our asset base in each of our primary and secondary operating areas through a balanced approach of acquisitions, exploitation and exploration. |
| Low-Cost Producer. Our high-quality asset base, our management style and our location in Oklahoma City have enabled us to achieve a low operating and administrative cost structure. During 2003, our operating costs per unit of production were $0.89 per mcfe, which consisted of general and administrative expenses of $0.09 per mcfe, production expenses of $0.51 per mcfe and production taxes of $0.29 per mcfe. We believe this is one of the lowest cost structures among publicly traded independent oil and natural gas producers. We seek to control operations of the properties in which we own an interest. Currently we operate approximately 79% of our proved reserves. This large percentage of operational control provides us with a high degree of operating flexibility and cost control. |
| Successful Acquisition Program. Our experienced asset acquisition team focuses on enhancing and expanding our existing assets in all three of our operating areas. These areas are characterized by long-lived natural gas reserves, low lifting costs, multiple geological targets, favorable basis differentials to benchmark commodity prices, well-developed oil and gas transportation infrastructures and considerable potential for further consolidation of assets. Since 1998, and including the recent Concho |
4
and South Texas acquisitions closed in January 2004, we have completed $3.6 billion in acquisitions at an average cost of $1.20 per mcfe of proved reserves. We are well-positioned to continue making attractive small and medium-sized acquisitions as a result of our extensive track record of identifying, completing and integrating multiple successful acquisitions, our large operating scale and our knowledge and expertise in the regions in which we operate. |
| Large Inventory of Drilling Projects. During the 14 years since our inception, Chesapeake has been one of the ten most active drillers of new wells in the United States and the most active driller in the Mid-Continent. In addition, we have developed an industry-leading expertise in drilling deep vertical and horizontal wells in search of large natural gas accumulations in challenging reservoir conditions. We pursue deep drilling targets because of our view that most undiscovered gas reserves in the U.S. will be found at depths below 15,000 feet. In addition, our large 3-D seismic inventory, much of which is proprietary to Chesapeake, provides the company with significant advantages over our competitors, which largely prefer to drill shallower development wells. As a result of our aggressive land and seismic acquisition strategies, we have been able to accumulate an onshore leasehold position of approximately three million net acres (pro forma for the Concho and South Texas acquisitions closed in January 2004). On this very large acreage position, our technical teams have identified over 2,500 exploratory and developmental drillsites, representing approximately five years of future drilling opportunities. |
| Hedging Program. We have used and intend to continue using hedging programs to reduce the risks inherent in producing oil and natural gas, commodities that are frequently characterized by significant price volatility. We believe this price volatility is likely to continue and may even increase in the years ahead, but that a producer can use this volatility to its benefit by taking advantage of prices when they reach levels that management believes may be unsustainable for the foreseeable future. Over the past three years, we have increased our oil and gas revenues by over $184 million through our successful hedging programs. We currently have gas hedges in place covering 67%, 26%, 11% and 8% of our anticipated gas production for 2004, 2005, 2006 and 2007 at average NYMEX prices of $5.32, $5.03, $4.88 and $4.76 per mcf, respectively. In addition, we have 78% of our projected oil production hedged for 2004 at an average NYMEX price of $28.68 per barrel of oil. |
| Entreprenuerial Management. Our management team formed the company in 1989 with an initial capitalization of $50,000. Through the following years, our current management team has guided the company through various operational and industry challenges and extremes of oil and gas prices to create one of the six largest independent producers of natural gas in the U.S. with an enterprise value of over $5.8 billion. Our co-founders, Aubrey K. McClendon and Tom L. Ward, have been partners in the oil and gas industry for 21 years and beneficially own, as of March 10, 2004, approximately 15.7 million and 17.2 million of the companys 241 million common shares, respectively. |
5
Drilling Activity
The following table sets forth the wells we drilled during the periods indicated. In the table, gross refers to the total wells in which we had a working interest and net refers to gross wells multiplied by our working interest.
2003 |
2002 |
2001 |
||||||||||||||||||||||||||||
Gross |
Percent |
Net |
Percent |
Gross |
Percent |
Net |
Percent |
Gross |
Percent |
Net |
Percent |
|||||||||||||||||||
United States |
||||||||||||||||||||||||||||||
Development: |
||||||||||||||||||||||||||||||
Productive |
958 | 96 | % | 401.0 | 97 | % | 617 | 95 | % | 237.7 | 95 | % | 423 | 92 | % | 196.9 | 94 | % | ||||||||||||
Non-productive |
37 | 4 | 11.2 | 3 | 34 | 5 | 11.5 | 5 | 36 | 8 | 12.2 | 6 | ||||||||||||||||||
Total |
995 | 100 | % | 412.2 | 100 | % | 651 | 100 | % | 249.2 | 100 | % | 459 | 100 | % | 209.1 | 100 | % | ||||||||||||
Exploratory: |
||||||||||||||||||||||||||||||
Productive |
76 | 86 | % | 35.9 | 83 | % | 47 | 82 | % | 24.6 | 82 | % | 36 | 68 | % | 18.4 | 67 | % | ||||||||||||
Non-productive |
12 | 14 | 7.5 | 17 | 10 | 18 | 5.4 | 18 | 17 | 32 | 9.0 | 33 | ||||||||||||||||||
Total |
88 | 100 | % | 43.4 | 100 | % | 57 | 100 | % | 30.0 | 100 | % | 53 | 100 | % | 27.4 | 100 | % | ||||||||||||
Canada(1) |
||||||||||||||||||||||||||||||
Development: |
||||||||||||||||||||||||||||||
Productive |
17 | 94 | % | 7.6 | 95 | % | ||||||||||||||||||||||||
Non-productive |
1 | 6 | 0.4 | 5 | ||||||||||||||||||||||||||
Total |
18 | 100 | % | 8.0 | 100 | % | ||||||||||||||||||||||||
(1) | The company sold all of its Canadian operations in October 2001. |
At December 31, 2003, we had 76 (29 net) wells in process. We own six rigs which are dedicated to drilling wells operated by Chesapeake and three additional rigs are under construction. Our drilling business is conducted through our wholly owned subsidiary, Nomac Drilling Corporation.
Well Data
At December 31, 2003, we had interests in 14,950 (5,873 net) producing wells, including properties in which we held an overriding royalty interest, of which 2,665 (942 net) were classified as primarily oil producing wells and 12,285 (4,931 net) were classified as primarily gas producing wells. Chesapeake operates approximately 5,990 of its 14,950 producing wells. During 2003, we drilled 442 (352 net) wells and participated in another 641 (104 net) wells operated by other companies. We operate approximately 79% of our proved reserves by volume.
6
Production, Sales, Prices and Expenses
The following table sets forth information regarding the production volumes, oil and gas sales, average sales prices received and expenses for the periods indicated:
2003 |
2002 |
2001 | |||||||||||||||
U.S. |
U.S. |
U.S. |
Canada |
Combined | |||||||||||||
Net Production: |
|||||||||||||||||
Oil (mbbl) |
4,665 | 3,466 | 2,880 | | 2,880 | ||||||||||||
Gas (mmcf) |
240,366 | 160,682 | 135,096 | 9,075 | 144,171 | ||||||||||||
Gas equivalent (mmcfe) |
268,356 | 181,478 | 152,376 | 9,075 | 161,451 | ||||||||||||
Oil and Gas Sales ($ in thousands): |
|||||||||||||||||
Oil sales |
$ | 132,630 | $ | 88,495 | $ | 69,602 | $ | | $ | 69,602 | |||||||
Oil derivatives realized gains (losses) |
(12,058 | ) | (1,092 | ) | 7,920 | | 7,920 | ||||||||||
Oil derivatives unrealized gains (losses) |
(9,440 | ) | (7,369 | ) | 5,116 | | 5,116 | ||||||||||
Total oil sales |
$ | 111,132 | $ | 80,034 | $ | 82,638 | $ | | $ | 82,638 | |||||||
Gas sales |
$ | 1,171,050 | $ | 470,913 | $ | 528,608 | $ | 31,928 | $ | 560,536 | |||||||
Gas derivatives realized gains (losses) |
(5,331 | ) | 97,138 | 97,471 | | 97,471 | |||||||||||
Gas derivatives unrealized gains (losses) |
19,971 | (79,898 | ) | 79,673 | | 79,673 | |||||||||||
Total gas sales |
$ | 1,185,690 | $ | 488,153 | $ | 705,752 | $ | 31,928 | $ | 737,680 | |||||||
Total oil and gas sales |
$ | 1,296,822 | $ | 568,187 | $ | 788,390 | $ | 31,928 | $ | 820,318 | |||||||
Average Sales Price |
|||||||||||||||||
Oil ($ per bbl) |
$ | 28.43 | $ | 25.53 | $ | 24.17 | $ | | $ | 24.17 | |||||||
Gas ($ per mcf) |
$ | 4.87 | $ | 2.93 | $ | 3.91 | $ | 3.52 | $ | 3.89 | |||||||
Gas equivalent ($ per mcfe) |
$ | 4.86 | $ | 3.08 | $ | 3.93 | $ | 3.52 | $ | 3.90 | |||||||
Average Sales Price |
|||||||||||||||||
Oil ($ per bbl) |
$ | 25.85 | $ | 25.22 | $ | 26.92 | $ | | $ | 26.92 | |||||||
Gas ($ per mcf) |
$ | 4.85 | $ | 3.54 | $ | 4.63 | $ | 3.52 | $ | 4.56 | |||||||
Gas equivalent ($ per mcfe) |
$ | 4.79 | $ | 3.61 | $ | 4.62 | $ | 3.52 | $ | 4.56 | |||||||
Expenses ($ per mcfe): |
|||||||||||||||||
Production expenses |
$ | 0.51 | $ | 0.54 | $ | 0.48 | $ | 0.26 | $ | 0.47 | |||||||
Production taxes |
$ | 0.29 | $ | 0.17 | $ | 0.22 | $ | | $ | 0.20 | |||||||
General and administrative |
$ | 0.09 | $ | 0.10 | $ | 0.09 | $ | 0.11 | $ | 0.09 | |||||||
Depreciation, depletion and amortization |
$ | 1.38 | $ | 1.22 | $ | 1.08 | $ | 0.90 | $ | 1.07 |
In October 2001, we sold our Canadian subsidiary for approximately $143.0 million.
7
Proved Reserves
The following table sets forth our estimated proved reserves and the present value of the proved reserves (based on our weighted average wellhead prices at December 31, 2003 of $30.22 per barrel of oil and $5.68 per mcf of gas). These prices were based on the cash spot prices for oil and natural gas at December 31, 2003.
Oil (mbbl) |
Gas (mmcf) |
Gas Equivalent (mmcfe) |
Percent of Proved Reserves |
Present Value ($ in thousands) |
|||||||||
Mid-Continent |
35,213 | 2,529,939 | 2,741,216 | 86.5 | % | $ | 6,301,690 | ||||||
South Texas and Texas Gulf Coast |
4,239 | 230,891 | 256,323 | 8.1 | 695,573 | ||||||||
Permian Basin |
7,247 | 83,274 | 126,756 | 4.0 | 260,369 | ||||||||
Williston Basin |
4,721 | 5,293 | 33,619 | 1.1 | 58,130 | ||||||||
Other areas |
2 | 10,643 | 10,661 | 0.3 | 17,380 | ||||||||
Total |
51,422 | 2,860,040 | 3,168,575 | 100.0 | % | $ | 7,333,142 | (a) | |||||
(a) | The standardized measure of discounted future net cash flows at December 31, 2003 was $5.3 billion. |
As of December 31, 2003, the present value of our proved developed reserves as a percentage of total proved reserves was 75%, and the volume of our proved developed reserves as a percentage of total proved reserves was 74%. Natural gas reserves accounted for 90% of the volume of total proved reserves at December 31, 2003.
Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of any estimate. A change in price of $0.10 per mcf for natural gas and $1.00 per barrel for oil would result in a change in our December 31, 2003 present value of proved reserves of approximately $145 million and $25 million, respectively.
Development, Exploration, Acquisition and Divestiture Activities
The following table sets forth historical cost information regarding our development, exploration, acquisition and divestiture activities during the periods indicated:
Years Ended December 31, |
||||||||||||
2003 |
2002 |
2001 |
||||||||||
($ in thousands) | ||||||||||||
Development and leasehold costs |
$ | 543,371 | $ | 266,291 | $ | 333,672 | ||||||
Exploration costs |
103,424 | 89,422 | 47,945 | |||||||||
Acquisition costs: |
||||||||||||
Proved properties |
1,110,077 | 316,583 | 669,201 | |||||||||
Unproved properties |
198,394 | 14,000 | 35,132 | |||||||||
Deferred income taxes |
(4,903 | ) | 62,398 | 36,309 | ||||||||
Sales of oil and gas properties |
(22,156 | ) | (839 | ) | (151,444 | ) | ||||||
Geological and geophysical costs |
38,181 | 22,798 | 7,131 | |||||||||
Asset retirement obligation(a) |
39,686 | | | |||||||||
Capitalized internal costs |
35,494 | 24,318 | 18,225 | |||||||||
Total |
$ | 2,041,568 | $ | 794,971 | $ | 996,171 | ||||||
(a) | The 2003 amount includes $24.1 million of asset retirement costs recorded as a result of implementation of SFAS 143 effective January 1, 2003 and $15.6 million of additional asset retirement costs incurred in 2003. |
8
Our development and leasehold costs included $229 million, $120 million and $121 million of expenditures in 2003, 2002 and 2001, respectively, related to properties carried as proved undeveloped locations in the prior years reserve reports. Included in our reserve report as of December 31, 2003 are estimated future development costs of $823 million related to the development of proved undeveloped reserves ($351 million in 2004, $276 million in 2005, $157 million in 2006 and $39 million in 2007 and beyond). Chesapeakes development drilling schedules are subject to revision and reprioritization throughout the year, resulting from unknowable factors such as the relative success in an individual developmental drilling prospect leading to an additional drilling opportunity, rig availability, title issues or delays, and the effect that acquisitions may have on prioritizing development drilling plans.
Acreage
The following table sets forth as of December 31, 2003 the gross and net acres of both developed and undeveloped oil and gas leases which we hold. Gross acres are the total number of acres in which we own a working interest. Net acres refer to gross acres multiplied by our fractional working interest. Acreage numbers do not include our options to acquire additional leasehold which have not been exercised.
Developed |
Undeveloped |
Total | ||||||||||
Gross |
Net |
Gross |
Net |
Gross |
Net | |||||||
Mid-Continent |
3,835,215 | 1,610,680 | 801,377 | 417,336 | 4,636,592 | 2,028,016 | ||||||
South Texas and Texas Gulf Coast |
274,375 | 164,690 | 188,270 | 134,264 | 462,645 | 298,954 | ||||||
Permian Basin |
69,324 | 51,683 | 94,926 | 61,727 | 164,250 | 113,410 | ||||||
Williston Basin and Other |
65,146 | 31,558 | 102,230 | 81,546 | 167,376 | 113,104 | ||||||
Total |
4,244,060 | 1,858,611 | 1,186,803 | 694,873 | 5,430,863 | 2,553,484 | ||||||
Marketing
Chesapeakes oil production is generally sold under market sensitive or spot price contracts. Our natural gas production is sold to purchasers generally under percentage-of-proceeds contracts, percentage-of-index contracts or market sensitive contracts. By the terms of the percentage-of-proceeds contracts, we receive a percentage of the resale price received by the purchaser for sales of residue gas and natural gas liquids recovered after transportation and processing our gas. These purchasers sell the residue gas and natural gas liquids based primarily on spot market prices. The revenue we receive from the sale of natural gas liquids is included in oil sales. Under percentage-of-index contracts, the price per mmbtu we receive for our gas is tied to indexes published in Inside FERC or Gas Daily. During 2003, sales to Reliant Energy Services and Duke Energy Field Services of $189.1 million and $163.3 million, respectively, accounted for 11% and 10%, respectively, of our total revenues. Management believes that the loss of either of these customers would not have a material adverse effect on our results of operations or our financial position. Other than the purchasers noted above, no other customer accounted for more than 10% of total revenues in 2003.
Chesapeake Energy Marketing, Inc., Mayfield Processing, L.L.C. and MidCon Compression, L.P., which are our marketing subsidiaries, provide marketing services, including commodity price structuring, contract administration and nomination services for Chesapeake and its partners. These subsidiaries are a reportable segment under SFAS No. 131, Disclosure about Segments of an Enterprise and Related Information. See note 8 of notes to consolidated financial statements in Item 8.
Hedging Activities
We utilize hedging strategies to hedge the price of a portion of our future oil and natural gas production and from time to time to manage interest rate exposure. See Item 7AQuantitative and Qualitative Disclosures About Market Risk.
9
Risk Factors
You should carefully consider the following risk factors in addition to the other information included in this report. Each of these risk factors could adversely affect our business, operating results and financial condition, as well as adversely affect the value of an investment in our common stock or other securities.
Oil and gas prices are volatile. A decline in prices could adversely affect our financial results, cash flows, access to capital and ability to grow.
Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and gas properties depend primarily upon the prices we receive for the oil and gas we sell. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. The amount we can borrow from banks is subject to periodic redeterminations based on prices specified by our bank group at the time of redetermination. In addition, we may have ceiling test write-downs in the future if prices fall significantly.
Historically, the markets for oil and gas have been volatile and they are likely to continue to be volatile. Wide fluctuations in oil and gas prices may result from relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and other factors that are beyond our control, including:
| worldwide and domestic supplies of oil and gas; |
| weather conditions; |
| the level of consumer demand; |
| the price and availability of alternative fuels; |
| the availability of pipeline capacity; |
| the price and level of foreign imports; |
| domestic and foreign governmental regulations and taxes; |
| the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls; |
| political instability or armed conflict in oil-producing regions; and |
| the overall economic environment. |
These factors and the volatility of the energy markets make it extremely difficult to predict future oil and gas price movements with any certainty. Declines in oil and gas prices would not only reduce revenue, but could reduce the amount of oil and gas that we can produce economically and, as a result, could have a material adverse effect on our financial condition, results of operations and reserves. Further, oil and gas prices do not necessarily move in tandem. Because approximately 90% of our proved reserves at December 31, 2003 are natural gas reserves, we are more affected by movements in natural gas prices.
Competition in the oil and natural gas industry is intense, and many of our competitors have greater financial and other resources than we do.
We operate in the highly competitive areas of oil and natural gas acquisition, development, exploitation, exploration and production. We face intense competition from both major and other independent oil and natural gas companies in each of the following areas:
| seeking to acquire desirable producing properties or new leases for future exploration; and |
| seeking to acquire the equipment and expertise necessary to develop and operate our properties. |
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Many of our competitors have financial and other resources substantially greater than ours, and some of them are fully integrated oil companies. These companies may be able to pay more for development prospects and productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to develop and exploit our oil and natural gas properties and to acquire additional properties in the future will depend upon our ability to successfully conduct operations, evaluate and select suitable properties and consummate transactions in this highly competitive environment.
The actual quantities and present value of our proved reserves may prove to be lower than we have estimated.
This report contains estimates of our proved reserves and the estimated future net revenues from our proved reserves. These estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and gas reserves is complex. The process involves significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise.
Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves most likely will vary from these estimates. Such variations may be significant and could materially affect the estimated quantities and present value of our proved reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development drilling, prevailing oil and gas prices and other factors, many of which are beyond our control. Our properties may also be susceptible to hydrocarbon drainage from production by operators on adjacent properties.
At December 31, 2003, approximately 26% of our estimated proved reserves by volume were undeveloped. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. These reserve estimates include the assumption that we will make significant capital expenditures to develop the reserves, including $351 million in 2004. You should be aware that the estimated costs may not be accurate, development may not occur as scheduled and results may not be as estimated.
You should not assume that the present values referred to in this document represent the current market value of our estimated oil and gas reserves. In accordance with SEC requirements, the estimates of our present values are based on prices and costs as of the date of the estimates. The December 31, 2003 present value is based on weighted average oil and gas prices of $30.22 per barrel of oil and $5.68 per mcf of natural gas. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of an estimate.
Any changes in consumption by oil and gas purchasers or in governmental regulations or taxation will also affect actual future net cash flows.
The timing of both the production and the costs for the development and production of oil and gas properties will affect both the timing of actual future net cash flows from our proved reserves and their present value. In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most accurate discount factor. Future interest rates and the risks associated with our business or the oil and gas industry in general will affect the accuracy of the 10% discount factor.
Acquisitions may prove to be worth less than we paid because of uncertainties in evaluating recoverable reserves and potential liabilities.
Our recent growth is due in part to acquisitions of exploration and production companies, producing properties and undeveloped leasehold. We expect acquisitions will also contribute to our future growth.
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Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, exploration potential, future oil and gas prices, operating costs and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we perform a review of the acquired properties which we believe is generally consistent with industry practices. However, such a review will not reveal all existing or potential problems. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well. Even when we inspect a well, we do not always discover structural, subsurface and environmental problems that may exist or arise.
We are generally not entitled to contractual indemnification for preclosing liabilities, including environmental liabilities. Normally, we acquire interests in properties on an as is basis with limited remedies for breaches of representations and warranties. In addition, competition for producing oil and gas properties is intense and many of our competitors have financial and other resources that are substantially greater than those available to us. Therefore, we may not be able to acquire oil and gas properties that contain economically recoverable reserves or be able to complete such acquisitions on acceptable terms.
Additionally, significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties, which may have substantially different operating and geological characteristics or be in different geographic locations than our existing properties. It is our current intention to continue focusing on acquiring properties with development and exploration potential located in the Mid-Continent, South Texas and Permian regions. To the extent that we acquire properties substantially different from the properties in our primary operating regions or acquire properties that require different technical expertise, we may not be able to realize the economic benefits of these acquisitions as efficiently as in our prior acquisitions.
Future price declines may result in a writedown of our asset carrying values.
We utilize the full cost method of accounting for costs related to our oil and gas properties. Under this method, all such costs (for both productive and nonproductive properties) are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the unit-of-production method. However, these capitalized costs are subject to a ceiling test which limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved oil and gas reserves discounted at 10% plus the lower of cost or market value of unproved properties. The full cost ceiling is evaluated at the end of each quarter using the prices for oil and gas at that date, adjusted for the impact of derivatives accounted for as cash flow hedges. A significant decline in oil and gas prices from current levels, or other factors, without other mitigating circumstances, could cause a future writedown of capitalized costs and a non-cash charge against future earnings. Chesapeakes aggregate present value of future net revenues plus the value of the unproved properties would equal the recorded net book value of our oil and gas properties at December 31, 2003 assuming an index price of approximately $3.25 per mcf for gas and $32.25 per barrel for oil. If index prices were to fall below these levels, Chesapeake could experience a writedown of the book value of its oil and gas assets.
Our level of indebtedness and preferred stock may adversely affect operations and limit our growth, and we may have difficulty making debt service and preferred stock dividend payments on our indebtedness and preferred stock as such payments become due.
As of December 31, 2003, we had long-term indebtedness of $2.1 billion, none of which was bank indebtedness. Our long-term indebtedness represented 54% of our total book capitalization at December 31, 2003. We expect to be highly leveraged in the foreseeable future.
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Our level of indebtedness and preferred stock affects our operations in several ways, including the following:
| a significant portion of our cash flows must be used to service our indebtedness, and our business may not generate sufficient cash flow from operations to enable us to continue to meet our obligations under our indebtedness and our stated dividends on our preferred stock; |
| a high level of debt and preferred stock increases our vulnerability to general adverse economic and industry conditions; |
| the covenants contained in the agreements governing our outstanding indebtedness may limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments; |
| our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry, and the rights and preferences applicable to our preferred stock may limit our ability to pay dividends on our preferred stock; and |
| a high level of debt and preferred stock may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, or other general corporate purposes. |
We may incur additional debt, including significant secured indebtedness or issue additional series of preferred stock, in order to make future acquisitions or to develop our properties. A higher level of indebtedness and additional preferred stock increases the risk that we may default on our existing debt obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, oil and gas prices and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flow to pay the interest on our debt, and future working capital, borrowings or equity financing may not be available to pay or refinance such debt. Factors that will affect our ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions, the value of our assets and our performance at the time we need capital.
In addition, our bank borrowing base is subject to periodic redeterminations. We could be forced to repay a portion of our bank borrowings due to redeterminations of our borrowing base. If we are forced to do so, we may not have sufficient funds to make such repayments. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.
Our hedging activities may reduce the realized prices received for our oil and gas sales and require us to provide collateral for hedging liabilities.
In order to manage our exposure to price volatility in marketing our oil and gas, we enter into oil and gas price risk management arrangements for a portion of our expected production. Commodity price hedging may limit the prices we actually realize and therefore reduce oil and gas revenues in the future. The estimated fair value of our oil and gas derivative instruments outstanding as of March 10, 2004 is a liability of approximately $99 million. In addition, our commodity price risk management transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:
| our production is less than expected; |
| there is a widening of price differentials between delivery points for our production and the delivery point assumed in the hedge arrangement; or |
| the counterparties to our contracts fail to perform under the contracts. |
Some of our commodity price and interest rate risk management arrangements require us to deliver cash collateral or other assurances of performance to the counterparties in the event that our payment obligations exceed certain levels. As of December 31, 2003, we were required to post a total of $33.5 million of collateral
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with two of our counterparties through letters of credit issued under our bank credit facility. As of March 10, 2004, we were required to post a total of $70 million of collateral. Future collateral requirements are uncertain and will depend on arrangements with our counterparties, highly volatile natural gas and oil prices and fluctuations in interest rates.
We may not have funds sufficient to make the significant capital expenditures required to replace our reserves.
Our exploration, development and acquisition activities require substantial capital expenditures. Historically, we have funded our capital expenditures through a combination of cash flows from operations, our bank credit facility and debt and equity issuances. Future cash flows are subject to a number of variables, such as the level of production from existing wells, prices of oil and gas, and our success in developing and producing new reserves. If revenue were to decrease as a result of lower oil and gas prices or decreased production, and our access to capital were limited, we would have a reduced ability to replace our reserves. If our cash flows from operations are not sufficient to fund our capital expenditure budget, we may not be able to access additional bank debt, debt or equity or other methods of financing to meet these requirements.
Lower oil and gas prices could negatively impact our ability to borrow.
Our bank credit facility limits our borrowings to a borrowing base of $350 million as of March 10, 2004. The borrowing base is determined periodically at the discretion of a majority of the banks and is based in part on oil and gas prices. Additionally, some of our indentures contain covenants limiting our ability to incur indebtedness in addition to that incurred under our bank credit facility. These indentures limit our ability to incur additional indebtedness unless we meet one of two alternative tests. The first alternative is based on our adjusted consolidated net tangible assets, which is determined using discounted future net revenues from proved oil and gas reserves as of the end of each year. The second alternative is based on the ratio of our adjusted consolidated EBITDA (as defined in all of our indentures) to our adjusted consolidated interest expense over a trailing twelve-month period. As of December 31, 2003, we are permitted to incur significant additional indebtedness under both of these debt incurrence tests. Lower oil and gas prices in the future could reduce our adjusted consolidated EBITDA, as well as our adjusted consolidated net tangible assets, and thus could reduce our ability to incur additional indebtedness.
The loss of key personnel could adversely affect our ability to operate.
We depend, and will continue to depend in the foreseeable future, on the services of our officers and key employees with extensive experience and expertise in evaluating and analyzing producing oil and gas properties and drilling prospects, maximizing production from oil and gas properties, marketing oil and gas production, and developing and executing financing and hedging strategies. Our ability to retain our officers and key employees is important to our continued success and growth. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on our business. We do not maintain key person life insurance on any of our personnel.
Exploration and development drilling may not result in commercially productive reserves.
We do not always encounter commercially productive reservoirs through our drilling operations. The new wells we drill or participate in may not be productive and we may not recover all or any portion of our drilling costs. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or gas is present or may be produced economically. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. Our efforts will be unprofitable if we drill dry wells or wells that are productive but do not produce enough reserves to return a profit after drilling, operating and other costs. Further, our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:
| unexpected drilling conditions; |
| title problems; |
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| pressure or irregularities in formations; |
| equipment failures or accidents; |
| adverse weather conditions; |
| compliance with environmental and other governmental requirements; and |
| the high cost, or shortages or delays in the availability of drilling rigs and equipment. |
If we are not able to replace reserves, we may not be able to sustain production.
Our future success depends largely upon our ability to find, develop or acquire additional oil and gas reserves that are economically recoverable. Unless we replace the reserves we produce through successful development, exploration or acquisition activities, our proved reserves will decline over time. In addition, approximately 26% of our total estimated proved reserves by volume at December 31, 2003 were undeveloped. By their nature, estimates of undeveloped reserves are less certain. Recovery of such reserves will require significant capital expenditures and successful drilling operations. We may not be able to successfully find and produce reserves economically in the future. In addition, we may not be able to acquire proved reserves at acceptable costs.
Oil and gas drilling and producing operations are hazardous and expose us to environmental liabilities.
Oil and gas operations are subject to many risks, including well blowouts, cratering and explosions, pipe failure, fires, formations with abnormal pressures, uncontrollable flows of oil, natural gas, brine or well fluids, and other environmental hazards and risks. Our drilling operations involve risks from high pressures and from mechanical difficulties such as stuck pipes, collapsed casings and separated cables. If any of these risks occur, we could sustain substantial losses as a result of:
| injury or loss of life; |
| severe damage to or destruction of property, natural resources and equipment; |
| pollution or other environmental damage; |
| clean-up responsibilities; |
| regulatory investigations and penalties; and |
| suspension of operations. |
Our liability for environmental hazards includes those created either by the previous owners of properties that we purchase or lease or by acquired companies prior to the date we acquire them. We maintain insurance against some, but not all, of the risks described above. Our insurance may not be adequate to cover casualty losses or liabilities. Also, in the future we may not be able to continue to obtain insurance at premium levels that justify its purchase.
Regulation
General. The oil and gas industry is subject to regulation at the federal, state and local level, and some of the laws, rules and regulations that govern our operations carry substantial penalties for noncompliance. This regulatory burden increases our cost of doing business and, consequently, affects our profitability.
Exploration and Production. Our operations are subject to various types of regulation at the U.S. federal, state and local levels. Such regulation includes requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds) covering drilling and well operations. Other activities subject to regulation are:
| the location of wells, |
| the method of drilling and completing wells, |
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| the surface use and restoration of properties upon which wells are drilled, |
| the plugging and abandoning of wells, |
| the disposal of fluids used or other wastes obtained in connection with operations, |
| the marketing, transportation and reporting of production, and |
| the valuation and payment of royalties. |
Our operations are also subject to various conservation regulations. These include the regulation of the size of drilling and spacing units (regarding the density of wells which may be drilled in a particular area) and the unitization or pooling of oil and gas properties. In this regard, some states, such as Oklahoma, allow the forced pooling or integration of tracts to facilitate exploration, while other states, such as Texas, rely on voluntary pooling of lands and leases. In areas where pooling is voluntary, it may be more difficult to form units and, therefore, more difficult to fully develop a project if the operator owns less than 100% of the leasehold. In addition, state conservation laws establish maximum rates of production from oil and gas wells, generally prohibit the venting or flaring of gas and impose certain requirements regarding the ratability of production. The effect of these regulations is to limit the amount of oil and gas we can produce and to limit the number of wells or the locations at which we can drill.
We do not anticipate that compliance with existing laws and regulations governing exploration and production will have a significantly adverse effect upon our capital expenditures, earnings or competitive position.
Environmental Regulation. Various federal, state and local laws and regulations concerning the discharge of contaminants into the environment, the generation, storage, transportation and disposal of contaminants, and the protection of public health, natural resources, wildlife and the environment affect our exploration, development and production operations. We must take into account the cost of complying with environmental regulations in planning, designing, drilling, operating and abandoning wells. In most instances, the regulatory requirements relate to the handling and disposal of drilling and production waste products, water and air pollution control procedures, and the remediation of petroleum-product contamination. In addition, our operations may require us to obtain permits for, among other things,
| discharges into surface waters, and |
| the construction and operation of underground injection wells or surface pits to dispose of produced saltwater and other nonhazardous oilfield wastes. |
Under state and federal laws, we could be required to remove or remediate previously disposed wastes, including wastes disposed of or released by us or prior owners or operators in accordance with current laws or otherwise, to suspend or cease operations in contaminated areas, or to perform remedial plugging operations to prevent future contamination. The Environmental Protection Agency and various state agencies have limited the disposal options for hazardous and nonhazardous wastes. The owner and operator of a site, and persons that treated, disposed of or arranged for the disposal of hazardous substances found at a site, may be liable, without regard to fault or the legality of the original conduct, for the release of a hazardous substance into the environment. The Environmental Protection Agency, state environmental agencies and, in some cases, third parties are authorized to take actions in response to threats to human health or the environment and to seek to recover from responsible classes of persons the costs of such action. Furthermore, certain wastes generated by our oil and natural gas operations that are currently exempt from treatment as hazardous wastes may in the future be designated as hazardous wastes and, therefore, be subject to considerably more rigorous and costly operating and disposal requirements.
Federal and state occupational safety and health laws require us to organize information about hazardous materials used, released or produced in our operations. Certain portions of this information must be provided to employees, state and local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in federal workplace standards.
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We have made and will continue to make expenditures to comply with environmental regulations and requirements. These are necessary business costs in the oil and gas industry. Although we are not fully insured against all environmental risks, we maintain insurance coverage which we believe is customary in the industry. Moreover, it is possible that other developments, such as stricter and more comprehensive environmental laws and regulations, as well as claims for damages to property or persons resulting from company operations, could result in substantial costs and liabilities, including civil and criminal penalties, to Chesapeake. We believe we are in substantial compliance with existing environmental regulations, and that, absent the occurrence of an extraordinary event the effect of which cannot be predicted, any noncompliance will not have a material adverse effect on our operations or earnings.
Income Taxes
At December 31, 2003, Chesapeake had federal income tax net operating loss (NOL) carryforwards of approximately $404 million. We also had approximately $72 million of alternative minimum tax (AMT) NOL carryforwards available as a deduction against future AMT income and approximately $9 million of percentage depletion carryforwards. The NOL carryforwards expire from 2012 through 2022. During 2003, we estimate that we will be able to utilize approximately $253.3 million of NOLs to reduce our 2003 federal taxable income. The value of the remaining carryforwards depends on the ability of Chesapeake to generate taxable income. In addition, for AMT purposes, only 90% of AMT income in any given year may be offset by AMT NOLs.
The ability of Chesapeake to utilize NOL carryforwards to reduce future federal taxable income and federal income tax is subject to various limitations under the Internal Revenue Code of 1986, as amended. The utilization of such carryforwards may be limited upon the occurrence of certain ownership changes, including the issuance or exercise of rights to acquire stock, the purchase or sale of stock by 5% stockholders, as defined in the Treasury regulations, and the offering of stock by us during any three-year period resulting in an aggregate change of more than 50% in the beneficial ownership of Chesapeake.
In the event of an ownership change (as defined for income tax purposes), Section 382 of the Code imposes an annual limitation on the amount of a corporations taxable income that can be offset by these carryforwards. The limitation is generally equal to the product of (i) the fair market value of the equity of the company multiplied by (ii) a percentage approximately equivalent to the yield on long-term tax exempt bonds during the month in which an ownership change occurs. In addition, the limitation is increased if there are recognized built-in gains during any post-change year, but only to the extent of any net unrealized built-in gains (as defined in the Code) inherent in the assets sold. Chesapeake had an ownership change in March 1998 which triggered a limitation. Certain NOLs acquired through various acquisitions are also subject to limitations. The following table summarizes our net operating losses as of December 31, 2003 and any related limitations:
Net Operating Losses | |||||||||
Total |
Limited |
Annual Limitation | |||||||
($ in thousands) | |||||||||
Net operating loss |
$ | 403,840 | $ | 312,140 | $ | 46,658 | |||
AMT net operating loss |
$ | 71,519 | $ | 71,519 | $ | 21,081 |
Although no assurances can be made, we do not believe that an additional ownership change has occurred as of December 31, 2003. Equity transactions after the date hereof by Chesapeake or by 5% stockholders (including relatively small transactions and transactions beyond our control) could cause an ownership change and therefore a limitation on the annual utilization of NOLs.
In the event of another ownership change, the amount of Chesapeakes NOLs available for use each year will depend upon future events that cannot currently be predicted and upon interpretation of complex rules under Treasury regulations. If less than the full amount of the annual limitation is utilized in any given year, the unused portion may be carried forward and may be used in addition to successive years annual limitation.
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We expect to utilize our NOL carryforwards and other tax deductions and credits to offset taxable income in the future. However, there is no assurance that the Internal Revenue Service will not challenge these carryforwards or their utilization.
In 2002, the Internal Revenue Service completed an audit of Chesapeake for the years ended December 31, 1999 and 2000. There were no significant adjustments resulting from this audit.
Title to Properties
Our title to properties is subject to royalty, overriding royalty, carried, net profits, working and other similar interests and contractual arrangements customary in the oil and gas industry, to liens for current taxes not yet due and to other encumbrances. As is customary in the industry in the case of undeveloped properties, only cursory investigation of record title is made at the time of acquisition. Drilling title opinions are usually prepared before commencement of drilling operations. We believe we have satisfactory title to substantially all of our active properties in accordance with standards generally accepted in the oil and gas industry. Nevertheless, we are involved in title disputes from time to time which result in litigation.
Operating Hazards and Insurance
The oil and gas business involves a variety of operating risks, including the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental hazards such as oil spills, gas leaks, ruptures or discharges of toxic gases. If any of these should occur, Chesapeake could suffer substantial losses due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, and suspension of operations. Our horizontal and deep drilling activities involve greater risk of mechanical problems than vertical and shallow drilling operations.
Chesapeake maintains a $50 million oil and gas lease operator policy that insures against certain sudden and accidental risks associated with drilling, completing and operating our wells. There can be no assurance that this insurance will be adequate to cover any losses or exposure to liability. We also carry a $100 million comprehensive general liability umbrella policy. We provide workers compensation insurance coverage to employees in all states in which we operate and we maintain a $1 million employment practice liability policy. While we believe these policies are customary in the industry, they do not provide complete coverage against all operating risks.
Employees
Chesapeake had 1,192 employees as of December 31, 2003, which includes 128 employed by our drilling subsidiary, Nomac Drilling Corporation. No employees are represented by organized labor unions. We believe our employee relations are good.
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Glossary of Oil and Gas Terms
The terms defined in this section are used throughout this Form 10-K.
Bcf. Billion cubic feet.
Bcfe. Billion cubic feet of gas equivalent.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.
Btu. British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
Commercial Well; Commercially Productive Well. An oil and gas well which produces oil and gas in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
Developed Acreage. The number of acres which are allocated or assignable to producing wells or wells capable of production.
Development Well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
Dry Hole; Dry Well. A well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.
Exploratory Well. A well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir or to extend a known reservoir.
Farmout. An assignment of an interest in a drilling location and related acreage conditional upon the drilling of a well on that location.
Formation. A succession of sedimentary beds that were deposited under the same general geologic conditions.
Full Cost Pool. The full cost pool consists of all costs associated with property acquisition, exploration, and development activities for a company using the full cost method of accounting. Additionally, any internal costs that can be directly identified with acquisition, exploration and development activities are included. Any costs related to production, general corporate overhead or similar activities are not included.
Gross Acres or Gross Wells. The total acres or wells, as the case may be, in which a working interest is owned.
Horizontal Wells. Wells which are drilled at angles greater than 70 degrees from vertical.
Mbbl. One thousand barrels of crude oil or other liquid hydrocarbons.
Mbtu. One thousand btus.
Mcf. One thousand cubic feet.
Mcfe. One thousand cubic feet of gas equivalent.
Mmbbl. One million barrels of crude oil or other liquid hydrocarbons.
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Mmbtu. One million btus.
Mmcf. One million cubic feet.
Mmcfe. One million cubic feet of gas equivalent.
Net Acres or Net Wells. The sum of the fractional working interest owned in gross acres or gross wells.
NYMEX. New York Mercantile Exchange.
Present Value or PV-10. When used with respect to oil and gas reserves, present value or PV-10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs in effect at the determination date, without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expense or to depreciation, depletion and amortization, discounted using an annual discount rate of 10%.
Productive Well. A well that is producing oil or gas or that is capable of production.
Proved Developed Reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as proved developed reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production responses that increased recovery will be achieved.
Proved Reserves. The estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (a) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the proved classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.
Proved Undeveloped Location. A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.
Proved Undeveloped Reserves. Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Proved undeveloped reserves may not include estimates attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.
Royalty Interest. An interest in an oil and gas property entitling the owner to a share of oil or gas production free of costs of production.
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Standardized Measure of Discounted Future Net Cash Flows. The discounted future net cash flows relating to proved reserves based on year-end prices, costs and statutory tax rates (adjusted for permanent differences) and a 10-percent annual discount rate.
Tcf. One trillion cubic feet.
Tcfe. One trillion cubic feet of gas equivalent.
Undeveloped Acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether such acreage contains proved reserves.
Working Interest. The operating interest which gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.
Written Put Option. An option, exercisable by the buyer, to require the seller (writer) to sell a specified amount of a commodity at an agreed upon price and time. The buyer pays the seller (writer) a premium for entering into the transaction.
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ITEM 2. Properties
Chesapeake focuses its natural gas exploration, development and acquisition efforts in one primary operating area and in three secondary operating areas: (i) the Mid-Continent (consisting of Oklahoma, western Arkansas, southwestern Kansas and the Texas Panhandle), representing 87% of our proved reserves, (ii) the South Texas and Texas Gulf Coast region, representing 8% of our proved reserves, (iii) the Permian Basin region of southeastern New Mexico and West Texas, representing 4% of our proved reserves, and (iv) the Williston Basin of eastern Montana and western North Dakota, representing 1% of our proved reserves. In October 2001, we sold our Canadian subsidiary which included all of our Canadian properties and leasehold.
During the year ended December 31, 2003, we participated in 1,083 gross (456 net) wells, 442 (352 net) of which we operated. A summary of our development, exploration, acquisition and divestiture activities by operating area is as follows:
Gross Wells Drilled |
Net Wells Drilled |
Capital Expenditures Oil and Gas Properties |
Sales of |
Total | |||||||||||||||||||
Exploration and Development |
Leasehold |
Sub-Total |
Acquisition |
||||||||||||||||||||
($ in thousands) | |||||||||||||||||||||||
Mid-Continent |
984 | 403.0 | $ | 579,853 | $ | 80,261 | $ | 660,114 | $ | 1,061,289 | $ | (22,156 | ) | $ | 1,699,247 | ||||||||
South Texas and Texas Gulf Coast |
55 | 24.7 | 61,590 | 17,609 | 79,199 | 195,065 | | 274,264 | |||||||||||||||
Permian Basin |
44 | 27.9 | 33,446 | 10,563 | 44,009 | 23,452 | | 67,461 | |||||||||||||||
Williston Basin and other |
| | 283 | 145 | 428 | 168 | | 596 | |||||||||||||||
Total |
1,083 | 455.6 | $ | 675,172 | $ | 108,578 | $ | 783,750 | $ | 1,279,974 | $ | (22,156 | ) | $ | 2,041,568 | ||||||||
Chesapeakes proved reserves increased 44% during 2003 to an estimated 3,169 bcfe at December 31, 2003, compared to 2,205 bcfe of estimated proved reserves at December 31, 2002. See note 11 of notes to our consolidated financial statements in Item 8 of this report.
Chesapeakes strategy for 2004 is to continue developing our natural gas assets through exploratory and developmental drilling and by selectively acquiring strategic properties in the Mid-Continent and in our secondary areas. We have budgeted approximately $750 million to $800 million for drilling, acreage acquisition, seismic and related capitalized internal costs, all of which is expected to be funded with operating cash flow based on our current assumptions. Our budget is frequently adjusted based on changes in oil and gas prices, drilling results, drilling costs and other factors. We expect to fund future acquisitions through a combination of operating cash flow, our secured credit facility and new debt and equity issuances.
Primary Operating Area
Mid-Continent. Chesapeakes Mid-Continent proved reserves of 2,741 bcfe represented 87% of our total proved reserves as of December 31, 2003, and this area produced 233.6 bcfe, or 87%, of our 2003 production. During 2003, we invested approximately $579.9 million to drill 984 (403.0 net) wells in the Mid-Continent. We anticipate spending approximately 80% to 85% of our total budget for exploration and development activities in the Mid-Continent region during 2004. We anticipate the Mid-Continent will contribute approximately 256 bcfe, or 78%, of expected total production during 2004. Substantially all of our budgeted production is expected to come from proved reserves owned as of December 31, 2003.
Secondary Operating Areas
South Texas and Texas Gulf Coast. Chesapeakes South Texas and Texas Gulf Coast proved reserves represented 256 bcfe, or 8%, of our total proved reserves as of December 31, 2003. During 2003, the South Texas and Texas Gulf Coast assets produced 23.3 bcfe, or 9%, of our total production. During 2003 , we invested
22
approximately $61.6 million to drill 55 (24.7 net) wells in the South Texas and Texas Gulf Coast region. We anticipate this area will contribute approximately 38 bcfe, or 12%, of expected total production during 2004. Substantially all of our budgeted production is expected to come from proved reserves estimated as of December 31, 2003 and acquired in January 2004. We anticipate spending approximately 10% of our total budget for exploration and development activities in the South Texas and Texas Gulf Coast region during 2004.
Permian Basin. Chesapeakes Permian Basin proved reserves represented 127 bcfe, or 4%, of our total proved reserves as of December 31, 2003. During 2003, the Permian assets produced 8.5 bcfe, or 3%, of our total production. We anticipate the Permian Basin will contribute approximately 29 bcfe, or 9%, of expected total production during 2004. Substantially all of our budgeted production is expected to come from proved reserves estimated as of December 31, 2003 and acquired in January 2004. During 2003, we invested approximately $33.4 million to drill 44 (27.9 net) wells in the Permian Basin. For 2004, we anticipate spending approximately 5% of our total budget for exploration and development activities in the Permian Basin.
Williston Basin. Chesapeakes Williston Basin proved reserves represented 34 bcfe, or 1%, of our total proved reserves as of December 31, 2003. During 2003, the Williston assets produced 3 bcfe, or 1%, of our total production. We anticipate the Williston Basin will contribute approximately 2.6 bcfe, or 1%, of expected total production during 2004. Substantially all of our budgeted production is expected to come from proved reserves estimated as of December 31, 2003. During 2003, we did not drill any wells and we have not budgeted any 2004 exploration and development activities in the Williston Basin.
Oil and Gas Reserves
The tables below set forth information as of December 31, 2003 with respect to our estimated proved reserves, the associated estimated future net revenue and the present value at such date. Ryder Scott Company L.P. evaluated 31%, Netherland, Sewell & Associates, Inc. evaluated 26%, and Lee Keeling and Associates evaluated 17% of our combined discounted future net revenues from our estimated proved reserves at December 31, 2003. The remaining 26% was evaluated internally by our engineers. All estimates were prepared based upon a review of production histories and other geologic, economic, ownership and engineering data we developed. The present value of estimated future net revenue shown is not intended to represent the current market value of the estimated oil and gas reserves we own.
Estimated Proved Reserves as of December 31, 2003 |
Oil (mbbl) |
Gas (mmcf) |
Total (mmcfe) |
|||||||
Proved developed |
38,442 | 2,121,734 | 2,352,389 | |||||||
Proved undeveloped |
12,980 | 738,306 | 816,186 | |||||||
Total proved |
51,422 | 2,860,040 | 3,168,575 | |||||||
Estimated Future Net Revenue as of December 31, 2003(a) |
Proved Developed |
Proved Undeveloped |
Total Proved |
|||||||
($ in thousands) | ||||||||||
Estimated future net revenue |
$ | 9,921,483 | $ | 3,152,535 | $ | 13,074,018 | ||||
Present value of future net revenue |
$ | 5,508,497 | $ | 1,824,645 | $ | 7,333,142 | (b) |
(a) | Estimated future net revenue represents the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs in effect at December 31, 2003. The amounts shown do not give effect to non-property related expenses, such as corporate general and administrative expenses, debt service and future income tax expense or to depreciation, depletion and amortization. The prices used in the external and internal reports yield weighted average wellhead prices of $30.22 per barrel of oil and $5.68 per mcf of gas. These prices should not be interpreted as a prediction of future prices. |
(b) | The standardized measure of discounted future net cash flows at December 31, 2003 was $5.3 billion. |
23
The future net revenue attributable to our estimated proved undeveloped reserves of $3.2 billion at December 31, 2003, and the $1.8 billion present value thereof, have been calculated assuming that we will expend approximately $823 million to develop these reserves. The amount and timing of these expenditures will depend on a number of factors, including actual drilling results, product prices and the availability of capital.
No estimates of proved reserves comparable to those included herein have been included in reports to any federal agency other than the Securities and Exchange Commission.
Chesapeakes ownership interest used in calculating proved reserves and the associated estimated future net revenue were determined after giving effect to the assumed maximum participation by other parties to our farmout and participation agreements. The prices used in calculating the estimated future net revenue attributable to proved reserves do not reflect market prices for oil and gas production sold subsequent to December 31, 2003. There can be no assurance that all of the estimated proved reserves will be produced and sold at the assumed prices.
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond Chesapeakes control. The reserve data represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates made by different engineers often vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimates, and such revisions may be material. Accordingly, reserve estimates are often different from the actual quantities of oil and gas that are ultimately recovered. Furthermore, the estimated future net revenue from proved reserves and the associated present value are based upon certain assumptions, including prices, future production levels and cost, that may not prove correct. The foregoing uncertainties are particularly true as to proved undeveloped reserves, which are inherently less certain than proved developed reserves and which comprise a significant portion of our proved reserves. In addition, the estimated future net revenue from proved reserves and the associated present value does not include any estimates of corporate overhead, debt service costs, future income tax expense, or depreciation, depletion and amortization expense.
See Item 1 Business and note 11 of notes to consolidated financial statements included in Item 8 of this report for a description of drilling, production and other information regarding our oil and gas properties.
Facilities
Chesapeake owns an office building complex in Oklahoma City and field offices in Lindsay, Waynoka, and Weatherford, Oklahoma; Garden City, Kansas; Borger, Dumas and College Station, Texas; Van Buren, Arkansas; Cheneyville, Louisiana; and Eunice and Hobbs, New Mexico. In addition, Chesapeake leases office space in Oklahoma City and Tulsa, Oklahoma and Midland, Texas and field office space in Forgan, Kingfisher, Sayre and Wilburton, Oklahoma; Zapata, Texas; and Dickinson, North Dakota. Chesapeake owns approximately 50 different gas gathering and processing facilities located in Oklahoma, Kansas, Texas and Louisiana.
ITEM 3. Legal Proceedings
We are currently involved in various disputes incidental to our business operations. We believe that the final resolution of such currently pending or threatened litigation is not likely to have a material adverse effect on our financial position or results of operations.
ITEM 4. Submission of Matters to a Vote of Security Holders
Not applicable.
24
PART II
ITEM 5. Market for Registrants Common Equity and Related Stockholder Matters
Price Range of Common Stock
Our common stock trades on the New York Stock Exchange under the symbol CHK. The following table sets forth, for the periods indicated, the high and low sales prices per share of our common stock as reported by the New York Stock Exchange:
Common Stock | ||||||
High |
Low | |||||
Year ended December 31, 2003: |
||||||
First Quarter |
$ | 8.64 | $ | 7.27 | ||
Second Quarter |
11.45 | 7.45 | ||||
Third Quarter |
10.97 | 9.17 | ||||
Fourth Quarter |
14.00 | 10.66 | ||||
Year ended December 31, 2002: |
||||||
First Quarter |
$ | 7.78 | $ | 5.05 | ||
Second Quarter |
8.55 | 6.81 | ||||
Third Quarter |
7.25 | 4.50 | ||||
Fourth Quarter |
8.06 | 5.89 |
At March 10, 2004 there were 1,198 holders of record of our common stock and approximately 97,000 beneficial owners.
Dividends
The following table sets forth the amount of dividends per share declared on Chesapeake common stock during the two years ended December 31, 2003:
2003 |
2002 | |||||
First Quarter |
$ | 0.030 | $ | | ||
Second Quarter |
0.035 | | ||||
Third Quarter |
0.035 | 0.030 | ||||
Fourth Quarter |
0.035 | 0.030 |
While we expect to continue to pay dividends on our common stock, the payment of future cash dividends will depend upon, among other things, our financial condition, funds from operations, the level of our capital and development expenditures, our future business prospects, any contractual restrictions and any other factors considered relevant by the board of directors.
Our revolving credit agreement limits the amount of cash dividends we may pay to $50 million per year, excluding dividends on our 6.75%, 6.00% and 5.00% cumulative convertible preferred stock. Six of the indentures governing our outstanding senior notes contain restrictions on our ability to declare and pay cash dividends. Under these indentures, we may not pay any cash dividends on our common or preferred stock if an event of default has occurred, if we have not met one of the two debt incurrence tests described in the indentures, or if immediately after giving effect to the dividend payment, we have paid total dividends and made other restricted payments in excess of the permitted amounts. As of December 31, 2003, our coverage ratio for purposes of the debt incurrence test was 5.1 to 1, compared to 2.25 to 1 required in our indentures. Our adjusted consolidated net tangible assets exceeded 200% of our total indebtedness, as required in our indentures, by more than $1.3 billion.
25
ITEM 6. Selected Financial Data
The following table sets forth selected consolidated financial data of Chesapeake for the years ended December 31, 2003, 2002, 2001, 2000 and 1999. The data are derived from our audited consolidated financial statements revised to reflect the reclassification of certain items. In addition to changes in the annual average prices for oil and gas and increased production from drilling activity, significant acquisitions in recent years also impacted comparability between years. See note 13 of notes to consolidated financial statements. The table should be read in conjunction with Managements Discussion and Analysis of Financial Condition and Results of Operations and our consolidated financial statements, including the notes, appearing in Items 7 and 8 of this report.
Years Ended December 31, |
||||||||||||||||||||
2003 |
2002 |
2001 |
2000 |
1999 |
||||||||||||||||
($ in thousands, except per share data) | ||||||||||||||||||||
Statement of Operations Data: |
||||||||||||||||||||
Revenues: |
||||||||||||||||||||
Oil and gas sales |
$ | 1,296,822 | $ | 568,187 | $ | 820,318 | $ | 470,170 | $ | 280,445 | ||||||||||
Oil and gas marketing sales |
420,610 | 170,315 | 148,733 | 157,782 | 74,501 | |||||||||||||||
Total revenues |
1,717,432 | 738,502 | 969,051 | 627,952 | 354,946 | |||||||||||||||
Operating costs: |
||||||||||||||||||||
Production expenses |
137,583 | 98,191 | 75,374 | 50,085 | 46,298 | |||||||||||||||
Production taxes |
77,893 | 30,101 | 33,010 | 24,840 | 13,264 | |||||||||||||||
General and administrative |
23,753 | 17,618 | 14,449 | 13,177 | 13,477 | |||||||||||||||
Oil and gas marketing expenses |
410,288 | 165,736 | 144,373 | 152,309 | 71,533 | |||||||||||||||
Oil and gas depreciation, depletion and amortization |
369,465 | 221,189 | 172,902 | 101,291 | 95,044 | |||||||||||||||
Depreciation and amortization of other assets |
16,793 | 14,009 | 8,663 | 7,481 | 7,810 | |||||||||||||||
Provision for legal settlements |
6,402 | | | | | |||||||||||||||
Total operating costs |
1,042,177 | 546,844 | 448,771 | 349,183 | 247,426 | |||||||||||||||
Income (loss) from operations |
675,255 | 191,658 | 520,280 | 278,769 | 107,520 | |||||||||||||||
Other income (expense): |
||||||||||||||||||||
Interest and other income |
2,827 | 7,340 | 2,877 | 3,649 | 8,562 | |||||||||||||||
Interest expense |
(154,356 | ) | (112,031 | ) | (98,321 | ) | (86,256 | ) | (81,052 | ) | ||||||||||
Loss on investment in Seven Seas |
(2,015 | ) | (17,201 | ) | | | | |||||||||||||
Loss on repurchases of debt |
(20,759 | ) | (2,626 | ) | (76,667 | ) | | | ||||||||||||
Impairments of investments in securities |
| | (10,079 | ) | | | ||||||||||||||
Gain on sale of Canadian subsidiary |
| | 27,000 | | | |||||||||||||||
Gothic standby credit facility costs |
| | (3,392 | ) | | | ||||||||||||||
Total other income (expense) |
(174,303 | ) | (124,518 | ) | (158,582 | ) | (82,607 | ) | (72,490 | ) | ||||||||||
Income before income taxes and cumulative effect of accounting change |
500,952 | 67,140 | 361,698 | 196,162 | 35,030 | |||||||||||||||
Income tax expense (benefit): |
||||||||||||||||||||
Current |
5,000 | (1,822 | ) | 3,565 | | | ||||||||||||||
Deferred |
185,360 | 28,676 | 140,727 | (259,408 | ) | 1,764 | ||||||||||||||
Total income tax expense (benefit) |
190,360 | 26,854 | 144,292 | (259,408 | ) | 1,764 | ||||||||||||||
Net income before cumulative effect of accounting change, net of tax |
310,592 | 40,286 | 217,406 | 455,570 | 33,266 | |||||||||||||||
Cumulative effect of accounting change, net of income taxes of $1,464,000 |
2,389 | | | | | |||||||||||||||
Net Income |
312,981 | 40,286 | 217,406 | 455,570 | 33,266 | |||||||||||||||
Preferred stock dividends |
(22,469 | ) | (10,117 | ) | (2,050 | ) | (8,484 | ) | (16,711 | ) | ||||||||||
Gain on redemption of preferred stock |
| | | 6,574 | | |||||||||||||||
Net income available to common shareholders |
$ | 290,512 | $ | 30,169 | $ | 215,356 | $ | 453,660 | $ | 16,555 | ||||||||||
Earnings per common sharebasic: |
||||||||||||||||||||
Income before cumulative effect of accounting change |
$ | 1.36 | $ | 0.18 | $ | 1.33 | $ | 3.52 | $ | 0.17 | ||||||||||
Cumulative effect of accounting change |
0.02 | | | | | |||||||||||||||
$ | 1.38 | $ | 0.18 | $ | 1.33 | $ | 3.52 | $ | 0.17 | |||||||||||
Earnings per common shareassuming dilution: |
||||||||||||||||||||
Income before cumulative effect of accounting change |
$ | 1.20 | $ | 0.17 | $ | 1.25 | $ | 3.01 | $ | 0.16 | ||||||||||
Cumulative effect of accounting change |
0.01 | | | | | |||||||||||||||
$ | 1.21 | $ | 0.17 | $ | 1.25 | $ | 3.01 | $ | 0.16 | |||||||||||
Cash dividends declared per common share |
$ | 0.14 | $ | 0.06 | $ | | $ | | $ | |
26
Years Ended December 31, |
||||||||||||||||||
2003 |
2002 |
2001 |
2000 |
1999 |
||||||||||||||
($ in thousands, except per share data) | ||||||||||||||||||
Cash Flow Data: |
||||||||||||||||||
Cash provided by operating activities before changes in assets and liabilities |
$ | 903,929 | $ | 412,517 | $ | 518,563 | $ | 305,804 | $ | 138,727 | ||||||||
Cash provided by operating activities |
945,602 | 432,531 | 553,737 | 314,640 | 145,022 | |||||||||||||
Cash used in investing activities |
2,077,217 | 779,745 | 670,105 | 325,229 | 153,908 | |||||||||||||
Cash provided by (used in) financing activities |
924,559 | 477,257 | 234,507 | (27,740 | ) | 13,102 | ||||||||||||
Effect of exchange rate changes on cash |
| | (545 | ) | (329 | ) | 4,922 | |||||||||||
Balance Sheet Data (at end of period): |
||||||||||||||||||
Total assets |
$ | 4,572,291 | $ | 2,875,608 | $ | 2,286,768 | $ | 1,440,426 | $ | 850,533 | ||||||||
Long-term debt, net of current maturities |
2,057,713 | 1,651,198 | 1,329,453 | 944,845 | 964,097 | |||||||||||||
Stockholders equity (deficit) |
1,732,810 | 907,875 | 767,407 | 313,232 | (217,544 | ) |
ITEM 7. Managements Discussion and Analysis of Financial Condition and Results of Operations
Financial Data
The following table sets forth information regarding the production volumes, oil and gas sales, average sales prices and expenses for the periods indicated:
Years Ended December 31, | |||||||||||
2003 |
2002 |
2001 | |||||||||
Net Production: |
|||||||||||
Oil (mbbl) |
4,665 | 3,466 | 2,880 | ||||||||
Gas (mmcf) |
240,366 | 160,682 | 144,171 | ||||||||
Gas equivalent (mmcfe) |
268,356 | 181,478 | 161,451 | ||||||||
Oil and Gas Sales ($ in thousands): |
|||||||||||
Oil sales |
$ | 132,630 | $ | 88,495 | $ | 69,602 | |||||
Oil derivatives realized gains (losses) |
(12,058 | ) | (1,092 | ) | 7,920 | ||||||
Oil derivatives unrealized gains (losses) |
(9,440 | ) | (7,369 | ) | 5,116 | ||||||
Total oil sales |
111,132 | 80,034 | 82,638 | ||||||||
Gas sales |
1,171,050 | 470,913 | 560,536 | ||||||||
Gas derivatives realized gains (losses) |
(5,331 | ) | 97,138 | 97,471 | |||||||
Gas derivatives unrealized gains (losses) |
19,971 | (79,898 | ) | 79,673 | |||||||
Total gas sales |
1,185,690 | 488,153 | 737,680 | ||||||||
Total oil and gas sales |
$ | 1,296,822 | $ | 568,187 | $ | 820,318 | |||||
Average Sales Price (excluding gains (losses) on derivatives): |
|||||||||||
Oil ($ per bbl) |
$ | 28.43 | $ | 25.53 | $ | 24.17 | |||||
Gas ($ per mcf) |
$ | 4.87 | $ | 2.93 | $ | 3.89 | |||||
Gas equivalent ($ per mcfe) |
$ | 4.86 | $ | 3.08 | $ | 3.90 | |||||
Average Sales Price (excluding unrealized gains (losses) on derivatives): |
|||||||||||
Oil ($ per bbl) |
$ | 25.85 | $ | 25.22 | $ | 26.92 | |||||
Gas ($ per mcf) |
$ | 4.85 | $ | 3.54 | $ | 4.56 | |||||
Gas equivalent ($ per mcfe) |
$ | 4.79 | $ | 3.61 | $ | 4.56 | |||||
Expenses ($ per mcfe): |
|||||||||||
Production expenses |
$ | 0.51 | $ | 0.54 | $ | 0.47 | |||||
Production taxes |
$ | 0.29 | $ | 0.17 | $ | 0.20 | |||||
General and administrative |
$ | 0.09 | $ | 0.10 | $ | 0.09 | |||||
Depreciation, depletion and amortization |
$ | 1.38 | $ | 1.22 | $ | 1.07 | |||||
Interest expense (a) |
$ | 0.55 | $ | 0.61 | $ | 0.61 | |||||
Interest Expense ($ in thousands): |
|||||||||||
Interest expense |
$ | 151,676 | $ | 114,695 | $ | 98,321 | |||||
Interest derivatives realized (gains) losses |
(3,859 | ) | (3,415 | ) | | ||||||
Interest derivatives unrealized (gains) losses |
6,539 | 751 | | ||||||||
Total interest expense |
$ | 154,356 | $ | 112,031 | $ | 98,321 | |||||
Net Wells Drilled |
456 | 279 | 245 | ||||||||
Net Wells at End of Period |
5,873 | 4,237 | 3,572 |
(a) | Includes the effects of realized gains or (losses) from hedging, but does not include the effects of unrealized gains or (losses) from hedging. |
27
Executive Summary
Chesapeake is the largest producer of natural gas in the Mid-Continent and is among the six largest independent producers of natural gas in the U.S. At the end of 2003, we owned interests in approximately 15,000 producing oil and gas wells. Our primary operating area is the Mid-Continent region of the United States, which includes Oklahoma, western Arkansas, southwestern Kansas and the Texas Panhandle. We are building secondary operating areas in the Permian Basin of western Texas and eastern New Mexico and in the South Texas and Texas Gulf Coast regions. The Company has achieved its current position as a result of a series of key management decisions made during the past six years. These decisions included favoring gas over oil, establishing regional dominance in our operating areas, delivering value-added growth through a balance of drilling and acquisitions and managing risk through opportunistic oil and natural gas hedging.
Oil and natural gas production for 2003 was 268 bcfe, an increase of 87 bcfe, or 48%, over the 181 bcfe produced in 2002. Of this 87 bcfe in year-over-year production growth, an estimated 36 bcfe was a result of organic drillbit growth while 51 bcfe was generated from acquisitions. We estimate our organic growth rate during 2003 was 20%, well above the companys forecasted organic growth rate of 5%.
We have increased our production annually for 14 consecutive years, which we believe is one of the best track records in the industry. In addition, the 2003 fourth quarter was Chesapeakes tenth consecutive quarter of sequential production growth. During the past ten quarters, Chesapeakes production has increased 87%, for an average sequential quarterly growth rate of 6.5% and an annualized growth rate of 28.1%
Chesapeake began 2003 with estimated proved reserves of 2,205 bcfe and ended the year with 3,169 bcfe, an increase of 964 bcfe, or 44%. Taking into account production of 268 bcfe, reserve replacement during the year was 1,232 bcfe, or 459%, at a finding and acquisition cost of $1.36 per mcfe. Our year-end 2003 proved reserves were 74% proved developed. Independent third-party reservoir engineers evaluated 74% of our estimated proved reserves at year-end 2003.
Of the 1,232 bcfe of proved reserve additions, acquisitions added 805 bcfe at a cost of $1.38 per mcfe and drilling, including positive revisions to previous estimates, added 438 bcfe for a reserve replacement rate from drilling of 163% at a cost of $1.32 per mcfe. Additionally, we continued to invest in our future in 2003. We made unproved property purchases of $198 million and incurred geological and geophysical expenditures of $38 million and lease acquisition expenditures of $85 million.
During 2003, Chesapeake drilled 442 (352 net) operated wells and participated in another 641 (104 net) wells operated by other companies. Chesapeakes drilling costs were $438 million for operated wells and $140 million for non-operated wells. The companys success rate was 96% for operated wells and 95% for non-operated wells. Chesapeake has an active property consolidation program that is focused on corporate and property acquisitions of up to $500 million. During 2003, we acquired approximately 805 bcfe of proved reserves for a total cost of $1.1 billion (primarily in nine transactions of more than $10 million each). Pro forma for two large acquisitions completed in January 2004, we spent $1.7 billion to acquire 1,102 bcfe of proved reserves in 2003.
As of December 31, 2003, Chesapeakes estimated future net cash flows discounted at 10% before taxes (PV-10) were $7.33 billion using field differential adjusted prices of $30.22 per bo (based on a NYMEX year-end price of $32.47 per bo) and $5.68 per mcf (based on a NYMEX year-end price of $5.97 per mcf). PV-10 as of December 31, 2002 was $3.72 billion using field differential adjusted prices of $30.18 per bo (based on a NYMEX year-end price of $31.25 per bo) and $4.28 per mcf (based on a NYMEX year-end price of $4.60 per mcf). Pro forma for acquisitions completed in January 2004, our proved reserves at year-end 2003 were 3,474 bcfe and had a PV-10 value of $7.9 billion.
Chesapeake continues to focus on improving the strength of its balance sheet. At the beginning of the year, the companys total debt as a percentage of total capitalization (total capitalization is the sum of total debt and
28
stockholders equity) was 65% and debt per proved mcfe was $0.75 per mcfe. By year-end 2003 (pro forma for the reserves acquired in January 2004 and the related financings and debt exchanges completed in January 2004), the companys debt as a percentage of total capitalization had decreased to 53% and debt per proved mcfe had decreased to $0.65 per mcfe, reductions of 18% and 13%, respectively. Key goals of management are to reduce debt to below 50% of total capitalization and debt per mcfe of proved reserves to below $0.60.
Liquidity and Capital Resources
Sources of Liquidity and Uses of Funds
Our primary source of liquidity to meet operating expenses and fund capital expenditures (other than for large acquisitions) is cash flow from operations in 2004. Based on our current production, price and expense assumptions, we expect cash flow from operations will exceed our drilling capital expenditures. Our budget for drilling, land and seismic activities during 2004 is currently between $750 million and $800 million. While we believe this level of exploration and development will be sufficient to increase our reserves in 2004 and achieve our target of a 20% increase in production over 2003 production (inclusive of acquisitions completed in January 2004), higher drilling and field operating costs, drilling results that alter planned development schedules, acquisitions or other factors could cause us to revise our drilling program, which is largely discretionary. Any cash flow from operations not needed to fund our drilling program will be available for acquisitions, debt repayment or other general corporate purposes in 2004.
Cash provided by operating activities (exclusive of changes in assets and liabilities) was $903.9 million in 2003, compared to $412.5 million in 2002 and $518.6 million in 2001. The $491.4 million increase from 2002 to 2003 was primarily due to higher realized prices and higher volumes of oil and gas production. The $106.1 million decrease from 2001 to 2002 was primarily due to decreased oil and gas revenues resulting from lower prices partially offset by higher volumes produced. We expect that 2004 production volumes will be higher than in 2003 and that cash provided by operating activities in 2004 will exceed 2003 levels. While a precipitous decline in gas prices in 2004 would significantly affect the amount of cash flow that would be generated from operations, we have 78% of our expected oil production in 2004 hedged at an average NYMEX price of $28.68 per barrel of oil and 69% of our expected natural gas production in 2004 hedged at an average NYMEX price of $5.32 per mcf. This level of hedging provides certainty of the cash flow we will receive for a substantial portion of our 2004 production. Depending on changes in oil and gas futures markets and managements view of underlying oil and natural gas supply and demand trends, however, we may increase or decrease our current hedging positions.
Another source of liquidity is our $350 million revolving bank credit facility (with a committed borrowing base of $350 million) which matures in May 2007. At March 10, 2004, we had $150 million of indebtedness under the bank credit facility. We use the facility to fund daily operating activities and acquisitions as needed. We borrowed and repaid $738.0 million in 2003 and $252.5 million in 2002, and we borrowed $433.5 million and repaid $458.5 million in 2001 under the facility. We incurred $2.5 million, $2.9 million and $6.6 million of financing costs related to the credit facility in 2003, 2002 and 2001, respectively, as a result of amendments to the credit facility agreement.
We believe that our available cash, cash provided by operating activities and funds available under our bank credit facility will be sufficient to fund our operating, interest and general and administrative expenses, our capital expenditure budget, our short-term contractual obligations and dividend payments at current levels for the foreseeable future.
The public markets have been our principal source of capital to finance large acquisitions. We have sold debt and equity in both public and private offerings in the past, and we expect that these sources of capital will continue to be available to us in the future for acquisitions. Nevertheless, we caution you that ready access to
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capital on reasonable terms and the availability of desirable acquisition targets at attractive prices are subject to many uncertainties, as explained under Risk Factors in Item 1Business. The following table reflects the proceeds from sales of securities we issued in 2003, 2002 and 2001($ in millions):
2003 |
2002 |
2001 | ||||||||||||||||
Total Proceeds |
Net Proceeds |
Total Proceeds |
Net Proceeds |
Total Proceeds |
Net Proceeds | |||||||||||||
Unsecured senior notes guaranteed by subsidiaries |
$ | 500.0 | $ | 485.4 | $ | 450.0 | $ | 439.4 | $ | 1,050.0 | $ | 1,028.3 | ||||||
Convertible preferred stock |
402.5 | 390.4 | | | 150.0 | 145.1 | ||||||||||||
Common stock |
186.3 | 177.4 | 172.5 | 164.1 | | | ||||||||||||
Total |
$ | 1,088.8 | $ | 1,053.2 | $ | 622.5 | $ | 603.5 | $ | 1,200.0 | $ | 1,173.4 | ||||||
We used $27.3 million and $5.0 million to pay common stock dividends in 2003 and 2002, respectively, and we paid dividends of $20.9 million, $10.2 million and $1.1 million on our preferred stock in 2003, 2002 and 2001. We received $9.3 million, $3.8 million and $3.2 million from the exercise of employee and director stock options in 2003, 2002 and 2001, respectively. We used $2.1 million to purchase treasury stock in 2003 to fund our matching contributions to the 401(k) Make-Up Plan.
Historically, we have used significant amounts of funds to purchase and retire outstanding company senior notes. In 2003, we purchased and subsequently retired $106.4 million of our 8.5% senior notes for $113.1 million, including redemption premium of $6.7 million. In 2002, we purchased and subsequently retired $107.9 million of our 7.875% senior notes for $111.6 million, including redemption premium of $3.7 million. In 2001, we used $906.0 million to purchase or redeem various Chesapeake and Gothic senior notes. We paid $3.3 million for make-whole provisions in the fourth quarter 2001 related to the exchange of our common stock for RAM Energy, Inc. common stock which occurred in March 2001.
Cash used in investing activities increased to $2,077.2 million in 2003, compared to $779.7 million in 2002 and $670.1 million in 2001. The following table shows our capital expenditures during these years ($ in millions):
2003 |
2002 |
2001 | |||||||
Exploration and development drilling |
$ | 727.2 | $ | 400.2 | $ | 421.0 | |||
Acquisitions of oil and gas properties and companies |
1,261.3 | 331.7 | 316.7 | ||||||
Deposit for pending acquisitions |
13.3 | 15.0 | | ||||||
Investment in securities of other companies |
30.8 | 2.4 | 40.2 | ||||||
Drilling rigs, plants and gathering systems |
23.3 | 6.6 | 15.9 | ||||||
Office buildings and other administrative |
49.4 | 30.6 | 23.1 | ||||||
Total |
$ | 2,105.3 | $ | 786.5 | $ | 816.9 | |||
Through divestitures of oil and gas properties, we received $22.2 million in 2003, $0.8 million in 2002 and $144.3 million, including $142.9 million for the sale of our Canadian subsidiary, in 2001. Sales of other assets and recoveries of investments in securities of other companies provided $5.8 million, $5.8 million and $3.2 million of cash in 2003, 2002 and 2001, respectively.
During 2003 and early 2004, we took several steps to improve our capital structure, including the transactions described below under Investing and Financing Transactions. These transactions enabled us to extend our average maturity of long-term debt to over nine years with an average interest rate of 7.7%. The companys debt as a percentage of total capitalization decreased to 53% (pro forma for January and February 2004 securities transactions) and debt per proved mcfe decreased to $0.65 per mcfe. Reducing debt to below 50% of total capitalization and reducing debt per mcfe of proved reserves to below $0.60 are key goals of our business strategy.
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Our accounts receivable are primarily from purchasers of oil and natural gas ($173.8 million at December 31, 2003) and exploration and production companies which own interests in properties we operate ($37.8 million at December 31, 2003). This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers may be similarly affected by changes in economic, industry or other conditions. We generally require letters of credit for receivables from customers which are judged to have sub-standard credit, unless the credit risk can otherwise be mitigated.
Our liquidity is not dependent on the use of off-balance sheet financing arrangements, such as the securitization of receivables or obtaining access to assets through special purpose entities. We have not relied on off-balance sheet financing arrangements in the past and we do not intend to rely on such arrangements in the future as a source of liquidity. We are not a commercial paper issuer.
Investing and Financing Transactions
The following describes significant investing and financing transactions that we completed in 2003 and in January and February 2004:
Investing Transactions:
First Quarter 2003
| Mid-Continent properties from a wholly-owned subsidiary of ONEOK, Inc.: cash consideration of $296 million of which $15 million was paid in 2002 |
| Anadarko Basin properties in western Oklahoma and Texas Panhandle from El Paso Corporation: cash consideration of approximately $500 million |
| Bray Field properties in southern Oklahoma from Vintage Petroleum, Inc.: cash consideration of approximately $29 million |
| 5.3 million shares, or approximately 25%, of Pioneer Drilling Company common stock: $20 million |
Second Quarter 2003
| Oxley Petroleum Company, Arkoma Basin properties in eastern Oklahoma and western Arkansas: cash consideration of approximately $155 million |
Third Quarter 2003
| Beckham County, Oklahoma producing properties, gas gathering system and gas treatment plant: cash consideration of approximately $44.5 million |
| 25% limited partnership interest in Eagle Energy Partnership I, L.P., a gas marketing company: $5.8 million |
Fourth Quarter 2003
| 20% limited partnership interest in Texas Vicksburg Holding L.P., which conducts E&P operations through several partnerships: $5.0 million |
| South Texas properties from Laredo Energy, L.P. and its partners: cash consideration of approximately $200 million |
| Permian Basin properties: cash consideration of $23 million |
January 2004
| Concho Resources Inc., Permian Basin and Mid-Continent properties: cash consideration of approximately $420 million of which $10 million was paid in 2003 |
| South Texas properties: cash consideration of approximately $65 million of which $3.3 million was paid in 2003 |
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Financing Transactions:
First Quarter 2003
| Private placement of $300 million 7.5% senior notes due 2013 |
| Public offering of 23 million shares of common stock at $8.10 per share |
| Private placement of $230 million of 6.0% cumulative convertible preferred stock |
Third Quarter 2003
| Privately negotiated exchange of $63.0 million of 7.75% senior notes due 2015 and accrued interest of $0.1 million for $27.9 million of 8.375% senior notes due 2008 and accrued interest of $0.5 million and $32.0 million of 8.5% senior notes due 2012 and accrued interest of $1.1 million |
Fourth Quarter 2003
| Privately negotiated exchange of $23.7 million of 7.75% senior notes due 2015 and accrued interest of $0.4 million for $6.0 million of 8.375% senior notes due 2008 and accrued interest of $0.2 million and $16.8 million of 8.125% senior notes due 2011 |
| Privately negotiated exchange of $63.8 million of 7.5% senior notes due 2013 and accrued interest of $0.4 million for $54.9 million of 8.125% senior notes due 2011 and accrued interest of $0.2 million and $6.3 million of 8.375% senior notes due 2008 and accrued interest of $0.2 million |
| Private placement of $200 million 6.875% senior notes due 2016 |
| Public offering of 1,725,000 shares of 5.0% convertible preferred stock at $100 per share |
| Paid $113.1 million (including premium of $6.7 million) for $106.4 million of 8.5% senior notes due 2012 pursuant to cash tender offer |
January and February 2004
| Public offering of 23 million shares of common stock at $13.51 per share |
| Public exchange of $72.8 million of 7.75% senior notes due 2015 and accrued interest of $2.8 million and additional $433.5 million of 6.875% senior notes due 2016 and accrued interest of $4.1 million for $458.5 million of 8.125% senior notes due 2011 and accrued interest of $10.8 million |
| Privately negotiated exchanges of $37.0 million of 6.875% senior notes due 2016 and accrued interest of $0.5 million for $24.3 million of 8.125% senior notes due 2011 and accrued interest of $0.7 million and $9.1 million of 7.75% senior notes due 2015 and accrued interest of $0.1 million |
Contractual Obligations
We have a $350 million revolving bank credit facility (with a committed borrowing base of $350 million) which matures in May 2007. As of December 31, 2003, we had no outstanding borrowings under this facility and had utilized $35.8 million of the facility for various letters of credit. Borrowings under the facility are collateralized by certain producing oil and gas properties and bear interest at either (i) the greater of the reference rate of Union Bank of California, N.A., or the federal funds effective rate plus 0.50% or (ii) London Interbank Offered Rate (LIBOR), at our option, plus a margin that varies according to our senior unsecured long-term debt rating. The collateral value and borrowing base are redetermined periodically. The unused portion of the facility is subject to an annual commitment fee of 0.375%. Interest is payable quarterly or, if LIBOR applies, it may be payable at more frequent intervals.
The credit facility agreement contains various covenants and restrictive provisions which limit our ability to incur additional indebtedness, sell properties, pay dividends, purchase or redeem our capital stock, make
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investments or loans or purchase certain of our senior notes, and create liens. The credit facility agreement requires us to maintain a current ratio (as defined) of at least 1 to 1 and a fixed charge coverage ratio (as defined) of at least 2.5 to 1. At December 31, 2003, our current ratio was 1.6 to 1 and our fixed charge coverage ratio was 4.8 to 1. If we should fail to perform our obligations under these and other covenants, the revolving credit commitment could be terminated and any outstanding borrowings under the facility could be declared immediately due and payable. Such acceleration, if involving a principal amount of $10 million or more, would constitute an event of default under our senior note indentures, which could in turn result in the acceleration of our senior note indebtedness. The credit facility agreement also has cross default provisions that apply to other indebtedness we may have with an outstanding principal amount in excess of $25.0 million.
As of December 31, 2003, senior notes represented approximately $2.1 billion of our long-term debt and consisted of the following ($ in thousands):
7.875% senior notes due 2004(a) |
$ | 42,137 | ||
8.375% senior notes due 2008 |
209,815 | |||
8.125% senior notes due 2011 |
728,255 | |||
9.0% senior notes due 2012 |
300,000 | |||
8.5% senior notes due 2012 |
4,290 | |||
7.5% senior notes due 2013 |
363,823 | |||
7.75% senior notes due 2015 |
236,691 | |||
6.875% senior notes due 2016 |
200,000 | |||
Discount on senior notes |
(26,959 | ) | ||
Discount for interest rate swap and swaption |
(339 | ) | ||
$ | 2,057,713 | |||
(a) | This amount was classified as long-term debt based on our ability and intent to satisfy this obligation with funding from our bank credit facility. |
Following the debt exchanges which occurred in January and February 2004 and excluding the 7.875% senior notes which were paid in March 2004 and the 8.5% senior notes which were called for redemption in March 2004, our pro forma senior notes payable as of December 31, 2003 consisted of the following:
8.375% senior notes due 2008 |
$ | 209,815 | ||
8.125% senior notes due 2011 |
245,407 | |||
9.0% senior notes due 2012 |
300,000 | |||
7.5% senior notes due 2013 |
363,823 | |||
7.75% senior notes due 2015 |
300,408 | |||
6.875% senior notes due 2016 |
670,487 | |||
Discount on senior notes |
(79,298 | ) | ||
$ | 2,010,642 | |||
No scheduled principal payments are required on any of the senior notes until 2008, when $209.8 million is due. Debt ratings for the senior notes are Ba3 by Moodys Investor Service, BB- by Standard & Poors Ratings Services and BB- by Fitch Ratings. Debt ratings for our secured bank credit facility are Ba2 by Moodys Investor Service, BBB- by Standard & Poors Ratings Services and BB+ by Fitch Ratings.
Our senior notes are unsecured senior obligations of Chesapeake and rank equally with all of our other unsecured indebtedness. All of our wholly owned subsidiaries except Chesapeake Energy Marketing, Inc., Mayfield Processing, L.L.C. and MidCon Compression, L.P. guarantee the notes. The indentures permit us to redeem the senior notes at any time at specified make-whole or redemption prices. The indentures for the 8.125%, 8.375%, 9.0%, 7.75%, 7.50% and 6.875% senior notes contain covenants limiting our ability and our restricted subsidiaries ability to incur additional indebtedness; pay dividends on our capital stock or redeem, repurchase or retire our capital stock or subordinated indebtedness; make investments and other restricted
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payments; create restrictions on the payment of dividends or other amounts to us from our restricted subsidiaries; incur liens; engage in transactions with affiliates; sell assets; and consolidate, merge or transfer assets. The debt incurrence covenants do not affect our ability to borrow under or expand our secured credit facility. As of December 31, 2003, we estimate that secured commercial bank indebtedness of approximately $1,237.3 million could have been incurred under the most restrictive indenture covenant. The indenture covenants do not apply to our marketing subsidiaries, Chesapeake Energy Marketing, Inc., Mayfield Processing, L.L.C. and MidCon Compression, L.P., which are our only unrestricted subsidiaries.
The table below summarizes our contractual obligations as of December 31, 2003 ($ in thousands):
Payments Due By Period | |||||||||||||||
Contractual Obligations |
Total |
Less than 1 Year |
1-3 Years |
3-5 Years |
More than 5 Years | ||||||||||
Long-term debt obligations |
$ | 2,085,011 | $ | 42,137 | $ | | $ | 209,815 | $ | 1,833,059 | |||||
Capital lease obligations |
| | | | | ||||||||||
Operating lease obligations |
5,437 | 2,353 | 2,169 | 500 | 415 | ||||||||||
Purchase obligations |
| | | | | ||||||||||
Standby letters of credit |
36,358 | 36,358 | | | | ||||||||||
Other long-term obligations |
1,738 | 1,496 | 242 | | | ||||||||||
Total contractual cash obligations |
$ | 2,128,544 | $ | 82,344 | $ | 2,411 | $ | 210,315 | $ | 1,833,474 | |||||
Some of our commodity price and financial risk management arrangements require us to deliver cash collateral or other assurances of performance to the counterparties in the event that our payment obligations with respect to our commodity price and financial risk management transactions exceed certain levels. At December 31, 2003, we were required to post $33.5 million of collateral and at March 10, 2004, we were required to post $70.0 million of collateral. Future collateral requirements are uncertain and will depend on arrangements with our counterparties, highly volatile natural gas and oil prices, and fluctuations in interest rates.
Hedging Activities
Oil and Gas Hedging Activities
Our results of operations and operating cash flows are impacted by changes in market prices for oil and gas. To mitigate a portion of the exposure to adverse market changes, we have entered into various derivative instruments, including swaps, counter-swaps (locking in the value of certain swaps), cap-swaps, basis protection swaps and call options. Item 7AQuantitative and Qualitative Disclosures About Market Risk contains a description of each of these instruments.
Hedging allows us to predict with greater certainty the effective prices we will receive for our hedged oil and gas production. We closely monitor the fair value of our hedging contracts and may elect to settle a contract prior to its scheduled maturity date in order to lock in a gain or loss. Commodity markets are volatile, and Chesapeakes hedging activity is dynamic.
Mark-to-market positions under oil and gas hedging contracts fluctuate with commodity prices. As described above under Contractual Obligations, we may be required to deliver cash collateral or other assurances of performance if our payment obligations to our hedging counterparties exceed levels stated in our contracts.
Realized gains and losses from our oil and gas derivatives resulted in a net decrease in oil and gas sales of $17.4 million or $0.06 per mcfe in 2003, a net increase of $96.0 million or $0.53 per mcfe in 2002 and a net increase of $105.4 million or $0.65 per mcfe in 2001. Oil and gas sales also includes changes in the fair value of oil and gas derivatives that do not qualify as cash flow hedges under SFAS 133, as well as gains (losses) on
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ineffectiveness of instruments designated as cash flow hedges. Unrealized gains (losses) included in oil and gas sales in 2003, 2002 and 2001 were $10.5 million, ($87.3) million and $84.8 million, respectively. Included in these unrealized gains (losses) are gains (losses) on ineffectiveness of cash flow hedges of ($9.2) million in 2003, ($3.6) million in 2002 and $2.5 million in 2001.
Changes in the fair value of oil and gas derivative instruments designated as cash flow hedges, to the extent effective in offsetting cash flows attributable to the hedged commodities, and locked-in gains and losses of derivative contracts are recorded in accumulated other comprehensive income until the month of related production. These unrealized losses, net of related tax effects, totaled $20.3 million and $3.5 million as of December 31, 2003 and 2002, respectively. Based upon the market prices at December 31, 2003, we expect to transfer to earnings approximately $17.6 million of the balance in accumulated other comprehensive income during the next 12 months. A detailed explanation of accounting for oil and gas derivatives under SFAS 133 appears under Application of Critical Accounting Policies-Hedging elsewhere in this Item 7.
The fair value of our oil and gas derivative instruments is recorded on our consolidated balance sheet as assets or liabilities. The estimated fair values of our oil and gas derivative instruments as of December 31, 2003 and 2002 are provided below:
December 31, |
||||||||
2003 |
2002 |
|||||||
($ in thousands) | ||||||||
Derivative assets (liabilities): |
||||||||
Fixed-price gas swaps |
$ | (44,794 | ) | $ | (21,523 | ) | ||
Fixed-price gas cap-swaps |
(18,608 | ) | (50,732 | ) | ||||
Gas basis protection swaps |
46,205 | 8,227 | ||||||
Fixed-price gas counter swaps |
| 37,048 | ||||||
Gas call options |
(17,876 | ) | | |||||
Fixed-price gas locked swaps |
1,777 | 16,498 | ||||||
Fixed-price crude oil swaps |
| (1,799 | ) | |||||
Fixed-price crude oil cap-swaps |
(11,692 | ) | (2,252 | ) | ||||
Estimated fair value |
$ | (44,988 | ) | $ | (14,533 | ) | ||
As of December 31, 2003, we had hedged approximately 78% of our expected oil production and 69% of our expected natural gas production in 2004. In addition, hedging contracts were in place for approximately 27% of expected natural gas production in 2005, 11% in 2006 and 8% in 2007. Natural gas basis protection swaps extend to 2009. A detailed listing of our oil and gas derivatives by year of maturity is included in Item 7AQuantitative and Qualitative Disclosures About Market Risk.
Additional information concerning changes in the fair value of our oil and gas derivative instruments is as follows:
December 31, |
||||||||||||
2003 |
2002 |
2001 |
||||||||||
($ in thousands) | ||||||||||||
Fair value of contracts outstanding, beginning of year |
$ | (14,533 | ) | $ | 157,309 | $ | (89,288 | ) | ||||
Change in fair value of contracts during the period |
(31,078 | ) | (52,419 | ) | 351,989 | |||||||
Contracts realized or otherwise settled during the period |
17,389 | (96,046 | ) | (105,392 | ) | |||||||
Fair value of new contracts when entered into during the period |
(16,766 | ) | (45,603 | ) | | |||||||
Fair value of contracts when closed during the period |
| 22,226 | | |||||||||
Fair value of contracts outstanding, end of year |
$ | (44,988 | ) | $ | (14,533 | ) | $ | 157,309 | ||||
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Interest Rate Hedging
We also utilize hedging strategies to manage the exposure our fixed-rate senior notes have to interest rate changes. By entering into interest rate swaps, we convert a portion of our fixed rate debt to floating rate debt. To the extent the interest rate swaps have been designated as fair value hedges, changes in the fair value of the derivative instrument and the corresponding debt are reflected as adjustments to interest expense in the corresponding months covered by the derivative agreement.
The following describes interest rate swaps entered into during 2002 and 2003, all of which were terminated prior to contractual maturity for cash settlements ($ in thousands):
Date |
Fair Value at |
Date |
Cash Settlement |
Gains Recognized in 2002 |
Gains Recognized in 2003 |
Gains to be Recognized in | ||||||||||||
March 2002(a) |
$ | | July 2002 | $ | 7,500 | $ | 6,778 | (c) | $ | 599 | $ | 123 | ||||||
June 2002(b) |
| July 2002 | 1,130 | 1,130 | | | ||||||||||||
August 2003(b) |
870 | January 2004 | 940 | | 870 | 70 | ||||||||||||
August 2003(b) |
1,292 | January 2004 | 1,370 | | 1,292 | 78 |
(a) | This instrument was designated as a fair value hedge with changes in the fair value recorded as an adjustment to the debt. Upon termination of the hedging relationship, the previously recorded changes in the fair value of the debt are amortized to earnings over the term of the debt. |
(b) | These instruments were not designated as fair value hedges; therefore, changes in the fair value were recorded as adjustments to interest expense. |
(c) | Of this amount, $1.7 million was recognized as a reduction to the loss on repurchases of debt upon retirement of 7.785% notes. |
In April 2002, Chesapeake entered into a swaption with an unrelated counterparty with respect to its 8.5% senior notes due 2012. The notional amount of the swaption was $142.7 million, which was the principal amount then outstanding under the 8.5% senior notes. The 8.5% senior notes included a call option whereby Chesapeake may redeem the debt at declining redemption prices beginning in March 2004. Under the swaption, the counterparty received the option to elect whether or not to enter into an interest rate swap with Chesapeake in March 2004, and Chesapeake received $7.8 million. The interest rate swap, if executed by the counterparty, requires Chesapeake to pay a fixed rate of 8.5% while the counterparty pays Chesapeake a floating rate of 6 month LIBOR plus 0.75%. Additionally, if the counterparty elects to enter into the interest rate swap, it may also elect to force Chesapeake to settle the transaction at the then current value of the interest rate swap.
According to SFAS 133, a fair value hedge relationship exists between the embedded call option in the 8.5% senior notes and the swaption. The fair value of the swaption is recorded on the consolidated balance sheets as a liability, and the carrying amount of the debt is adjusted by the change in the fair value of the call option subsequent to the initiation of the swaption. Any resulting differences are recorded currently as ineffectiveness in the consolidated statements of operations as an adjustment to interest expense.
During the third quarter 2003, we exchanged and subsequently retired $32.0 million of our 8.5% senior notes. The exchange of debt was treated as a modification rather than an extinguishment. Accordingly, the adjustment to the carrying value of the debt of $3.3 million related to the application of hedge accounting was reflected as a discount on the notes issued in the exchange transaction and will be amortized to interest expense using the effective interest method. During the fourth quarter 2003, we purchased and subsequently retired $106.4 million of the remaining $110.7 million of 8.5% senior notes pursuant to a tender offer and recorded a $12.0 million loss related to the removal of the fair value designation of the corresponding amount of the swaption. Temporary fluctuations in the fair value of the portion of the swaption no longer designated as a fair value hedge are recorded as adjustments to interest expense. We recorded a $3.3 million unrealized loss in interest expense during 2003 due to a decline in the fair value of the portion of the swaption no longer designated as a fair value hedge.
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As of December 31, 2003, the remaining notional amount of the swaption designated as a fair value hedge was $4.3 million. We have recorded an adjustment to the carrying amount of the debt of $0.5 million which represents the temporary fluctuations in the fair value of the call option included in the $4.3 million principal amount of 8.5% senior notes. Since the inception of the swaption, we have recorded a change in the fair market value of the swaption from a $7.8 million liability to a $32.6 million liability, an increase of $24.8 million. We have recorded as additional interest expense $5.6 million to reflect ineffectiveness after giving effect to the removal of the designation of a portion of the swaption as a fair value hedge under SFAS 133 as described previously.
On February 27, 2004, Chesapeake and the counterparty agreed to extend the counterpartys right to require Chesapeake to settle the transaction on March 15, 2004 to April 15, 2004. On March 10, 2004, the counterparty exercised its option to enter into the interest rate swap effective March 15, 2004. On April 15, 2004 and each succeeding March 15, the counterparty may elect to terminate the swap and cause it to be settled at the then current value of the interest rate swap. We may elect to terminate the swap and cause it to be settled at the then current value of the interest rate swap at any time during the term of the swap. Cash payments related to the interest rate swap, if initiated, or as a result of cash settlement at termination, will be recorded as adjustments to earnings.
Results of Operations
General. For the year ended December 31, 2003, Chesapeake had net income of $313.0 million, or $1.21 per diluted common share, on total revenues of $1,717.4 million. This compares to net income of $40.3 million, or $0.17 per diluted common share, on total revenues of $738.5 million during the year ended December 31, 2002, and net income of $217.4 million, or $1.25 per diluted common share, on total revenues of $969.1 million during the year ended December 31, 2001. The 2003 net income includes, on a pre-tax basis, a $20.8 million loss on repurchases of debt, a $6.4 million provision for legal settlements, $4.0 million in net unrealized gains on oil and gas and interest rate derivatives and a $2.0 million impairment of our investment in Seven Seas Petroleum Inc. The 2002 net income includes, on a pre-tax basis, $88.0 million in net unrealized losses on oil and gas and interest rate derivatives, a $17.2 million impairment of our investment in Seven Seas Petroleum Inc. and a $2.6 million loss on repurchases of debt. The 2001 net income included, on a pre-tax basis, $84.8 million in net unrealized gains on oil and gas derivatives, a $10.1 million impairment of certain equity investments, a $27.0 million gain on the sale of our Canadian subsidiary, a $3.4 million cost for an unsecured standby credit facility associated with the acquisition of Gothic Energy Corporation and a $76.7 million loss on repurchases of debt.
Oil and Gas Sales. During 2003, oil and gas sales were $1,296.8 million versus $568.2 million in 2002 and $820.3 million in 2001. In 2003, Chesapeake produced 268.4 bcfe at a weighted average price of $4.79 per mcfe, compared to 181.5 bcfe produced in 2002 at a weighted average price of $3.61 per mcfe, and 161.5 bcfe produced in 2001 at a weighted average price of $4.56 per mcfe (weighted average prices for all years discussed exclude the effect of unrealized gains or losses on derivatives). The increase in prices in 2003 resulted in an increase in revenue of $317.2 million and increased production resulted in a $313.6 million increase, for a total increase in revenues of $630.8 million (excluding unrealized gains or losses on oil and gas derivatives).
The change in oil and gas prices has a significant impact on our oil and gas revenues and cash flows. Assuming 2003 production levels, a change of $0.10 per mcf of gas produced would result in an increase or decrease in revenues and cash flow of approximately $24.0 million and $22.6 million, respectively, and a change of $1.00 per barrel of oil produced would result in an increase or decrease in revenues and cash flows of approximately $4.7 million and $4.4 million, respectively, without considering the effect of derivative activities.
For 2003, we realized an average price per barrel of oil of $25.85, compared to $25.22 in 2002 and $26.92 in 2001 (weighted average prices for all years discussed exclude the effect of unrealized gains or losses on derivatives). Natural gas prices realized per mcf (excluding unrealized gains or losses on derivatives) were $4.85, $3.54 and $4.56 in 2003, 2002 and 2001, respectively. Realized gains or losses from our oil and gas derivatives resulted in a net decrease in oil and gas revenues of $17.4 million or $0.06 per mcfe in 2003, a net increase of $96.0 million or $0.53 per mcfe in 2002 and a net increase of $105.4 million or $0.65 per mcfe in 2001.
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Year over year changes in oil and gas sales during the last three years were also affected by unrealized gains (losses) on oil and gas derivatives, which were $10.5 million in 2003, $(87.3) million in 2002 and $84.8 million in 2001.
The following table shows our production by region for 2003, 2002 and 2001:
Years Ended December 31, |
|||||||||||||||
2003 |
2002 |
2001 |
|||||||||||||
mmcfe |
Percent |
mmcfe |
Percent |
mmcfe |
Percent |
||||||||||
Mid-Continent |
233,559 | 87.0 | % | 147,348 | 81.2 | % | 116,133 | 71.9 | % | ||||||
South Texas and Texas Gulf Coast |
23,322 | 8.7 | 23,264 | 12.8 | 27,531 | 17.1 | |||||||||
Permian Basin |
8,496 | 3.2 | 7,637 | 4.2 | 5,029 | 3.1 | |||||||||
Williston Basin and Other |
2,979 | 1.1 | 3,229 | 1.8 | 3,683 | 2.3 | |||||||||
Canada |
| | | | 9,075 | 5.6 | |||||||||
Total production |
268,356 | 100.0 | % | 181,478 | 100.0 | % | 161,451 | 100.0 | % | ||||||
Natural gas production represented approximately 90% of our total production volume on an equivalent basis in 2003, compared to 89% in 2002 and 89% 2001. The increase in production from 2001 through 2003 is due to the combination of organic production growth during the period as well as acquisitions completed in 2002 and 2003.
Oil and Gas Marketing Sales. Chesapeake realized $420.6 million in oil and gas marketing sales for third parties in 2003, with corresponding oil and gas marketing expenses of $410.3 million, for a net margin of $10.3 million. Sales for third parties include the sale of oil and gas from wells not operated by Chesapeake, as well as the sale of oil and gas from working interest owners other than Chesapeake in wells operated by Chesapeake. This compares to sales of $170.3 million and $148.7 million, expenses of $165.7 million and $144.4 million, and margins of $4.6 million and $4.3 million in 2002 and 2001, respectively. In 2003, Chesapeake realized an increase in volumes and prices related to oil and gas marketing sales. In 2002, the increase in volume was partially offset by a decrease in oil and gas prices.
Production Expenses. Production expenses, which include lifting costs and ad valorem taxes, were $137.6 million in 2003, compared to $98.2 million and $75.4 million in 2002 and 2001, respectively. On a unit-of-production basis, production expenses were $0.51 per mcfe in 2003 compared to $0.54 and $0.47 per mcfe in 2002 and 2001, respectively. The decrease in costs on a per unit basis in 2003 is due primarily to lower production costs associated with properties acquired during the year and realization of efficiencies from higher scale of operations in the Mid-Continent region. The increase in 2002 was primarily due to higher field service costs and higher production costs associated with properties acquired during 2002. We expect that production expenses per mcfe in 2004 will range from $0.55 to $0.60.
Production Taxes. Production taxes were $77.9 million in 2003 compared to $30.1 million in 2002 and $33.0 million in 2001. On a unit-of-production basis, production taxes were $0.29, $0.17 and $0.20 per mcfe in 2003, 2002 and 2001, respectively. The increase in 2003 of $47.8 million was due to an increase in the average wellhead prices received for natural gas and the loss of certain Oklahoma severance tax exemptions resulting from natural gas prices exceeding a pre-determined ceiling during the period. The decrease in 2002 of $2.9 million was due to a decrease in the average wellhead prices received for natural gas. In general, production taxes are calculated using value-based formulas that produce higher per unit costs when oil and gas prices are higher. We expect production taxes per mcfe to range from $0.28 to $0.32 in 2004 based on an assumption that oil and natural gas wellhead prices range from $4.50 to $5.00 per mcfe.
General and Administrative Expenses. General and administrative expenses, which are net of internal payroll and non-payroll costs capitalized in our oil and gas properties (see note 11 of notes to consolidated financial statements), were $23.8 million in 2003, $17.6 million in 2002 and $14.4 million in 2001. The increase
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in 2003 and 2002 is the result of the companys growth related to the various acquisitions which occurred in 2003 and 2002. This growth has resulted in a substantial increase in employees and related costs. We anticipate that general and administrative expenses for 2004 will be between $0.10 and $0.11 per mcfe produced, which is approximately the same level as 2003.
Chesapeake follows the full-cost method of accounting under which all costs associated with property acquisition, exploration and development activities are capitalized. We capitalize internal costs that can be directly identified with our acquisition, exploration and development activities and do not include any costs related to production, general corporate overhead or similar activities. We capitalized $35.5 million, $24.3 million and $18.2 million of internal costs in 2003, 2002 and 2001, respectively, directly related to our oil and gas exploration and development efforts.
Provision for Legal Settlements. We have entered into a settlement agreement, effective December 31, 2003, to resolve a legal proceeding brought against us by certain royalty owners. Under the terms of the settlement, we will refund Oklahoma royalty owners $10.5 million, including interest. The refund amount includes $3.6 million relating to marketing fees which we have previously paid into the court and charged to provision for legal settlements ($0.3 million in the first quarter 2003 and $3.3 million in 2002). In the third and fourth quarter 2003, we accrued an additional $6.9 million related to the settlement. A description of the settlement is included in note 4 of notes to consolidated financial statements.
At the beginning of 2002, we had a reserve of approximately $4 million for potential liability associated with a number of cases alleging the cessation of leases in the West Panhandle Field of the Texas Panhandle. During 2002, we reversed approximately $3 million of this accrued liability, and we reversed the remaining $0.8 million in 2003. As of December 31, 2003, there are no outstanding liabilities related to these cases.
Oil and Gas Depreciation, Depletion and Amortization. Depreciation, depletion and amortization of oil and gas properties was $369.5 million, $221.2 million and $172.9 million during 2003, 2002 and 2001, respectively. The average DD&A rate per mcfe, which is a function of capitalized costs, future development costs, and the related underlying reserves in the periods presented, was $1.38 (all domestic), $1.22 (all domestic) and $1.07 ($1.08 in U.S. and $0.90 in Canada) in 2003, 2002 and 2001, respectively. We expect the 2004 DD&A rate to be between $1.50 and $1.55 per mcfe produced. The increase in the average rate from 2001 to 2003 is primarily the result of higher drilling costs and higher costs associated with acquisitions.
Depreciation and Amortization of Other Assets. Depreciation and amortization of other assets was $16.8 million in 2003, compared to $14.0 million in 2002 and $8.7 million in 2001. The increases in 2003 and 2002 were primarily the result of higher depreciation costs on fixed assets related to capital expenditures made in both years. Other property and equipment costs are depreciated on a straight-line basis. Buildings are depreciated over 39 years, drilling rigs are depreciated over 15 years and all other property and equipment are depreciated over the estimated useful lives of the assets, which range from two to fifteen years. To the extent drilling rigs are used to drill our wells, a substantial portion of the depreciation is capitalized in oil and gas properties as exploration or development costs. We expect 2004 depreciation and amortization of other assets to be between $0.07 and $0.09 per mcfe produced.
Interest and Other Income. Interest and other income was $2.8 million, $7.3 million and $2.9 million in 2003, 2002 and 2001, respectively. The 2003 income consisted of $1.0 million of interest income, a $0.4 million loss on our equity investment in Pioneer Drilling Company, a $0.6 million gain on the final settlement of the sale of our Canadian subsidiary, and $1.6 million of miscellaneous income. The 2002 income consisted of $2.9 million in interest income, $2.9 million of interest accrued on our investment in Seven Seas, a $0.5 million gain on the sale of our RAM notes, a $0.3 million loss on our investment in Petroleum Place and $1.3 million of miscellaneous income. The 2001 income consisted of $0.9 million of interest income on our investment in Seven Seas notes and $0.5 million of interest income on our RAM notes.
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Interest Expense. Interest expense increased to $154.4 million in 2003, compared to $112.0 million in 2002 and $98.3 million in 2001. The increase in 2003 is due to a $517.7 million increase in average long-term borrowings in 2003 compared to 2002. The increase in 2002 is due to a $264 million increase in average long-term borrowings in 2002 compared to 2001. In addition to the interest expense reported, we capitalized $13.0 million of interest during 2003, compared to $5.0 million capitalized in 2002, and $4.7 million capitalized in 2001 on significant investments in unproved properties that were not being currently depreciated, depleted or amortized and on which exploration activities were in progress. Interest is capitalized using the weighted average interest rate on our outstanding borrowings. We expect 2004 interest expense to be between $0.45 and $0.50 per mcfe produced.
From time to time, we enter into derivative instruments designed to mitigate our exposure to the volatility in interest rates. For interest rate derivative instruments designated as fair value hedges (in accordance with SFAS 133), changes in fair value of interest rate derivatives are recorded on the consolidated balance sheets as assets (liabilities) and the debts carrying value amount is adjusted by the change in the fair value of the debt subsequent to the initiation of the derivative. Any resulting differences are recorded currently as ineffectiveness in the consolidated statements of operations as an adjustment to interest expense. Included in interest expense in 2003 are a realized gain of $3.9 million related to interest rate derivatives and an unrealized loss on interest rate derivatives of $6.5 million. Included in interest expense in 2002 are a realized gain of $3.4 million related to interest rate derivatives and an unrealized loss on interest rate derivatives of $0.8 million. There were no such gains or losses in 2001. A detailed explanation of our interest rate hedging appears under the caption Hedging ActivitiesInterest Rate Hedging elsewhere in this item 7.
Loss on Investment in Seven Seas. In July 2001, Chesapeake purchased $22.5 million principal amount of 12% senior secured notes due 2004 issued by Seven Seas Petroleum Inc. and detachable seven-year warrants to purchase approximately 12.6 million shares of Seven Seas common stock at an exercise price of approximately $1.78 per share. In the third quarter of 2002, Chesapeake recorded an impairment of $4.8 million representing 100% of the cost allocated to our Seven Seas common stock warrants. During the fourth quarter of 2002, we recorded an additional impairment of $12.4 million to reduce our net investment in the senior secured notes, including accrued interest, to $7.5 million, representing Chesapeakes anticipated share of the net proceeds from the liquidation of Seven Seas assets in bankruptcy. In the third quarter of 2003, we received approximately $5.5 million in proceeds from the sale of its principal assets. Seven Seas reported in October 2003 that it had no source of additional cash flow and only contingent assets remaining, the value of which were highly speculative. Accordingly, in the fourth quarter of 2003, we determined that any remaining assets of Seven Seas would not be adequate for us to realize the remaining investment on our books. At that time, we recorded an impairment of $2.0 million which reduced the carrying value of our investment to zero.
Loss on Repurchases of Debt. During 2003, we purchased and subsequently retired $106.4 million of our 8.5% senior notes due 2012 for a total consideration of $114.9 million, including accrued interest of $1.8 million and $6.7 million of redemption premium. In connection with this repurchase transaction we recorded a pre-tax loss of $20.8 million, consisting of $6.7 million of redemption premium, $1.8 million write-off of unamortized debt issue costs and notes discount, $0.3 million of transaction costs, and a write-off of the call option value of $12.0 million carried as a discount on the 8.5% senior notes based on the hedging relationship between the notes and the swaption. During 2002, we purchased and subsequently retired $107.9 million of our 7.875% senior notes due 2004 for total consideration of $112.9 million, including accrued interest of $1.3 million and $3.7 million of redemption premium partially offset by a $1.7 million gain from interest rate hedging activities associated with the retired debt. During 2001, we purchased or redeemed $500.0 million principal amount of our 9.625% senior notes, $202.3 million principal amount of the 11.125% senior secured notes of Gothic Production Corporation, a Chesapeake subsidiary, and $120.0 million principal amount of our 9.125% senior notes. The purchase and redemption of these notes included payment of aggregate make-whole and redemption premiums of $75.6 million and the write-off of unamortized debt costs and debt issue premiums resulting in a pre-tax loss of $76.7 million.
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Impairments of Investments in Securities. During 2001 we recorded impairments to two equity investments of $10.1 million. The majority of this impairment was related to our investment in RAM Energy, Inc. In March 2001, we issued 1.1 million shares of Chesapeake common stock in exchange for 49.5% of RAMs outstanding common stock. Our shares were valued at $8.854 each, or $9.9 million in total. During 2001, we recorded our equity in RAMs net losses, which had the effect of reducing our carrying value in these securities to $8.6 million. In December 2001, we sold the RAM shares for minimal consideration. In addition, we reduced the carrying value of our $2.0 million investment in an Internet-based oil and gas business by $1.5 million to $0.5 million.
Gain on Sale of Canadian Subsidiary. In October 2001, we sold our Canadian subsidiary, which had oil and gas operations primarily in northeast British Columbia, for approximately $143.0 million. Under full-cost accounting, our investment in these Canadian oil and gas properties was treated as a separate cost center for accounting purposes. As a result of the sale of this cost center, any gain or loss on the disposition was required to be recognized in current earnings. In the fourth quarter of 2001, we recorded a gain on sale of our Canadian subsidiary of $27.0 million.
Provision (Benefit) for Income Taxes. Chesapeake recorded income tax expense of $191.8 million in 2003, compared to income tax expense of $26.9 million in 2002 and income tax expense of $144.3 million in 2001. All income tax expense for 2003 and 2002 was related to our domestic operations. Income tax expense for 2001 was comprised of $127.6 million related to our domestic operations, $7.1 million related to our Canadian operations and $9.6 million related to the sale of our Canadian subsidiary. As of December 31, 2001, we determined that it was more likely than not that $2.4 million of the deferred tax assets related to Louisiana net operating losses will not be realized and we recorded a valuation allowance equal to such amounts. During 2003, we determined that it was more likely than not that an additional $4.4 million of the deferred tax assets related to Louisiana net operating losses will not be realized and we recorded an additional valuation allowance equal to such amounts.
Cumulative Effect of Accounting Change. Effective January 1, 2003, Chesapeake adopted SFAS No. 143, Accounting For Asset Retirement Obligations. Upon adoption of SFAS 143, we recorded the discounted fair value of our expected future obligations of $30.5 million, a cumulative effect of the change in accounting principle as an increase to earnings of $2.4 million (net of income taxes) and an increase in net oil and gas properties of $34.3 million.
Application of Critical Accounting Policies
Readers of this document and users of the information contained in it should be aware of how certain events may impact our financial results based on the accounting policies in place. The four policies we consider to be the most significant are discussed below. The companys management has discussed each critical accounting policy with the audit committee of the companys board of directors.
The selection and application of accounting policies is an important process that changes as our business changes and as accounting rules are developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules and the use of judgment to the specific set of circumstances existing in our business.
Hedging. From time to time, Chesapeake uses commodity price and financial risk management instruments to mitigate our exposure to price fluctuations in oil and natural gas and interest rates. Recognized gains and losses on derivative contracts are reported as a component of the related transaction. Results of oil and gas derivative transactions are reflected in oil and gas sales, and results of interest rate hedging transactions are reflected in interest expense. The changes in the fair value of derivative instruments not qualifying for designation as either cash flow or fair value hedges that occur prior to maturity are reported currently in the consolidated statement of operations as unrealized gains (losses) within oil and gas sales or interest expense.
Effective January 1, 2001, we adopted Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities. This statement establishes accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be
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recorded at fair value and included in the consolidated balance sheet as assets or liabilities. The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. For derivative instruments designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Any change in the fair value resulting from ineffectiveness, as defined by SFAS 133, is recognized immediately in oil and gas sales. For derivative instruments designated as fair value hedges (in accordance with SFAS 133), changes in fair value, as well as the offsetting changes in the estimated fair value of the hedged item attributable to the hedged risk, are recognized currently in earnings. Differences between the changes in the fair values of the hedged item and the derivative instrument, if any, represent gains or losses on ineffectiveness and are reflected currently in interest expense. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. Changes in fair value of contracts that do not qualify as hedges or are not designated as hedges are also recognized currently in earnings. See Hedging Activities below and Item 7AQuantitative and Qualitative Disclosures about Market Risk for additional information regarding our hedging activities.
One of the primary factors that can have an impact on our results of operations is the method used to value our derivatives. We have established the fair value of all derivative instruments using estimates determined by our counterparties and subsequently evaluated internally using established index prices and other sources. These values are based upon, among other things, futures prices, volatility, time to maturity and credit risk. The values we report in our financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond our control.
Another factor that can impact our results of operations each period is our ability to estimate the level of correlation between future changes in the fair value of the hedge instruments and the transactions being hedged, both at the inception and on an ongoing basis. This correlation is complicated since energy commodity prices, the primary risk we hedge, have quality and location differences that can be difficult to hedge effectively. The factors underlying our estimates of fair value and our assessment of correlation of our hedging derivatives are impacted by actual results and changes in conditions that affect these factors, many of which are beyond our control.
Due to the volatility of oil and natural gas prices and, to a lesser extent, interest rates, the companys financial condition and results of operations can be significantly impacted by changes in the market value of our derivative instruments. As of December 31, 2003, 2002 and 2001, the net market value of our derivatives was a liability of $75.4 million, a liability of $44.7 million and an asset of $157.3 million, respectively. With respect to our derivatives held as of December 31, 2003, an increase or decrease in natural gas prices of $0.25 per mmbtu would decrease or increase the estimated fair value of our derivatives by approximately $86 million. An increase or decrease in crude oil prices of $1.00 per barrel would decrease or increase the estimated fair value of our derivatives by approximately $5 million.
Oil and Gas Properties. The accounting for our business is subject to special accounting rules that are unique to the oil and gas industry. There are two allowable methods of accounting for oil and gas business activities: the successful efforts method and the full-cost method. Chesapeake follows the full-cost method of accounting under which all costs associated with property acquisition, exploration and development activities are capitalized. We also capitalize internal costs that can be directly identified with our acquisition, exploration and development activities and do not include any costs related to production, general corporate overhead or similar activities. Under the successful efforts method, geological and geophysical costs and costs of carrying and retaining undeveloped properties are charged to expense as incurred. Costs of drilling exploratory wells that do not result in proved reserves are charged to expense. Depreciation, depletion, amortization and impairment of oil and gas properties are generally calculated on a well by well or lease or field basis versus the aggregated full cost pool basis. Additionally, gain or loss is generally recognized on all sales of oil and gas properties under the
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successful efforts method. As a result, our financial statements will differ from companies that apply the successful efforts method since we will generally reflect a higher level of capitalized costs as well as a higher oil and gas depreciation, depletion and amortization rate.
Capitalized costs are amortized on a composite unit-of-production method based on proved oil and gas reserves. As of December 31, 2003, approximately 74% of our present value (discounted at 10%) of estimated future net revenues of proved reserves was evaluated by independent petroleum engineers, with the balance evaluated by our internal reservoir engineers. In addition, our internal engineers reevaluate our reserves on a quarterly basis. Depreciation, depletion and amortization expense is based on the amount of estimated reserves. If we maintain the same level of production year over year, the depreciation, depletion and amortization expense may be significantly different if our estimate of remaining reserves changes significantly.
Proceeds from the sale of properties are accounted for as reductions of capitalized costs unless such sales involve a significant change in the relationship between costs and the value of proved reserves or the underlying value of unproved properties, in which case a gain or loss is recognized. No income is recognized in connection with contractual services provided by Chesapeake on properties in which we hold an economic interest.
The costs of unproved properties are excluded from amortization until the properties are evaluated. We review all of our unevaluated properties quarterly to determine whether or not and to what extent proved reserves have been assigned to the properties, and otherwise if impairment has occurred. Unevaluated properties are grouped by major producing area where individual property costs are not significant and are assessed individually when individual costs are significant.
We review the carrying value of our oil and gas properties under the full-cost accounting rules of the Securities and Exchange Commission on a quarterly basis. This quarterly review is referred to as a ceiling test. Under the ceiling test, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed an amount equal to the sum of the present value of estimated future net revenues less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. The two primary factors impacting this test are reserve levels and current prices, and their associated impact on the present value of estimated future net revenues. Revisions to estimates of natural gas and oil reserves and/or an increase or decrease in prices can have a material impact on the present value of estimated future net revenues. The process of estimating natural gas and oil reserves is very complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various properties increases the likelihood of significant changes in these estimates. In addition, the prices of natural gas and oil are volatile and change from period to period. Price changes directly impact the estimated revenues from our properties and the associated present value of future net revenues. Such changes also impact the economic life of our properties and thereby affect the quantity of reserves that can be assigned to a property.
The volatility of oil and natural gas prices and the impact of revisions to reserve estimates can have a significant impact on the companys financial condition and results of operations. Our oil and gas depreciation, depletion and amortization (DD&A) rates have fluctuated between $0.75 per mcfe in 2000 to $1.38 per mcfe in 2003 reflecting the impact of changes in prices and finding costs during these periods. As of December 31, 2003, a decrease in natural gas prices of $0.10 per mcf and a decrease in oil prices of $1.00 per barrel would reduce the companys estimated proved reserves of 3,169 bcfe by 2.7 bcfe and 1.0 bcfe, respectively, and would also reduce the companys present value of estimated future net revenues by approximately $144.9 million and $25.0 million, respectively.
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Statement of Financial Accounting Standards No. 141, Business Combinations and Statement of Financial Accounting Standards No. 142, Goodwill and Intangible Assets were issued by the Financial Accounting Standards Board in June 2001 and became effective for us on July 1, 2001 and January 1, 2002, respectively. SFAS 141 requires all business combinations initiated after June 30, 2001 to be accounted for using the purchase method. Additionally, SFAS 141 requires companies to disaggregate and report separately from goodwill certain intangible assets. SFAS 142 establishes new guidelines for accounting for goodwill and other intangible assets. Under SFAS 142, goodwill and certain other intangible assets are not amortized, but rather are reviewed annually for impairment.
The Emerging Issues Task Forces (EITF) is considering two issues related to the reporting of oil and gas mineral rights. Issue No. 03-S, Application of SFAS No. 142, Goodwill and Other Intangible Assets to Oil and Gas Companies, considers whether oil and gas drilling rights are subject to the classification and disclosure provisions of SFAS 142 if they are intangible assets.
Chesapeake classifies the cost of oil and gas mineral rights as property and equipment and believes that this is consistent with oil and gas accounting and industry practice. If the EITF determines that oil and gas mineral rights are intangible assets and are subject to the applicable classification and disclosure provisions of SFAS 142, we estimate that $227.3 million and $72.5 million would be classified on our consolidated balance sheets as intangible undeveloped leasehold and $1.4 billion and $532.8 million would be classified as intangible developed leasehold as of December 31, 2003 and 2002, respectively. These amounts are net of accumulated DD&A. There would be no effect on the consolidated statements of operations or cash flows as the intangible assets related to oil and gas mineral rights would continue to be amortized under the full cost method of accounting.
We will continue to classify our oil and gas mineral rights held under lease and other contractual rights representing the right to extract such reserves as tangible oil and gas properties until further guidance is provided.
Income Taxes. As part of the process of preparing the consolidated financial statements, we are required to estimate the federal and state income taxes in each of the jurisdictions in which Chesapeake operates. This process involves estimating the actual current tax exposure together with assessing temporary differences resulting from differing treatment of items, such as derivative instruments, depreciation, depletion and amortization, and certain accrued liabilities for tax and accounting purposes. These differences and the net operating loss carryforwards result in deferred tax assets and liabilities, which are included in our consolidated balance sheet. We must then assess, using all available positive and negative evidence, the likelihood that the deferred tax assets will be recovered from future taxable income. If we believe that recovery is not likely, we must establish a valuation allowance. To the extent Chesapeake establishes a valuation allowance or increases or decreases this allowance in a period, we must include an expense or reduction of expense within the tax provisions in the consolidated statement of operations.
Under SFAS No. 109, Accounting for Income Taxes, an enterprise must use judgment in considering the relative impact of negative and positive evidence. The weight given to the potential effect of negative and positive evidence should be commensurate with the extent to which it can be objectively verified. The more negative evidence that exists (a) the more positive evidence is necessary and (b) the more difficult it is to support a conclusion that a valuation allowance is not needed for some portion or all of the deferred tax asset. Among the more significant types of evidence that we consider are:
| taxable income projections in future years, |
| whether the carryforward period is so brief that it would limit realization of tax benefits, |
| future sales and operating cost projections that will produce more than enough taxable income to realize the deferred tax asset based on existing sales prices and cost structures, and |
| our earnings history exclusive of the loss that created the future deductible amount coupled with evidence indicating that the loss is an aberration rather than a continuing condition. |
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If (a) natural gas and oil prices were to decrease significantly below present levels (and if such decreases were considered other than temporary), (b) exploration, drilling and operating costs were to increase significantly beyond current levels, or (c) we were confronted with any other significantly negative evidence pertaining to our ability to realize our NOL carryforwards prior to their expiration, we may be required to provide a valuation allowance against our deferred tax asset. As of December 31, 2003 we have a deferred tax asset of $194.9 million, of which only $6.8 million had an associated valuation allowance.
Accounting for Business Combinations. Our business has grown substantially through acquisitions and our business strategy is to continue to pursue acquisitions as opportunities arise. Prior to the issuance of SFAS 141, Accounting for Business Combinations in 2001, we applied the guidance provided by Accounting Principles Board Opinion (APB) No. 16, and its interpretations, as well as various other authoritative literature and interpretations that address issues encountered in accounting for business combinations. We have accounted for all of our business combinations using the purchase method, which is the only method permitted under SFAS 141. The accounting for business combinations is complicated and involves the use of significant judgment.
Under the purchase method of accounting, a business combination is accounted for at a purchase price based upon the fair value of the consideration given, whether in the form of cash, assets, stock or the assumption of liabilities. The assets and liabilities acquired are measured at their fair values, and the purchase price is allocated to the assets and liabilities based upon these fair values. The excess of the cost of an acquired entity, if any, over the net of the amounts assigned to assets acquired and liabilities assumed is recognized as goodwill. The excess of the fair value of assets acquired and liabilities assumed over the cost of an acquired entity, if any, is allocated as a pro rata reduction of the amounts that otherwise would have been assigned to certain of the acquired assets.
Determining the fair values of the assets and liabilities acquired involves the use of judgment, since some of the assets and liabilities acquired do not have fair values that are readily determinable. Different techniques may be used to determine fair values, including market prices, where available, appraisals, comparisons to transactions for similar assets and liabilities and present value of estimated future cash flows, among others. Since these estimates involve the use of significant judgment, they can change as new information becomes available.
Each of the business combinations completed during the past five years were of small-to-medium sized exploration and production companies with oil and gas interests primarily in the Mid-Continent. We believe that the consideration we have paid to acquire these companies has represented the fair value of the assets and liabilities acquired at the time of acquisition. Consequently, we have not recognized any goodwill from any of our business combinations, nor do we expect to recognize any goodwill from similar business combinations that we may complete in the future.
Disclosures About Effects of Transactions with Related Parties
As of December 31, 2003, we had accrued accounts receivable from our chief executive officer and chief operating officer of $0.3 million and $2.6 million, respectively, representing billings for December 2003 which were paid in January 2004. Since Chesapeake was founded in 1989, our CEO and COO have acquired small working interests in certain of our oil and gas properties by participating in our drilling activities. Joint interest billing accounts of the CEO and COO are settled in cash. Under their employment agreements, the CEO and COO are permitted to participate in all, or none, of the wells drilled by or on behalf of Chesapeake during each calendar quarter, but they are not allowed to participate only in selected wells. A participation election is required to be received by the Compensation Committee of Chesapeakes board of directors 30 days prior to the start of a quarter. Their participation is permitted only under the terms outlined in their employment agreements, which, among other things, limit their individual participation to a maximum working interest of 2.5% in a well and prohibits participation in situations where Chesapeakes working interest would be reduced below 12.5% as a result of their participation.
45
In October 2001, we sold Chesapeake Canada Corporation, a wholly-owned subsidiary, for net proceeds of approximately $143.0 million. Our CEO and COO each received $2.0 million related to their fractional ownership interest in these Canadian assets, which they acquired and paid for pursuant to the terms of their employment agreements. The portion of the proceeds allocated to our CEO and COO was based upon the estimated fair values of the assets sold as determined by management and the independent members of our board of directors using a methodology similar to that used by Chesapeake for acquisitions of assets from disinterested third parties.
During 2003, 2002 and 2001, we paid legal fees of $2,123,000, $600,000, and $391,000, respectively, for legal services provided by a law firm of which a director is a member.
Recently Issued Accounting Standards
During 2002 and 2003, the Financial Accounting Standards Board issued the following Statements of Financial Accounting Standards which were reviewed by Chesapeake to determine the potential impact on our financial statements upon adoption.
In July 2002, the FASB issued SFAS No. 146, Accounting For Costs Associated with Exit or Disposal Activities. SFAS 146 is effective for exit or disposal activities initiated after December 31, 2002. We adopted this standard during the quarter ended March 31, 2003 and it did not have any impact on our financial position or results of operations.
In November 2002, the FASB issued FASB Interpretation, or FIN 45 Guarantors Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantee of Indebtedness of Others. FIN 45 requires that upon issuance of a guarantee, the guarantor must recognize a liability for the fair value of the obligation it assumes under that guarantee. FIN 45s provisions for initial recognition and measurement should be applied on a prospective basis to guarantees issued or modified after December 31, 2002. The guarantors previous accounting for guarantees that were issued before the date of FIN 45s initial application may not be revised or restated to reflect the effect of the recognition and measurement provisions of the Interpretation. The disclosure requirements are effective for financial statements of both interim and annual periods that end after December 15, 2002. Chesapeake is not a guarantor under any significant guarantees and thus this interpretation is not expected to have a significant effect on the companys financial position or results of operations.
In January 2003, the FASB issued Financial Interpretation No. 46, Consolidation of Variable Interest Entities An Interpretation of ARB No. 51. FIN 46 is an interpretation of Accounting Research Bulletin 51, Consolidated Financial Statements, and addresses consolidation of variable interest entities (VIEs) by business enterprises. The primary objective of FIN 46 is to provide guidance on the identification and financial reporting of entities over which control is achieved through means other than voting rights; such entities are known as VIEs. FIN 46 requires an enterprise to consolidate a VIE if that enterprise has a variable interest that will absorb a majority of the entitys expected losses, receive a majority of the entitys expected residual returns, or both. An enterprise shall consider the rights and obligations conveyed by its variable interest in making this determination. At December 31, 2003, Chesapeake did not have any entities that would qualify for consolidation in accordance with the provisions of FIN 46, as amended. Therefore, the adoption of FIN 46, as amended, did not have an impact on our consolidated financial statements.
In March 2003, the FASB issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. SFAS 149 is effective for contracts entered into or modified after June 30, 2003. This statement amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts (collectively referred to as derivatives) and for hedging activities under SFAS 133, Accounting for Derivative Instruments and Hedging Activities. We adopted this standard during the quarter ended September 30, 2003 and it did not have any impact on our financial position or results of operations.
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In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity. SFAS 150 is effective for financial instruments entered into or modified after May 31, 2003 and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. This statement establishes new standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. SFAS 150 requires that an issuer classify a financial instrument that is within the scope of this statement as a liability because the financial instrument embodies an obligation of the issuer. This statement applies to certain forms of mandatorily redeemable financial instruments including certain types of preferred stock, written put options and forward contracts. Adoption of this standard did not have any significant impact on our financial position or results of operations.
In December 2003, the Securities and Exchange Commission issued Staff Accounting Bulletin 104, Revenue Recognition. SAB 104 revises or rescinds certain guidance included in previously issued staff accounting bulletins in order to make this interpretive guidance consistent with current authoritative accounting and auditing guidance and SEC rules and regulations relating to revenue recognition. This bulletin was effective immediately upon issuance. Chesapeakes current revenue recognition policies comply with SAB 104.
Forward-Looking Statements
This report includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements give our current expectations or forecasts of future events. They include statements regarding oil and gas reserve estimates, planned capital expenditures, the drilling of oil and gas wells and future acquisitions, expected oil and gas production, cash flow and anticipated liquidity, business strategy and other plans and objectives for future operations, expected future expenses and utilization of net operating loss carryforwards. Statements concerning the fair values of derivative contracts and their estimated contribution to our future results of operations are based upon market information as of a specific date. These market prices are subject to significant volatility.
Although we believe the expectations and forecasts reflected in these and other forward-looking statements are reasonable, we can give no assurance they will prove to have been correct. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. Factors that could cause actual results to differ materially from expected results are described under Risk Factors in Item 1 and include:
| the volatility of oil and gas prices, |
| our substantial indebtedness, |
| the strength and financial resources of our competitors, |
| the cost and availability of drilling and production services, |
| our commodity price risk management activities, including counterparty contract performance risk, |
| uncertainties inherent in estimating quantities of oil and gas reserves, projecting future rates of production and the timing of development expenditures, |
| our ability to replace reserves, |
| the availability of capital, |
| uncertainties in evaluating oil and gas reserves of acquired properties and associated potential liabilities, |
| declines in the values of our oil and gas properties resulting in ceiling test write-downs, |
| drilling and operating risks, |
| our ability to generate future taxable income sufficient to utilize our NOLs before expiration, |
| future ownership changes which could result in additional limitations to our NOLs, |
47
| adverse effects of governmental and environmental regulation, |
| losses possible from pending or future litigation, and |
| the loss of officers or key employees. |
We caution you not to place undue reliance on these forward-looking statements, which speak only as of the date of this report, and we undertake no obligation to update this information. We urge you to carefully review and consider the disclosures made in this and our other reports filed with the Securities and Exchange Commission that attempt to advise interested parties of the risks and factors that may affect our business.
ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk
Oil and Gas Hedging Activities
Our results of operations and operating cash flows are impacted by changes in market prices for oil and gas. To mitigate a portion of the exposure to adverse market changes, we have entered into various derivative instruments. As of December 31, 2003, our oil and gas derivative instruments were comprised of swaps, cap-swaps, basis protection swaps and call options. These instruments allow us to predict with greater certainty the effective oil and gas prices to be received for our hedged production. Although derivatives often fail to achieve 100% effectiveness for accounting purposes, we believe our derivative instruments continue to be highly effective in achieving the risk management objectives for which they were intended.
| For swap instruments, we receive a fixed price for the hedged commodity and pay a floating market price, as defined in each instrument, to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty. |
| For cap-swaps, Chesapeake receives a fixed price and pays a floating market price. The fixed price received by Chesapeake includes a premium in exchange for a cap limiting the counterpartys exposure. In other words, there is no limit to Chesapeakes exposure but there is a limit to the downside exposure of the counterparty. Because this derivative includes a written put option (i.e., the cap), cap-swaps do not qualify for designation as cash flow hedges (in accordance with SFAS 133) since the combination of the hedged item and the written put option do not provide as much potential for favorable cash flows as exposure to unfavorable cash flows. |
| Basis protection swaps are arrangements that guarantee a price differential of oil or gas from a specified delivery point. Chesapeake receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract. |
| For call options, Chesapeake receives a cash premium from the counterparty in exchange for the sale of a call option. If the floating price exceeds the fixed price of the call option, then Chesapeake pays the counterparty such excess. If the floating price settles below the fixed price of the call option, no payment is due from Chesapeake. |
Chesapeake enters into counter-swaps from time to time for the purpose of locking in the value of a swap. Under the counter-swap, Chesapeake receives a floating price for the hedged commodity and pays a fixed price to the counterparty. The counter-swap is 100% effective in locking in the value of a swap since subsequent changes in the market value of the swap are entirely offset by subsequent changes in the market value of the counter-swap. We refer to this locked-in value as a locked swap. At the time Chesapeake enters into a counter-swap, Chesapeake removes the original swaps designation as a cash flow hedge and classifies the original swap as a non-qualifying hedge under SFAS 133. The reason for this new designation is that collectively the swap and the counter-swap no longer hedge the exposure to variability in expected future cash flows. Instead, the swap and counter-swap effectively lock in a specific gain (or loss) that will be unaffected by subsequent variability in oil and gas prices. Any locked-in gain or loss is recorded in accumulated other comprehensive income and reclassified to oil and gas sales in the month of related production.
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In accordance with FASB Interpretation No. 39, Chesapeake nets the value of its derivative arrangements with the same counterparty in the accompanying consolidated balance sheets, to the extent that a legal right of set off exists.
Gains or losses from derivative transactions are reflected as adjustments to oil and gas sales on the consolidated statements of operations. Pursuant to SFAS 133, certain derivatives do not qualify for designation as cash flow hedges. Changes in the fair value of these non-qualifying derivatives that occur prior to their maturity (i.e., temporary fluctuations in value) are reported currently in the consolidated statements of operations as unrealized gains (losses) within oil and gas sales. Unrealized gains (losses) included in oil and gas sales in 2003, 2002 and 2001 were $10.5 million, $(87.3) million and $84.8 million, respectively.
Following provisions of SFAS 133, changes in the fair value of derivative instruments designated as cash flow hedges, to the extent they are effective in offsetting cash flows attributable to the hedged risk, are recorded in other comprehensive income until the hedged item is recognized in earnings. Any change in fair value resulting from ineffectiveness is recognized currently in oil and gas sales. We recorded a gain (loss) on ineffectiveness of ($9.2) million, ($3.6) million and $2.5 million in 2003, 2002 and 2001, respectively.
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As of December 31, 2003, we had the following open oil and gas derivative instruments designed to hedge a portion of our oil and gas production for periods after December 2003:
Volume |
Weighted Average Strike |
Weighted Average Put Strike Price |
Weighted Average Call Strike |
Weighted Average Differential |
SFAS 133 Hedge |
Premiums Received |
Fair Value at December 31, 2003 ($ in thousands) |
|||||||||||||
Natural Gas (mmbtu): |
||||||||||||||||||||
Swaps: |
||||||||||||||||||||
2004 |
171,120,000 | 5.31 | | | | Yes | $ | | $ | (40,922 | ) | |||||||||
2005 |
45,550,000 | 4.82 | | | | Yes | | (8,507 | ) | |||||||||||
2006 |
25,550,000 | 4.74 | | | | Yes | | 678 | ||||||||||||
2007 |
25,550,000 | 4.76 | | | | Yes | | 3,432 | ||||||||||||
Basis Protection |
||||||||||||||||||||
2004 |
157,380,000 | | | | (0.17 | ) | No | | 18,390 | |||||||||||
2005 |
109,500,000 | | | | (0.16 | ) | No | | 11,042 | |||||||||||
2006 |
47,450,000 | | | | (0.16 | ) | No | | 4,123 | |||||||||||
2007 |
63,875,000 | | | | (0.17 | ) | No | | 5,280 | |||||||||||
2008 |
64,050,000 | | | | (0.17 | ) | No | | 4,613 | |||||||||||
2009 |
36,500,000 | | | | (0.16 | ) | No | | 2,757 | |||||||||||
Cap-Swaps: |
||||||||||||||||||||
2004 |
29,320,000 | 5.31 | 3.75 | | | No | | (8,475 | ) | |||||||||||
2005 |
36,500,000 | 5.31 | 3.79 | | | No | | (9,015 | ) | |||||||||||
2006 |
7,300,000 | 5.36 | 3.75 | | | No | | (1,118 | ) | |||||||||||
Call Options: |
||||||||||||||||||||
2004 |
60,760,000 | | | 6.30 | | No | 16,766 | (17,876 | ) | |||||||||||
Locked-Swaps: |
||||||||||||||||||||
2004 |
| | | | | No | | 2,302 | ||||||||||||
Total Gas |
16,766 | (33,296 | ) | |||||||||||||||||
Oil (bbls): |
||||||||||||||||||||
Cap-Swaps: |
||||||||||||||||||||
2004 |
4,516,000 | 28.68 | 21.76 | | | No | | (11,692 | ) | |||||||||||
Total Oil |
| (11,692 | ) | |||||||||||||||||
Total Gas and Oil |
$ | 16,766 | $ | (44,988 | ) | |||||||||||||||
We have established the fair value of all derivative instruments using estimates of fair value reported by our counterparties and subsequently evaluated internally using established index prices and other sources. The actual contribution to our future results of operations will be based on the market prices at the time of settlement and may be more or less than the fair value estimates used at December 31, 2003.
Based upon the market prices at December 31, 2003, we expect to transfer approximately $17.6 million of loss included in the balance in accumulated other comprehensive income to earnings during the next 12 months when the transactions actually occur. All transactions hedged as of December 31, 2003 are expected to mature by December 31, 2007, with the exception of the basis protection swaps which extend through 2009.
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Additional information concerning the fair value of our oil and gas derivative instruments is as follows:
December 31, |
||||||||||||
2003 |
2002 |
2001 |
||||||||||
($ in thousands) | ||||||||||||
Fair value of contracts outstanding, beginning of year |
$ | (14,533 | ) | $ | 157,309 | $ | (89,288 | ) | ||||
Change in fair value of contracts during the period |
(31,078 | ) | (52,419 | ) | 351,989 | |||||||
Contracts realized or otherwise settled during the period |
17,389 | (96,046 | ) | (105,392 | ) | |||||||
Fair value of new contracts when entered into during the period |
(16,766 | ) | (45,603 | ) | | |||||||
Fair value of contracts when closed during the period |
| 22,226 | | |||||||||
Fair value of contracts outstanding, end of year |
$ | (44,988 | ) | $ | (14,533 | ) | $ | 157,309 | ||||
The change in the fair value of our derivative instruments since January 1, 2003 resulted from an increase in market prices for natural gas and crude oil relative to the hedged price. Derivative instruments reflected as current in the consolidated balance sheet represent the estimated fair value of derivative instrument settlements scheduled to occur over the subsequent twelve-month period based on market prices for oil and gas as of the consolidated balance sheet date. The derivative settlement amounts are not due and payable until the month in which the related underlying hedged transaction occurs.
Interest Rate Risk
The table below presents principal cash flows and related weighted average interest rates by expected maturity dates. The fair value of the fixed-rate long-term debt has been estimated based on quoted market prices.
Years of Maturity |
|||||||||||||||||||||||||||||
2004 |
2005 |
2006 |
2007 |
2008 |
Thereafter |
Total |
Fair Value |
||||||||||||||||||||||
($ in millions) | |||||||||||||||||||||||||||||
Liabilities: |
|||||||||||||||||||||||||||||
Long-term debt, including current portion fixed rate |
$ | 42.1 | $ | | $ | | $ | | $ | 209.8 | $ | 1,833.1 | $ | 2,085.0 | (1) | $ | 2,279.5 | ||||||||||||
Average interest rate |
7.9 | % | | | | 8.4 | % | 8.0 | % | 8.0 | % | 8.0 | % |
(1) | This amount does not include the discount included in long-term debt of $27.0 million, the effect of interest rate swaps of $0.1 million and the effect of the swaption of ($ 0.5) million. |
Changes in interest rates affect the amount of interest we earn on our cash, cash equivalents and short-term investments and the interest rate we pay on borrowings under our revolving credit facility. All of our other long-term indebtedness is fixed rate and therefore does not expose us to the risk of earnings or cash flow loss due to changes in market interest rates. However, changes in interest rates do affect the fair value of our debt.
Interest Rate Hedging
We also utilize hedging strategies to manage the exposure our fixed-rate senior notes have to interest rate changes. By entering into interest rate swaps, we convert a portion of our fixed rate debt to floating rate debt. To the extent the interest rate swaps have been designated as fair value hedges, changes in the fair value of the derivative instrument and the corresponding debt are reflected as adjustments to interest expense in the corresponding months covered by the derivative agreement.
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The following describes interest rate swaps entered into during 2002 and 2003, all of which were terminated prior to contractual maturity, for cash settlements ($ in thousands):
Date Initiated |
Fair Value at December 31, 2003 |
Date Closed |
Cash Settlement Received |
Gains Recognized in 2002 |
Gains Recognized in 2003 |
Gains to be Recognized in 2004 | ||||||||||||
March 2002(a) |
$ | | July 2002 | $ | 7,500 | $ | 6,778 | (c) | $ | 599 | $ | 123 | ||||||
June 2002 (b) |
| July 2002 | 1,130 | 1,130 | | | ||||||||||||
August 2003 (b) |
870 | January 2004 | 940 | | 870 | 70 | ||||||||||||
August 2003(b) |
1,292 | January 2004 | 1,370 | | 1,292 | 78 |
(a) | This instrument was designated as a fair value hedge with changes in the fair value recorded as an adjustment to the debt. Upon termination of the hedging relationship, the previously recorded changes in the fair value of the debt are amortized to earnings over the term of the debt. |
(b) | These instruments were not designated as fair value hedges; therefore, changes in the fair value were recorded as adjustments to interest expense. |
(c) | Of this amount, $1.7 million was recognized as a reduction to the loss on repurchases of debt upon retirement of 7.875% notes. |
In April 2002, Chesapeake entered into a swaption with an unrelated counterparty with respect to its 8.5% senior notes due 2012. The notional amount of the swaption was $142.7 million, which was the principal amount then outstanding under the 8.5% senior notes. The 8.5% senior notes included a call option whereby Chesapeake may redeem the debt at declining redemption prices beginning in March 2004. Under the swaption, the counterparty received the option to elect whether or not to enter into an interest rate swap with Chesapeake in March 2004, and Chesapeake received $7.8 million. The interest rate swap, if executed by the counterparty, requires Chesapeake to pay a fixed rate of 8.5% while the counterparty pays Chesapeake a floating rate of 6 month LIBOR plus 0.75%. Additionally, if the counterparty elects to enter into the interest rate swap, it may also elect to force Chesapeake to settle the transaction at the then current value of the interest rate swap.
According to SFAS 133, a fair value hedge relationship exists between the embedded call option in the 8.5% senior notes and the swaption. The fair value of the swaption is recorded on the consolidated balance sheets as a liability, and the carrying amount of the debt is adjusted by the change in the fair value of the call option subsequent to the initiation of the swaption. Any resulting differences are recorded currently as ineffectiveness in the consolidated statements of operations as an adjustment to interest expense.
During the third quarter 2003, we exchanged and subsequently retired $32.0 million of our 8.5% senior notes. The exchange of debt was treated as a modification rather than an extinguishment. Accordingly, the adjustment to the carrying value of the debt of $3.3 million related to the application of hedge accounting was reflected as a discount on the notes issued in the exchange transaction and will be amortized to interest expense using the effective interest method. During the fourth quarter 2003, we purchased and subsequently retired $106.4 million of the remaining $110.7 million of 8.5% senior notes pursuant to a tender offer and recorded a $12.0 million loss related to the removal of the fair value designation of the corresponding amount of the swaption. Temporary fluctuations in the fair value of the portion of the swaption no longer designated as a fair value hedge are recorded as adjustments to interest expense. We recorded a $3.3 million unrealized loss in interest expense during 2003 due to a decline in the fair value of the portion of the swaption no longer designated as a fair value hedge.
As of December 31, 2003, the remaining notional amount of the swaption designated as a fair value hedge was $4.3 million. We have recorded an adjustment to the carrying amount of the debt of $0.5 million which represents the temporary fluctuations in the fair value of the call option included in the $4.3 million principal amount of 8.5% senior notes. Since the inception of the swaption, we have recorded a change in the fair market
52
value of the swaption from a $7.8 million liability to a $32.6 million liability, an increase of $24.8 million. We have recorded as additional interest expense $5.6 million to reflect ineffectiveness after giving effect to the removal of the designation of a portion of the swaption as a fair value hedge under SFAS 133 as described previously.
On February 27, 2004, Chesapeake and the counterparty agreed to extend the counterpartys right to require Chesapeake to settle the transaction on March 15, 2004 to April 15, 2004. On March 10, 2004, the counterparty exercised its option to enter into the interest rate swap effective March 15, 2004. On April 15, 2004 and each succeeding March 15, the counterparty may elect to terminate the swap and cause it to be settled at the then current value of the interest rate swap. We may elect to terminate the swap and cause it to be settled at the then current value of the interest rate swap at any time during the term of the swap. Cash payments related to the interest rate swap, if initiated, or as a result of cash settlement at termination, will be recorded as adjustments to interest expense.
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ITEM 8. Financial Statements and Supplementary Data
CHESAPEAKE ENERGY CORPORATION
Page | ||
Consolidated Financial Statements: |
||
55 | ||
56 | ||
Consolidated Statements of Operations for the Years Ended December 31, 2003, 2002 and 2001 |
57 | |
Consolidated Statements of Cash Flows for the Years Ended December 31, 2003, 2002 and 2001 |
58 | |
Consolidated Statements of Stockholders Equity for the Years Ended December 31, 2003, 2002 and 2001 |
60 | |
61 | ||
62 | ||
Financial Statement Schedules: |
||
110 |
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REPORT OF INDEPENDENT AUDITORS
To the Board of Directors and Shareholders
of Chesapeake Energy Corporation
In our opinion, the consolidated financial statements listed in the accompanying index appearing under Item 8 of the Form 10-K present fairly, in all material respects, the financial position of Chesapeake Energy Corporation and its subsidiaries (the Company) at December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule also listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Companys management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these financial statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 1 to the consolidated financial statements, in 2001 the Company changed its method of accounting for its hedging activities as a result of adopting the provisions of Statement of Financial Accounting Standards No. 133 Accounting for Derivative Instruments and Hedging Activities.
As discussed in Note 12 to the consolidated financial statements, effective January 1, 2003, the Company changed the manner in which it accounts for asset retirement obligations.
PricewaterhouseCoopers LLP
Oklahoma City, Oklahoma
February 29, 2004
55
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
December 31, |
||||||||
2003 |
2002 |
|||||||
($ in thousands) | ||||||||
ASSETS | ||||||||
CURRENT ASSETS: |
||||||||
Cash and cash equivalents |
$ | 40,581 | $ | 247,637 | ||||
Restricted cash |
| 82 | ||||||
Accounts receivable: |
||||||||
Oil and gas sales |
173,792 | 109,246 | ||||||
Joint interest, net of allowances of $2,669,000 and $1,433,000, respectively |
37,789 | 22,760 | ||||||
Short-term derivatives |
1,777 | 16,498 | ||||||
Related parties |
2,983 | 2,155 | ||||||
Other |
26,830 | 13,471 | ||||||
Deferred income tax asset |
36,705 | 8,109 | ||||||
Short-term derivative instruments |
2,690 | | ||||||
Inventory and other |
19,257 | 15,359 | ||||||
Total Current Assets |
342,404 | 435,317 | ||||||
PROPERTY AND EQUIPMENT: |
||||||||
Oil and gas properties, at cost based on full-cost accounting: |
||||||||
Evaluated oil and gas properties |
6,221,576 | 4,334,833 | ||||||
Unevaluated properties |
227,331 | 72,506 | ||||||
Less: accumulated depreciation, depletion and amortization |
(2,480,261 | ) | (2,123,773 | ) | ||||
3,968,646 | 2,283,566 | |||||||
Other property and equipment |
225,891 | 154,092 | ||||||
Less: accumulated depreciation and amortization |
(61,420 | ) | (47,774 | ) | ||||
Total Property and Equipment |
4,133,117 | 2,389,884 | ||||||
OTHER ASSETS: |
||||||||
Long-term derivative instruments |
17,493 | 2,666 | ||||||
Long-term investments |
31,544 | 9,075 | ||||||
Other assets |
47,733 | 38,666 | ||||||
Total Other Assets |
96,770 | 50,407 | ||||||
TOTAL ASSETS |
$ | 4,572,291 | $ | 2,875,608 | ||||
LIABILITIES AND STOCKHOLDERS EQUITY | ||||||||
CURRENT LIABILITIES: |
||||||||
Accounts payable |
$ | 164,264 | $ | 86,001 | ||||
Accrued interest |
46,648 | 35,025 | ||||||
Short-term derivative instruments |
92,651 | 33,697 | ||||||
Other accrued liabilities |
108,020 | 56,465 | ||||||
Revenues and royalties due others |
101,573 | 54,364 | ||||||
Total Current Liabilities |
513,156 | 265,552 | ||||||
LONG-TERM LIABILITIES: |
||||||||
Long-term debt, net |
2,057,713 | 1,651,198 | ||||||
Revenues and royalties due others |
13,921 | 13,797 | ||||||
Asset retirement obligation |
48,812 | | ||||||
Long-term derivative instruments |
4,736 | 30,174 | ||||||
Deferred income tax liability |
191,026 | | ||||||
Other liabilities |
10,117 | 7,012 | ||||||
Total Long-term Liabilities |
2,326,325 | 1,702,181 | ||||||
CONTINGENCIES AND COMMITMENTS (Note 4) |
||||||||
STOCKHOLDERS EQUITY: |
||||||||
Preferred Stock, $.01 par value, 10,000,000 shares authorized: |
||||||||
6.75% cumulative convertible preferred stock, 2,998,000 issued and outstanding at December 31, 2003 and 2002, entitled in liquidation to $149,900,000 |
149,900 | 149,900 | ||||||
6.00% cumulative convertible preferred stock, 4,600,000 and 0 shares issued and outstanding at December 31, 2003 and 2002, respectively, entitled in liquidation to $230,000,000 |
230,000 | | ||||||
5.00% cumulative convertible preferred stock, 1,725,000 and 0 shares issued and outstanding at December 31, 2003 and 2002, respectively, entitled in liquidation to $172,500,000 |
172,500 | | ||||||
Common Stock, $.01 par value, 350,000,000 shares authorized, 221,855,894 and 194,936,912 shares issued at December 31, 2003 and 2002, respectively |
2,218 | 1,949 | ||||||
Paid-in capital |
1,389,212 | 1,205,554 | ||||||
Accumulated deficit |
(168,617 | ) | (426,085 | ) | ||||
Accumulated other comprehensive income (loss), net of tax of $12,449,000 and $2,307,000, respectively |
(20,312 | ) | (3,461 | ) | ||||
Less: treasury stock, at cost; 5,071,571 and 4,792,529 common shares at December 31, 2003 and 2002, respectively |
(22,091 | ) | (19,982 | ) | ||||
Total Stockholders Equity |
1,732,810 | 907,875 | ||||||
TOTAL LIABILITIES AND STOCKHOLDERS EQUITY |
$ | 4,572,291 | $ | 2,875,608 | ||||
The accompanying notes are an integral part of these consolidated financial statements.
56
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Years Ended December 31, |
||||||||||||
2003 |
2002 |
2001 |
||||||||||
(in thousands, except per share data) | ||||||||||||
REVENUES: |
||||||||||||
Oil and gas sales |
$ | 1,296,822 | $ | 568,187 | $ | 820,318 | ||||||
Oil and gas marketing sales |
420,610 | 170,315 | 148,733 | |||||||||
Total Revenues |
1,717,432 | 738,502 | 969,051 | |||||||||
OPERATING COSTS: |
||||||||||||
Production expenses |
137,583 | 98,191 | 75,374 | |||||||||
Production taxes |
77,893 | 30,101 | 33,010 | |||||||||
General and administrative |
23,753 | 17,618 | 14,449 | |||||||||
Oil and gas marketing expenses |
410,288 | 165,736 | 144,373 | |||||||||
Oil and gas depreciation, depletion and amortization |
369,465 | 221,189 | 172,902 | |||||||||
Depreciation and amortization of other assets |
16,793 | 14,009 | 8,663 | |||||||||
Provision for legal settlements |
6,402 | | | |||||||||
Total Operating Costs |
1,042,177 | 546,844 | 448,771 | |||||||||
INCOME FROM OPERATIONS |
675,255 | 191,658 | 520,280 | |||||||||
OTHER INCOME (EXPENSE): |
||||||||||||
Interest and other income |
2,827 | 7,340 | 2,877 | |||||||||
Interest expense |
(154,356 | ) | (112,031 | ) | (98,321 | ) | ||||||
Loss on investment in Seven Seas |
(2,015 | ) | (17,201 | ) | | |||||||
Loss on repurchases of Chesapeake debt |
(20,759 | ) | (2,626 | ) | (76,667 | ) | ||||||
Impairments of investments in securities |
| | (10,079 | ) | ||||||||
Gain on sale of Canadian subsidiary |
| | 27,000 | |||||||||
Gothic standby credit facility costs |
| | (3,392 | ) | ||||||||
Total Other Income (Expense) |
(174,303 | ) | (124,518 | ) | (158,582 | ) | ||||||
INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE |
500,952 | 67,140 | 361,698 | |||||||||
INCOME TAX EXPENSE: |
||||||||||||
Current |
5,000 | (1,822 | ) | 3,565 | ||||||||
Deferred |
185,360 | 28,676 | 140,727 | |||||||||
Total Income Tax Expense |
190,360 | 26,854 | 144,292 | |||||||||
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE, NET OF TAX |
310,592 | 40,286 | 217,406 | |||||||||
CUMULATIVE EFFECT OF ACCOUNTING CHANGE, NET OF INCOME TAXES OF $1,464,000 |
2,389 | | | |||||||||
NET INCOME |
312,981 | 40,286 | 217,406 | |||||||||
PREFERRED STOCK DIVIDENDS |
(22,469 | ) | (10,117 | ) | (2,050 | ) | ||||||
NET INCOME AVAILABLE TO COMMON SHAREHOLDERS |
$ | 290,512 | $ | 30,169 | $ | 215,356 | ||||||
EARNINGS PER COMMON SHARE BASIC: |
||||||||||||
Income before cumulative effect of accounting change |
$ | 1.36 | $ | 0.18 | $ | 1.33 | ||||||
Cumulative effect of accounting change |
0.02 | | | |||||||||
$ | 1.38 | $ | 0.18 | $ | 1.33 | |||||||
EARNINGS PER COMMON SHARE ASSUMING DILUTION: |
||||||||||||
Income before cumulative effect of accounting change |
$ | 1.20 | $ | 0.17 | $ | 1.25 | ||||||
Cumulative effect of accounting change |
0.01 | | | |||||||||
$ | 1.21 | $ | 0.17 | $ | 1.25 | |||||||
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in thousands): |
||||||||||||
Basic |
211,203 | 166,910 | 162,362 | |||||||||
Assuming dilution |
258,567 | 172,714 | 173,981 | |||||||||
The accompanying notes are an integral part of these consolidated financial statements.
57
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended December 31, |
||||||||||||
2003 |
2002 |
2001 |
||||||||||
($ in thousands) | ||||||||||||
CASH FLOWS FROM OPERATING ACTIVITIES: |
||||||||||||
NET INCOME |
$ | 312,981 | $ | 40,286 | $ | 217,406 | ||||||
ADJUSTMENTS TO RECONCILE NET INCOME TO CASH PROVIDED BY OPERATING ACTIVITIES: |
||||||||||||
Depreciation, depletion and amortization |
382,004 | 230,236 | 177,543 | |||||||||
Deferred income taxes |
186,664 | 28,676 | 138,831 | |||||||||
Loss on repurchases of Chesapeake debt |
20,759 | 2,626 | 76,667 | |||||||||
Amortization of loan costs and bond discount |
5,861 | 6,041 | 5,084 | |||||||||
Unrealized (gains) losses on derivatives |
(3,992 | ) | 88,018 | (84,789 | ) | |||||||
Cumulative effect of accounting change |
(3,853 | ) | | | ||||||||
Loss on investment in Seven Seas |
2,015 | 17,201 | | |||||||||
Impairment of investments |
| | 10,079 | |||||||||
Gain on sale of Canadian subsidiary |
| | (27,000 | ) | ||||||||
Write-off of credit facility costs |
| | 3,392 | |||||||||
Other |
1,490 | (567 | ) | 1,350 | ||||||||
Cash provided by operating activities before changes in assets and liabilities |
903,929 | 412,517 | 518,563 | |||||||||
CHANGES IN ASSETS AND LIABILITIES: |
||||||||||||
(Increase) decrease in accounts receivable |
(72,683 | ) | (44,966 | ) | 34,265 | |||||||
(Increase) decrease in inventory and other assets |
(10,971 | ) | 11,330 | 929 | ||||||||
Increase (decrease) in accounts payable, accrued liabilities and other |
86,861 | 23,223 | 2,454 | |||||||||
Increase (decrease) in current and non-current revenues and royalties due others |
38,466 | 30,427 | (2,474 | ) | ||||||||
Changes in assets and liabilities |
41,673 | 20,014 | 35,174 | |||||||||
Cash provided by operating activities |
945,602 | 432,531 | 553,737 | |||||||||
CASH FLOWS FROM INVESTING ACTIVITIES: |
||||||||||||
Acquisitions of oil and gas companies, proved properties and unproved properties, net of cash acquired |
(1,261,275 | ) | (331,651 | ) | (316,743 | ) | ||||||
Exploration and development of oil and gas properties |
(727,231 | ) | (400,180 | ) | (420,969 | ) | ||||||
Additions to buildings and other fixed assets |
(71,454 | ) | (33,559 | ) | (24,853 | ) | ||||||
Additions to long-term investments |
(30,750 | ) | (2,408 | ) | (40,239 | ) | ||||||
Divestitures of oil and gas properties |
22,156 | 839 | 1,432 | |||||||||
Deposits for Concho, South Texas assets and ONEOK acquisitions |
(13,250 | ) | (15,000 | ) | | |||||||
Sale of non-oil and gas assets and recoveries of investments |
5,799 | 5,774 | 3,204 | |||||||||
Additions to drilling rig equipment |
(1,221 | ) | (3,551 | ) | (14,145 | ) | ||||||
Sale of Canadian subsidiary |
| | 142,906 | |||||||||
Other |
9 | (9 | ) | (698 | ) | |||||||
Cash used in investing activities |
(2,077,217 | ) | (779,745 | ) | (670,105 | ) | ||||||
CASH FLOWS FROM FINANCING ACTIVITIES: |
||||||||||||
Proceeds from long-term borrowings |
738,000 | 252,500 | 433,500 | |||||||||
Payments on long-term borrowings |
(738,000 | ) | (252,500 | ) | (458,500 | ) | ||||||
Cash received from issuance of senior notes, net of offering costs |
485,445 | 439,427 | 1,028,275 | |||||||||
Proceeds from issuance of preferred stock, net of offering costs |
390,365 | | 145,086 | |||||||||
Proceeds from issuance of common stock, net of offering costs |
177,427 | 164,104 | | |||||||||
Cash paid to purchase senior notes, including redemption premium |
(113,074 | ) | (111,597 | ) | (906,021 | ) | ||||||
Cash paid for common stock dividend |
(27,253 | ) | (4,987 | ) | | |||||||
Cash paid for preferred stock dividend |
(20,916 | ) | (10,177 | ) | (1,092 | ) | ||||||
Cash paid for financing cost of credit facilities |
(2,474 | ) | (2,902 | ) | (6,611 | ) | ||||||
Cash paid for treasury stock and preferred stock |
(2,109 | ) | | (10 | ) | |||||||
Net increase in outstanding payments in excess of cash balance |
28,315 | | | |||||||||
Other financing costs |
(496 | ) | (421 | ) | | |||||||
Cash received (paid) in settlements of make-whole provisions |
| | (3,336 | ) | ||||||||
Cash received from exercise of stock options |
9,329 | 3,810 | 3,216 | |||||||||
Cash provided by financing activities |
924,559 | 477,257 | 234,507 | |||||||||
EFFECT OF EXCHANGE RATE CHANGES ON CASH |
| | (545 | ) | ||||||||
Net increase (decrease) in cash and cash equivalents |
(207,056 | ) | 130,043 | 117,594 | ||||||||
Cash and cash equivalents, beginning of period |
247,637 | 117,594 | | |||||||||
Cash and cash equivalents, end of period |
$ | 40,581 | $ | 247,637 | $ | 117,594 | ||||||
The accompanying notes are an integral part of these consolidated financial statements
58
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS(Continued)
Years Ended December 31, |
|||||||||||
2003 |
2002 |
2001 |
|||||||||
($ in thousands) | |||||||||||
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION CASH PAYMENTS FOR: |
|||||||||||
Interest, net of capitalized interest |
$ | 137,146 | $ | 105,671 | $ | 97,832 | |||||
Income taxes, net of refunds received |
$ | 5,160 | $ | (738 | ) | $ | 5,461 | ||||
DETAILS OF ACQUISITION OF GOTHIC ENERGY CORPORATION: |
|||||||||||
Fair value of properties acquired |
$ | | $ | | $ | 371,371 | |||||
Stock issued (13,553,276 shares) |
$ | | $ | | $ | (28,000 | ) | ||||
Gothic preferred and common stock held by Chesapeake |
$ | | $ | | $ | (10,000 | ) | ||||
Debt assumed |
$ | | $ | | $ | (331,255 | ) | ||||
Acquisition costs and other |
$ | | $ | | $ | (2,116 | ) |
SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING AND FINANCING ACTIVITIES:
In 2003, we issued $86.7 million of our 7.75% senior notes due 2015, $63.8 million of our 7.50% senior notes due 2013 and accrued interest of $1.0 million in exchange for $71.7 million of our 8.125% senior notes due 2011, $40.2 million of our 8.375% senior notes due 2008, $32.0 million of our 8.5% senior notes due 2012 and $2.2 million of our accrued interest, pursuant to privately negotiated transactions. The $71.7 million of our 8.125% senior notes, $40.2 of our 8.375% senior notes and $32.0 million of our 8.5% senior notes were retired upon receipt.
As of December 31, 2003, 2002 and 2001, dividends payable on our common and preferred stock were $15.7 million, $8.2 million, and $0, respectively.
During 2003, 2002 and 2001, $18.1 million, $1.0 million, and $13.3 million, respectively, of additions to oil and gas properties were recorded as an increase to accrued exploration and development costs.
In January 2003, Chesapeake adopted SFAS 143, Accounting For Asset Retirement Obligations. As a result, during the year ended December 31, 2003, we recorded non-cash additions to net oil and gas properties of $49.5 million.
In 2002, holders of our 6.75% cumulative convertible preferred stock converted 2,000 shares into 12,987 shares of common stock (at a conversion price of $7.70 per share).
In 2001, holders of our 7% cumulative convertible preferred stock converted 622,768 shares into 4,480,171 shares of common stock (at a conversion price of $6.95 per share), and we redeemed the remaining 1,269 shares of preferred stock for 7,239 shares of common stock and $3,000 of cash (at a redemption price of $52.45 per share, paid in 5.7 shares of common stock and cash of $2.45).
In 2001, Chesapeake completed the acquisition of Gothic Energy Corporation. We issued 3,989,813 shares of Chesapeake common stock to Gothic shareholders (other than Chesapeake).
In 2001, we issued 1,117,216 shares of Chesapeake common stock in exchange for 49.5% of RAM Energy, Inc.s outstanding common stock. Chesapeake shares were valued at $8.854 per share. Subsequently, we made a make-whole payment to the former RAM shareholders of $3.3 million.
In 2001, Chesapeake purchased certain oil and gas assets from RAM Energy, Inc. for a total consideration of $74.4 million, consisting of $61.7 million of cash, surrender of $11.5 million principal amount of our RAM notes including $0.4 million in accrued interest, and cancellation of a $1.2 million receivable by us from RAM.
The accompanying notes are an integral part of these consolidated financial statements.
59
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY
Years Ended December 31, |
||||||||||||
2003 |
2002 |
2001 |
||||||||||
($ in thousands) | ||||||||||||
PREFERRED STOCK: |
||||||||||||
Balance, beginning of period |
$ | 149,900 | $ | 150,000 | $ | 31,202 | ||||||
Issuance of 6.00% cumulative convertible preferred stock |
230,000 | | | |||||||||
Issuance of 5.00% cumulative convertible preferred stock |
172,500 | | | |||||||||
Exchange of common stock for 2,000 and 624,037 shares of preferred stock |
| (100 | ) | (31,202 | ) | |||||||
Issuance of 6.75% cumulative convertible preferred stock |
| | 150,000 | |||||||||
Balance, end of period |
552,400 | 149,900 | 150,000 | |||||||||
COMMON STOCK: |
||||||||||||
Balance, beginning of period |
1,949 | 1,696 | 1,578 | |||||||||
Exercise of stock options and warrants |
39 | 23 | 21 | |||||||||
Issuance of 23,000,000 shares of common stock |
230 | 230 | | |||||||||
Issuance of 3,989,813 shares of common stock to Gothic shareholders |
| | 40 | |||||||||
Issuance of 1,117,216 shares of common stock to RAM Energy, Inc. shareholders |
| | 11 | |||||||||
Exchange of 4,487,410 shares of common stock for preferred stock |
| | 45 | |||||||||
Other |
| | 1 | |||||||||
Balance, end of period |
2,218 | 1,949 | 1,696 | |||||||||
PAID-IN CAPITAL: |
||||||||||||
Balance, beginning of period |
1,205,554 | 1,035,156 | 963,584 | |||||||||
Exercise of stock options and warrants |
9,290 | 3,787 | 3,188 | |||||||||
Issuance of common stock |
186,070 | 172,270 | | |||||||||
Issuance of common stock to acquire RAM Energy, Inc. common stock |
| | 9,881 | |||||||||
Issuance of common stock to acquire Gothic Energy Corporation |
| | 29,389 | |||||||||
Offering expenses |
(21,139 | ) | (8,506 | ) | (4,891 | ) | ||||||
Exchange of 12,987 and 4,487,410 shares of common stock for preferred stock |
| 100 | 31,157 | |||||||||
Make-whole payments on common stock issued to RAM Energy, Inc. shareholders |
| | (3,336 | ) | ||||||||
Compensation costs related to stock and stock options |
2,292 | 356 | 800 | |||||||||
Tax benefit from exercise of stock options |
7,145 | 2,391 | 5,384 | |||||||||
Balance, end of period |
1,389,212 | 1,205,554 | 1,035,156 | |||||||||
ACCUMULATED DEFICIT: |
||||||||||||
Balance, beginning of period |
(426,085 | ) | (442,974 | ) | (659,286 | ) | ||||||
Net income |
312,981 | 40,286 | 217,406 | |||||||||
Dividends on common stock |
(29,128 | ) | (10,690 | ) | | |||||||
Dividends on preferred stock |
(26,385 | ) | (12,707 | ) | (1,094 | ) | ||||||
Balance, end of period |
(168,617 | ) | (426,085 | ) | (442,974 | ) | ||||||
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS): |
||||||||||||
Balance, beginning of period |
(3,461 | ) | 43,511 | (3,901 | ) | |||||||
Foreign currency translation adjustments |
| | (3,551 | ) | ||||||||
Transfer of translation adjustments related to sale of Canadian subsidiary |
| | 7,452 | |||||||||
Gain/(loss) on hedging activity |
(16,851 | ) | (46,972 | ) | 43,511 | |||||||
Balance, end of period |
(20,312 | ) | (3,461 | ) | 43,511 | |||||||
TREASURY STOCKCOMMON: |
||||||||||||
Balance, beginning of period |
(19,982 | ) | (19,982 | ) | (19,945 | ) | ||||||
Exercised options |
| | (37 | ) | ||||||||
Purchase of 279,042 shares of treasury stock |
(2,109 | ) | | | ||||||||
Balance, end of period |
(22,091 | ) | (19,982 | ) | (19,982 | ) | ||||||
TOTAL STOCKHOLDERS EQUITY |
$ | 1,732,810 | $ | 907,875 | $ | 767,407 | ||||||
The accompanying notes are an integral part of these consolidated financial statements.
60
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
Years Ended December 31, |
||||||||||||
2003 |
2002 |
2001 |
||||||||||
($ in thousands) | ||||||||||||
NET INCOME |
$ | 312,981 | $ | 40,286 | $ | 217,406 | ||||||
Other comprehensive income (loss), net of income tax: |
||||||||||||
Change in fair value of derivative instruments, net of income taxes of ($15,272), ($18,027) and $98,140 |
(24,917 | ) | (27,041 | ) | 147,210 | |||||||
Reclassification of (gain) loss on settled contracts, net of income taxes of $1,448, ($14,711) and ($32,415) |
2,363 | (22,066 | ) | (48,623 | ) | |||||||
Ineffective portion of derivatives qualifying for hedge accounting, net of income taxes of $3,495, $1,423 and ($1,002) |
5,703 | 2,135 | (1,503 | ) | ||||||||
Foreign currency translation adjustments, net of income taxes of ($2,367) |
| | (3,551 | ) | ||||||||
Transfer of translation adjustments related to sale of Canadian subsidiary, net of income taxes of $4,968 |
| | 7,452 | |||||||||
Cumulative effect of accounting change for financial derivatives, net of income taxes of ($35,715) |
| | (53,573 | ) | ||||||||
Comprehensive income (loss) |
$ | 296,130 | $ | (6,686 | ) | $ | 264,818 | |||||
The accompanying notes are an integral part of these consolidated financial statements.
61
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Basis of Presentation and Summary of Significant Accounting Policies
Description of Company
Chesapeake Energy Corporation is an oil and natural gas exploration and production company engaged in the acquisition, exploration, and development of properties for the production of crude oil and natural gas from underground reservoirs and the marketing of natural gas and oil for other working interest owners in properties we operate. Our properties are located in Oklahoma, Texas, Arkansas, Louisiana, Kansas, Montana, Colorado, North Dakota and New Mexico.
Principles of Consolidation
The accompanying consolidated financial statements of Chesapeake Energy Corporation include the accounts of our direct and indirect wholly-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated. Investments in companies and partnerships which give us significant influence, but not control, over the investee are accounted for using the equity method. Other investments are generally carried at cost.
Accounting Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.
Cash Equivalents
For purposes of the consolidated financial statements, Chesapeake considers investments in all highly liquid instruments with maturities of three months or less at date of purchase to be cash equivalents.
Restricted Cash
Chesapeake classifies cash balances as restricted cash when cash is restricted as to withdrawal or usage. The restricted cash balance at December 31, 2003 and 2002 was $0 and $82,000 respectively.
Inventory
Inventory, which is included in current assets, consists primarily of tubular goods and other lease and well equipment which we plan to utilize in our ongoing exploration and development activities and is carried at the lower of cost or market using the specific identification method. Oil inventory in tanks is carried at the lower of the estimated cost to produce or market value.
Oil and Gas Properties
Chesapeake follows the full-cost method of accounting under which all costs associated with property acquisition, exploration and development activities are capitalized. We capitalize internal costs that can be directly identified with our acquisition, exploration and development activities and do not include any costs related to production, general corporate overhead or similar activities (see note 11). Capitalized costs are amortized on a composite unit-of-production method based on proved oil and gas reserves. As of December 31, 2003, approximately 74% of our present value (discounted at 10%) of estimated future net revenues of proved
62
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
reserves was evaluated by independent petroleum engineers, with the balance evaluated by our internal reservoir engineers. In addition, our internal engineers evaluate all properties quarterly. The average composite rates used for depreciation, depletion and amortization were $1.38 (U.S.) per equivalent mcfe in 2003, $1.22 (U.S.) per equivalent mcfe in 2002, and $1.07 ($1.08 in U.S. and $0.90 in Canada) per equivalent mcfe in 2001.
Proceeds from the sale of properties are accounted for as reductions of capitalized costs unless such sales involve a significant change in the relationship between costs and the value of proved reserves or the underlying value of unproved properties, in which case a gain or loss is recognized. No income is recognized in connection with contractual services provided by Chesapeake on properties in which we hold an economic interest.
The costs of unproved properties are excluded from amortization until the properties are evaluated. We review all of our unevaluated properties quarterly to determine whether or not and to what extent proved reserves have been assigned to the properties, and otherwise if impairment has occurred. Unevaluated properties are grouped by major prospect area where individual property costs are not significant and are assessed individually when individual costs are significant.
We review the carrying value of our oil and gas properties under the full-cost accounting rules of the Securities and Exchange Commission on a quarterly basis. Under these rules, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed an amount equal to the sum of the present value of estimated future net revenues less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects.
Leasehold Costs
Statement of Financial Accounting Standards No. 141, Business Combinations and Statement of Financial Accounting Standards No. 142, Goodwill and Intangible Assets were issued by the Financial Accounting Standards Board in June 2001 and became effective for us on July 1, 2001 and January 1, 2002, respectively. SFAS 141 requires all business combinations initiated after June 30, 2001 to be accounted for using the purchase method. Additionally, SFAS 141 requires companies to disaggregate and report separately from goodwill certain intangible assets. SFAS 142 establishes new guidelines for accounting for goodwill and other intangible assets. Under SFAS 142, goodwill and certain other intangible assets are not amortized, but rather are reviewed annually for impairment.
The Emerging Issues Task Forces (EITF) is considering two issues related to the reporting of oil and gas mineral rights. Issue No. 03-S, Application of SFAS No. 142, Goodwill and Other Intangible Assets to Oil and Gas Companies, considers whether oil and gas drilling rights are subject to the classification and disclosure provisions of SFAS 142 if they are intangible assets.
Chesapeake classifies the cost of oil and gas mineral rights as property and equipment and believes that this is consistent with oil and gas accounting and industry practice. If the EITF determines that oil and gas mineral rights are intangible assets and are subject to the applicable classification and disclosure provisions of SFAS 142, we estimate that $227.3 million and $72.5 million would be classified on our consolidated balance sheets as intangible undeveloped leasehold and $1.4 billion and $532.8 million would be classified as intangible developed leasehold as of December 31, 2003 and 2002, respectively. These amounts are net of accumulated DD&A. There would be no effect on the consolidated statements of operations or cash flows as the intangible assets related to oil and gas mineral rights would continue to be amortized under the full cost method of accounting.
We will continue to classify our oil and gas mineral rights held under lease and other contractual rights representing the right to extract such reserves as tangible oil and gas properties until further guidance is provided.
63
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
Asset Retirement Obligations
Effective January 1, 2003, Chesapeake adopted SFAS No. 143, Accounting for Asset Retirement Obligations. This statement applies to obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction and development of the assets.
SFAS 143 requires that the fair value of a liability for a retirement obligation be recognized in the period in which the liability is incurred. For oil and gas properties, this is the period in which an oil or gas well is acquired or drilled. The asset retirement obligation is capitalized as part of the carrying amount of our oil and gas properties at its discounted fair value. The liability is then accreted each period until the liability is settled or the well is sold, at which time the liability is reversed.
Other Property and Equipment
Other property and equipment consists primarily of gas gathering and processing facilities, drilling rigs, vehicles, land, office buildings and equipment, and software. Major renewals and betterments are capitalized while the costs of repairs and maintenance are charged to expense as incurred. The costs of assets retired or otherwise disposed of and the applicable accumulated depreciation are removed from the accounts, and the resulting gain or loss is reflected in operations. Other property and equipment costs are depreciated on a straight-line basis. A summary of other property and equipment and the useful lives are as follows:
December 31, |
||||||||
2003 |
2002 |
Useful Life | ||||||
(in thousands) | (in years) | |||||||
Land |
$ | 11,777 | $ | 9,000 | N/A | |||
Buildings and improvements |
74,272 | 50,269 | 15 39 | |||||
Gathering, processing and compression equipment |
58,083 | 30,818 | 7 15 | |||||
Other fixtures and equipment |
55,477 | 38,943 | 2 7 | |||||
Drilling rigs |
26,282 | 25,062 | 15 | |||||
Total |
$ | 225,891 | $ | 154,092 | ||||
Debt Issue Costs
Included in other assets are costs associated with the issuance of our senior notes and costs associated with our revolving bank credit facility. The remaining unamortized debt issue costs at December 31, 2003 and 2002 totaled $28.4 million and $21.5 million, respectively, and are being amortized over the life of the senior notes or revolving credit facility.
Capitalized Interest
During 2003, 2002 and 2001, interest of approximately $13.0 million, $5.0 million and $4.7 million, respectively, was capitalized on significant investments in unproved properties that were not being currently depreciated, depleted or amortized and on which exploration activities were in progress. Interest is capitalized using the weighted average interest rate on our outstanding borrowings.
64
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
Income Taxes
Chesapeake has adopted Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes. SFAS 109 requires deferred tax liabilities or assets to be recognized for the anticipated future tax effects of temporary differences that arise as a result of the differences in the carrying amounts and the tax bases of assets and liabilities.
Net Income (Loss) Per Share
Statement of Financial Accounting Standards No. 128, Earnings Per Share, requires presentation of basic and diluted earnings per share, as defined, on the face of the statements of operations for all entities with complex capital structures. SFAS 128 requires a reconciliation of the numerator and denominator of the basic and diluted EPS computations.
The following securities were not included in the calculation of diluted earnings per share, as the effect was antidilutive:
| For the years ended December 31, 2003, 2002 and 2001, outstanding warrants to purchase 0.4 million, 0.6 million and 1.1 million shares of common stock at a weighted average exercise price of $14.55, $14.51 and $12.61, respectively, were antidilutive because the exercise prices of the warrants were greater than the average market price of the common stock. |
| For the years ended December 31, 2003, 2002 and 2001, outstanding options to purchase 1.9 million, 0.6 million and 0.3 million shares of common stock at a weighted average exercise price of $11.15, $11.93 and $15.54, respectively, were antidilutive because the exercise prices of the options were greater than the average market price of the common stock. |
| For the year ended December 31, 2002, diluted shares do not include the assumed conversion of the outstanding 6.75% preferred stock (convertible into 19.5 million common shares), and the common stock equivalent of preferred stock outstanding prior to conversion (convertible into 5,693 shares) as the effects were antidilutive. |
65
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
A reconciliation for the years ended December 31, 2003, 2002 and 2001 is as follows:
Income (Numerator) |
Shares (Denominator) |
Per Amount | |||||||
(in thousands, except per share data) | |||||||||
For the Year Ended December 31, 2003: |
|||||||||
Income before cumulative effect of accounting change, net of tax |
$ | 310,592 | |||||||
Preferred stock dividends |
(22,469 | ) | |||||||
Basic EPS Income available to common shareholders before cumulative effect of accounting change, net of tax |
$ | 288,123 | 211,203 | $ | 1.36 | ||||
Effect of Dilutive Securities |
|||||||||
Assumed conversion at the beginning of the period of preferred shares outstanding during the period: |
|||||||||
Common shares assumed issued for 5.00% convertible preferred stock |
| 1,441 | |||||||
Common shares assumed issued for 6.00% convertible preferred stock |
| 18,499 | |||||||
Common shares assumed issued for 6.75% convertible preferred stock |
| 19,467 | |||||||
Preferred stock dividends |
22,469 | | |||||||
Employee stock options |
| 7,957 | |||||||
Diluted EPS Income available to common shareholders before cumulative effect of accounting change, net of tax |
$ | 310,592 | 258,567 | $ | 1.20 | ||||
For the Year Ended December 31, 2002: |
|||||||||
Basic EPS Income available to common shareholders |
$ | 30,169 | 166,910 | $ | 0.18 | ||||
Effect of Dilutive Securities |
|||||||||
Employee stock options |
| 5,797 | |||||||
Warrants assumed in Gothic acquisition |
| 7 | |||||||
Diluted EPS Income available to common shareholders |
$ | 30,169 | 172,714 | $ | 0.17 | ||||
For the Year Ended December 31, 2001: |
|||||||||
Basic EPS Income available to common shareholders |
$ | 215,356 | 162,362 | $ | 1.33 | ||||
Effect of Dilutive Securities |
|||||||||
Assumed conversion at the beginning of the period of preferred shares exchanged during the period: |
|||||||||
Common shares assumed issued for 6.75% convertible preferred stock |
| 2,989 | |||||||
Common shares assumed issued prior to conversion for 7% convertible preferred stock |
| 1,464 | |||||||
Preferred stock dividends |
2,050 | | |||||||
Employee stock options |
| 7,160 | |||||||
Warrants assumed in Gothic acquisition |
| 6 | |||||||
Diluted EPS Income available to common shareholders |
$ | 217,406 | 173,981 | $ | 1.25 | ||||
66
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
On January 14, 2004, we issued 23,000,000 shares of common stock at a price to the public of $13.51 per share.
On November 12, 2003, we issued 1,725,000 shares of 5% cumulative convertible preferred stock, par value $0.01 per share and liquidation preference $100 per share, in a public offering.
On March 5, 2003, we issued 4,600,000 shares of 6% cumulative convertible preferred stock, par value $0.01 per share and liquidation preference $50 per share, in a private offering. We subsequently registered, under the Securities Act of 1933, the shares of the preferred stock and underlying common stock for resale by the holders.
On March 5, 2003, we issued 23,000,000 shares of Chesapeake common stock at $8.10 per share in a public offering.
On December 18, 2002, we issued 23,000,000 shares of common stock at $7.50 per share in a public offering.
On November 13, 2001, we issued 3,000,000 shares of 6.75% cumulative convertible preferred stock, par value $0.01 per share and liquidation preference $50 per share, in a private offering. As of December 31, 2003, 2,998,000 shares remain outstanding. We subsequently registered, under the Securities Act of 1933, the shares of the preferred stock and underlying common stock for resale by the holders.
In 2001, holders of our 7% cumulative convertible preferred stock converted 622,768 shares into 4,480,171 shares of common stock (at a conversion price of $6.95 per share), and we redeemed the remaining 1,269 shares of 7% preferred stock for 7,239 shares of common stock and $3,000 of cash (at a redemption price of $52.45 per share, paid in 5.7 shares of common stock and cash of $2.45).
Revenue Recognition
Gas Imbalances. We follow the sales method of accounting for our gas revenue whereby we recognize sales revenue on all gas sold to our purchasers, regardless of whether the sales are proportionate to our ownership in the property. An asset and a liability is recognized to the extent that we have an imbalance in excess of the remaining gas reserves on the underlying properties. The gas imbalance asset and liability at December 31, 2003 and 2002 were not significant.
Oil and Natural Gas Sales. Revenue from the sale of oil and natural gas is recognized when title passes, net of royalties.
Marketing Sales. Chesapeake takes title to the natural gas it purchases from other working interest owners in operated wells and arranges for transportation and delivers the natural gas to third parties, at which time revenues are recorded. Chesapeakes results of operations related to its oil and gas marketing activities are presented on a gross basis, because we act as a principal rather than an agent. All significant intercompany accounts and transactions have been eliminated. Only sales to third parties are reflected in the consolidated statements of operations.
Hedging
From time to time, Chesapeake uses commodity price and financial risk management instruments to mitigate our exposure to price fluctuations in oil and natural gas transactions and interest rates. Recognized gains and losses on derivative contracts are reported as a component of the related transaction. Results of oil and gas derivative transactions are reflected in oil and gas sales and results of interest rate hedging transactions are reflected in interest expense. The changes in fair value of derivative instruments not qualifying for designation as
67
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
either cash flow or fair value hedges that occur prior to maturity are reported currently in the consolidated statement of operations as unrealized gains (losses) within oil and gas sales or interest expense. Cash flows from derivative instruments are classified in the same category within the statement of cash flows as the items being hedged, or on a basis consistent with the nature of the instrument.
We have established the fair value of all derivative instruments using estimates determined by our counterparties and subsequently evaluated internally using established index prices and other sources. These values are based upon, among other things, futures prices, volatility, time to maturity and credit risk. The values we report in our financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors.
Effective January 1, 2001, we adopted Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities. This statement establishes accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded at fair value and included in the consolidated balance sheet as assets or liabilities. The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. For derivative instruments designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Any change in the fair value resulting from ineffectiveness, as defined by SFAS 133, is recognized immediately in oil and gas sales. For derivative instruments designated as fair value hedges (in accordance with SFAS 133), changes in fair value, as well as the offsetting changes in the estimated fair value of the hedged item attributable to the hedged risk, are recognized currently in earnings. Differences between the changes in the fair values of the hedged item and the derivative instrument, if any, represent gains or losses on ineffectiveness and are reflected currently in interest expense. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. Changes in fair value of contracts that do not qualify as hedges or are not designated as hedges are also recognized currently in earnings.
Adoption of SFAS 133 at January 1, 2001 resulted in the recognition of $9.3 million of current derivative assets and $98.6 million in current derivative liabilities. The cumulative effect of the accounting change decreased accumulated other comprehensive income by $53.6 million, net of income tax, but did not have an effect on our net income or earnings per share amounts.
Accounts Payable and Accrued Liabilities
Included in accounts payable at December 31, 2003 are liabilities of approximately $28.3 million representing the amount by which checks issued, but not presented to our banks for collection, exceeded balances in applicable bank accounts. Other accrued liabilities include $34.1 million and $16.0 million of accrued drilling costs as of December 31, 2003 and 2002, respectively.
Currency Translation
The results of operations for non-U.S. subsidiaries are translated from local currencies into U.S. dollars using average exchange rates during each period; assets and liabilities are translated using exchange rates at the end of each period. Adjustments resulting from the translation process are reported in a separate component of stockholders equity, and are not included in the determination of the results of operations. In October 2001, we sold our Canadian subsidiary. As a result, all translation adjustments related to our investment in this subsidiary were reclassified to earnings in the fourth quarter of 2001.
Stock Options
Chesapeake has elected to follow APB No. 25, Accounting for Stock Issued to Employees and related interpretations in accounting for its employee stock options. Under APB No. 25, compensation expense is
68
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
recognized for the difference between the option price and market value on the measurement date. In March 2000, the Financial Accounting Standards Board issued FASB Interpretation No. 44 (FIN 44), which provided clarification regarding the application of APB No. 25. FIN 44 specifically addressed the accounting consequence of various modifications to the terms of a previously granted fixed-price stock option. Pursuant to FIN 44, we recognized compensation expense of $0.9 million, $0.4 million and $0.8 million in 2003, 2002, and 2001, respectively, as a result of modifications to fixed-price stock options that were made during the years ended December 31, 2003, 2001 and 2000. No compensation expense has been recognized for stock options upon original issuance in 2003, 2002 or 2001 because the exercise price of the stock options granted under the plans equaled the market price of the underlying stock on the date of grant.
Pro forma information regarding net income and earnings per share is required by SFAS No. 123 and has been determined as if we had accounted for our employee stock options under the fair value method of the statement. The fair value for these options was estimated at the date of grant using a Black-Scholes option pricing model with the following weighted-average assumptions for 2003, 2002 and 2001, respectively: interest rates (zero-coupon U.S. government issues with a remaining life equal to the expected term of the options) ranging from 2.24% to 4.97%, dividend yields ranging from 0.0% to 1.55%, and volatility factors of the expected market price of our common stock ranging from 0.35 to 0.58. We used a weighted-average expected life of the options of five years for each of 2003, 2002 and 2001.
The Black-Scholes option valuation model was developed for use in estimating the fair value of traded options which have no vesting restrictions and are fully transferable. In addition, option valuation models require the input of highly subjective assumptions including the expected stock price volatility. Because our employee stock options have characteristics significantly different from those of traded options, and because changes in the subjective input assumptions can materially affect the fair value estimate, in managements opinion the existing models do not necessarily provide a reliable single measure of the fair value of the companys employee stock options.
Pro forma information applying the fair value method follows:
Years Ended December 31, | |||||||||
2003 |
2002 |
2001 | |||||||
($ in thousands, except per share amounts) | |||||||||
Net Income: |
|||||||||
As reported |
$ | 312,981 | $ | 40,286 | $ | 217,406 | |||
Less compensation expense, net of tax(1) |
11,018 | 8,644 | 9,063 | ||||||
Pro forma |
$ | 301,963 | $ | 31,642 | $ | 208,343 | |||
Basic Earnings per common share: |
|||||||||
As reported |
$ | 1.38 | $ | 0.18 | $ | 1.33 | |||
Less compensation expense, net of tax(1) |
0.06 | 0.05 | 0.06 | ||||||
Pro forma |
$ | 1.32 | $ | 0.13 | $ | 1.27 | |||
Diluted Earnings per common share: |
|||||||||
As reported |
$ | 1.21 | $ | 0.17 | $ | 1.25 | |||
Less compensation expense, net of tax(1) |
0.04 | 0.05 | 0.05 | ||||||
Pro forma |
$ | 1.17 | $ | 0.12 | $ | 1.20 | |||
(1) | Adjustments are net of compensation expenses related to FIN 44 of $0.9 million, $0.4 million and $0.8 million in 2003, 2002 and 2001, respectively. |
69
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
For purposes of the pro forma disclosures, the estimated fair value of the options is amortized to expense over the options vesting period, which is four years. The above pro forma disclosures may not be representative of the effects on pro forma net income for future years.
Reclassifications
Certain reclassifications have been made to the consolidated financial statements for 2002 and 2001 to conform to the presentation used for the 2003 consolidated financial statements.
2. Senior Notes
On November 26, 2003, we issued $200.0 million principal amount of 6.875% senior notes due 2016 in a private placement.
On March 5, 2003, we issued $300.0 million principal amount of 7.50% senior notes due 2013, which were exchanged on November 5, 2003 for substantially identical notes registered under the Securities Act of 1933. On October 17, 2003, we issued an additional $63.8 million of our 7.50% senior notes due 2013 and accrued interest of $0.4 million in exchange for $54.9 million of our 8.125% senior notes due 2011, $6.3 million of our 8.375% senior notes due 2008 and accrued interest of $0.4 million, pursuant to a privately negotiated transaction. The $54.9 million of 8.125% senior notes and $6.3 million of 8.375% senior notes were retired upon receipt.
On December 20, 2002, we issued $150.0 million principal amount of 7.75% senior notes due 2015, which were exchanged on February 20, 2003 for substantially identical notes registered under the Securities Act of 1933. On July 16, 2003, we issued an additional $29.5 million of our 7.75% senior notes due 2015 in exchange for $27.9 million of our 8.375% senior notes due 2008 and $0.5 million of accrued interest, pursuant to a privately negotiated transaction. The $27.9 million of 8.375% senior notes due 2008 were retired upon receipt. On August 5, 2003, we issued an additional $33.5 million of our 7.75% senior notes due 2015 and accrued interest of $0.1 million in exchange for $32.0 million of our 8.5% senior notes due 2012 and $1.1 million of accrued interest, pursuant to a privately negotiated transaction. The $32.0 million of 8.5% senior notes were retired upon receipt. On October 3, 2003, we issued an additional $23.7 million of our 7.75% senior notes due 2015 and accrued interest of $0.4 million in exchange for $16.8 million of our 8.125% senior notes due 2011, $6.0 million of our 8.375% senior notes due 2008 and accrued interest of $0.2 million, pursuant to a privately negotiated transaction. The $16.8 million of 8.125% senior notes and $6.0 million of 8.375% senior notes were retired upon receipt.
On August 12, 2002, we issued $250.0 million principal amount of 9% senior notes due 2012, which were exchanged on October 24, 2002 for substantially identical notes registered under the Securities Act of 1933. In a private offering on November 14, 2002 we issued an additional $50.0 million principal amount of 9% senior notes due 2012 which were exchanged on February 20, 2003 for substantially identical notes registered under the Securities Act of 1933.
On March 17, 1997, we issued $150.0 million principal amount of 8.5% senior notes due 2012. During the quarter ended March 31, 2001, Chesapeake purchased and subsequently retired $7.3 million of these notes for total consideration of $7.4 million, including accrued interest of $0.2 million and the write-off of $0.1 million of unamortized bond discount. On August 5, 2003, we exchanged $32.0 million principal of 8.5% senior notes for $33.5 million of our 7.75% senior notes discussed above. In the fourth quarter of 2003, we purchased and subsequently retired $106.4 million of these notes for a total consideration of $114.9 million, including accrued interest of $1.8 million. In connection with this repurchase transaction, we recorded a pre-tax loss of $20.8 million, consisting of $6.7 million of redemption premium, $1.8 million write-off of unamortized debt
70
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
issue costs and notes discount, $0.3 million of transaction costs, and a write-off of the call option value of $12.0 million recorded as a discount on the 8.5% senior notes based on the hedging relationship between the notes and our 8.5% swaption further discussed in Note 10.
Chesapeake is a holding company and owns no operating assets and has no significant operations independent of its subsidiaries. Our obligations under our outstanding senior notes have been fully and unconditionally guaranteed, on a joint and several basis, by each of our restricted subsidiaries (as defined in the respective indentures governing these notes) (collectively, the guarantor subsidiaries). Each guarantor subsidiary is a direct or indirect wholly-owned subsidiary.
The senior note indentures permit us to redeem the senior notes at any time at specified make-whole or redemption prices. The indentures contain covenants limiting us and the guarantor subsidiaries with respect to asset sales; the incurrence of additional indebtedness and the issuance of preferred stock; liens; sale and leaseback transactions; lines of business; dividend and other payment restrictions; mergers or consolidations; and transactions with affiliates.
Set forth below are condensed consolidating financial statements of the parent, guarantor subsidiaries and the non-guarantors. Chesapeake Energy Marketing, Inc., Mayfield Processing, L.L.C. and MidCon Compression, L.P. are wholly owned subsidiaries which are not guarantors of the senior notes. Chesapeake Energy Marketing, Inc. was a non-guarantor subsidiary for all periods presented. Mayfield Processing, L.L.C. and MidCon Compression, L.P. were established as non-guarantor subsidiaries during 2003. All of our other wholly-owned subsidiaries were guarantor subsidiaries during all periods presented.
71
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
CONDENSED CONSOLIDATING BALANCE SHEET
AS OF DECEMBER 31, 2003
($ in thousands)
Guarantor Subsidiaries |
Non- Guarantor Subsidiaries |
Parent |
Eliminations |
Consolidated |
||||||||||||||||
ASSETS | ||||||||||||||||||||
CURRENT ASSETS: |
||||||||||||||||||||
Cash and cash equivalents, including restricted cash |
$ | 248 | $ | 32,131 | $ | 8,202 | $ | | $ | 40,581 | ||||||||||
Accounts receivable |
181,538 | 127,717 | 11,000 | (78,861 | ) | 241,394 | ||||||||||||||
Short-term derivative receivable |
1,777 | | | | 1,777 | |||||||||||||||
Short-term derivative instruments |
| | 2,690 | | 2,690 | |||||||||||||||
Deferred income tax asset |
| | 36,705 | | 36,705 | |||||||||||||||
Inventory and other |
17,368 | 1,770 | 119 | | 19,257 | |||||||||||||||
Total Current Assets |
200,931 | 161,618 | 58,716 | (78,861 | ) | 342,404 | ||||||||||||||
PROPERTY AND EQUIPMENT: |
||||||||||||||||||||
Evaluated oil and gas properties |
6,221,576 | | | | 6,221,576 | |||||||||||||||
Unevaluated leasehold |
227,331 | | | | 227,331 | |||||||||||||||
Other property and equipment |
82,230 | 58,083 | 85,578 | | 225,891 | |||||||||||||||
Less: accumulated depreciation, depletion and amortization |
(2,511,382 | ) | (23,982 | ) | (6,317 | ) | | (2,541,681 | ) | |||||||||||
Net Property and Equipment |
4,019,755 | 34,101 | 79,261 | | 4,133,117 | |||||||||||||||
OTHER ASSETS: |
||||||||||||||||||||
Investments in subsidiaries and intercompany advances |
| | 853,184 | (853,184 | ) | | ||||||||||||||
Long-term derivative instruments |
17,493 | | | | 17,493 | |||||||||||||||
Long-term investments |
5,000 | | 26,544 | | 31,544 | |||||||||||||||
Other assets |
23,641 | 14 | 24,092 | (14 | ) | 47,733 | ||||||||||||||
Total Other Assets |
46,134 | 14 | 903,820 | (853,198 | ) | 96,770 | ||||||||||||||
TOTAL ASSETS |
$ | 4,266,820 | $ | 195,733 | $ | 1,041,797 | $ | (932,059 | ) | $ | 4,572,291 | |||||||||
LIABILITIES AND STOCKHOLDERS EQUITY (DEFICIT) | ||||||||||||||||||||
CURRENT LIABILITIES: |
||||||||||||||||||||
Accounts payable |
$ | 160,422 | $ | 120,369 | $ | | $ | (116,527 | ) | $ | 164,264 | |||||||||
Accrued interest |
| | 46,648 | | 46,648 | |||||||||||||||
Short-term derivative instruments |
60,050 | | 32,601 | | 92,651 | |||||||||||||||
Other accrued liabilities |
86,759 | 5,553 | 15,751 | (43 | ) | 108,020 | ||||||||||||||
Revenues and royalties due others |
63,907 | | | 37,666 | 101,573 | |||||||||||||||
Total Current Liabilities |
371,138 | 125,922 | 95,000 | (78,904 | ) | 513,156 | ||||||||||||||
OTHER LIABILITIES: |
||||||||||||||||||||
Long-term debt, net |
| | 2,057,713 | | 2,057,713 | |||||||||||||||
Revenues and royalties due others |
13,921 | | | | 13,921 | |||||||||||||||
Asset retirement obligation |
48,812 | | | | 48,812 | |||||||||||||||
Long-term derivative instruments |
4,209 | | 527 | | 4,736 | |||||||||||||||
Deferred income tax liability (asset) |
278,914 | 3,772 | (91,660 | ) | | 191,026 | ||||||||||||||
Other liabilities |
10,117 | | | | 10,117 | |||||||||||||||
Intercompany payables (receivables) |
2,753,590 | (1,026 | ) | (2,752,593 | ) | 29 | | |||||||||||||
Total Other Liabilities |
3,109,563 | 2,746 | (786,013 | ) | 29 | 2,326,325 | ||||||||||||||
STOCKHOLDERS EQUITY (DEFICIT): |
||||||||||||||||||||
Common Stock |
56 | 1 | 2,218 | (57 | ) | 2,218 | ||||||||||||||
Preferred Stock |
| | 552,400 | | 552,400 | |||||||||||||||
Other |
786,063 | 67,064 | 1,178,192 | (853,127 | ) | 1,178,192 | ||||||||||||||
Total Stockholders Equity |
786,119 | 67,065 | 1,732,810 | (853,184 | ) | 1,732,810 | ||||||||||||||
TOTAL LIABILITIES AND STOCKHOLDERS EQUITY |
$ | 4,266,820 | $ | 195,733 | $ | 1,041,797 | $ | (932,059 | ) | $ | 4,572,291 | |||||||||
72
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
CONDENSED CONSOLIDATING BALANCE SHEET
AS OF DECEMBER 31, 2002
($ in thousands)
Guarantor Subsidiaries |
Non- Guarantor Subsidiaries |
Parent |
Eliminations |
Consolidated |
||||||||||||||||
ASSETS | ||||||||||||||||||||
CURRENT ASSETS: |
||||||||||||||||||||
Cash and cash equivalents, including restricted cash |
$ | (31,893 | ) | $ | 24,448 | $ | 255,164 | $ | | $ | 247,719 | |||||||||
Accounts receivable |
122,074 | 69,362 | 3,006 | (46,810 | ) | 147,632 | ||||||||||||||
Short-term derivative receivable |
16,498 | | | | 16,498 | |||||||||||||||
Deferred income tax asset |
| | 8,109 | | 8,109 | |||||||||||||||
Inventory and other |
14,202 | 1,157 | | | 15,359 | |||||||||||||||
Total Current Assets |
120,881 | 94,967 | 266,279 | (46,810 | ) | 435,317 | ||||||||||||||
PROPERTY AND EQUIPMENT: |
||||||||||||||||||||
Evaluated oil and gas properties |
4,334,833 | | | | 4,334,833 | |||||||||||||||
Unevaluated leasehold |
72,506 | | | | 72,506 | |||||||||||||||
Other property and equipment |
64,475 | 30,818 | 58,799 | | 154,092 | |||||||||||||||
Less: accumulated depreciation, depletion and amortization |
(2,146,538 | ) | (20,789 | ) | (4,220 | ) | | (2,171,547 | ) | |||||||||||
Net Property and Equipment |
2,325,276 | 10,029 | 54,579 | | 2,389,884 | |||||||||||||||
OTHER ASSETS: |
||||||||||||||||||||
Investments in subsidiaries and intercompany advances |
| | 357,698 | (357,698 | ) | | ||||||||||||||
Deferred income tax asset (liability) |
(124,455 | ) | (1,941 | ) | 128,467 | | 2,071 | |||||||||||||
Long-term derivative instruments |
2,666 | | | | 2,666 | |||||||||||||||
Long-term investments |
| | 9,075 | | 9,075 | |||||||||||||||
Other assets |
20,246 | 57 | 16,349 | (57 | ) | 36,595 | ||||||||||||||
Total Other Assets |
(101,543 | ) | (1,884 | ) | 511,589 | (357,755 | ) | 50,407 | ||||||||||||
TOTAL ASSETS |
$ | 2,344,614 | $ | 103,112 | $ | 832,447 | $ | (404,565 | ) | $ | 2,875,608 | |||||||||
LIABILITIES AND STOCKHOLDERS EQUITY | ||||||||||||||||||||
CURRENT LIABILITIES: |
||||||||||||||||||||
Accounts payable |
$ | 82,083 | $ | 71,316 | $ | | $ | (67,398 | ) | $ | 86,001 | |||||||||
Accrued interest |
| | 35,025 | | 35,025 | |||||||||||||||
Short-term derivative instruments |
33,697 | | | | 33,697 | |||||||||||||||
Other accrued liabilities |
46,231 | 1,960 | 8,326 | (52 | ) | 56,465 | ||||||||||||||
Revenues and royalties due others |
33,776 | | | 20,588 | 54,364 | |||||||||||||||
Total Current Liabilities |
195,787 | 73,276 | 43,351 | (46,862 | ) | 265,552 | ||||||||||||||
OTHER LIABILITIES: |
||||||||||||||||||||
Long-term debt, net |
| | 1,651,198 | | 1,651,198 | |||||||||||||||
Revenues and royalties due others |
13,797 | | | | 13,797 | |||||||||||||||
Long-term derivative instruments |
| | 30,174 | | 30,174 | |||||||||||||||
Other liabilities |
5,687 | 1,325 | | | 7,012 | |||||||||||||||
Intercompany payables (receivable) |
1,801,833 | (1,677 | ) | (1,800,151 | ) | (5 | ) | | ||||||||||||
Total Other Liabilities |
1,821,317 | (352 | ) | (118,779 | ) | (5 | ) | 1,702,181 | ||||||||||||
STOCKHOLDERS EQUITY (DEFICIT): |
||||||||||||||||||||
Common Stock |
56 | 1 | 1,949 | (57 | ) | 1,949 | ||||||||||||||
Preferred Stock |
| | 149,900 | | 149,900 | |||||||||||||||
Other |
327,454 | 30,187 | 756,026 | (357,641 | ) | 756,026 | ||||||||||||||
Total Stockholders Equity |
327,510 | 30,188 | 907,875 | (357,698 | ) | 907,875 | ||||||||||||||
TOTAL LIABILITIES AND STOCKHOLDERS EQUITY |
$ | 2,344,614 | $ | 103,112 | $ | 832,447 | $ | (404,565 | ) | $ | 2,875,608 | |||||||||
73
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
($ in thousands)
Guarantor Subsidiaries |
Non- Guarantor Subsidiaries |
Parent |
Eliminations |
Consolidated |
||||||||||||||||
For the Year Ended December 31, 2003: |
||||||||||||||||||||
REVENUES: |
||||||||||||||||||||
Oil and gas sales |
$ | 1,296,822 | $ | | $ | | $ | | $ | 1,296,822 | ||||||||||
Oil and gas marketing sales |
| 1,295,872 | | (875,262 | ) | 420,610 | ||||||||||||||
Total Revenues |
1,296,822 | 1,295,872 | | (875,262 | ) | 1,717,432 | ||||||||||||||
OPERATING COSTS: |
||||||||||||||||||||
Production expenses |
137,583 | | | | 137,583 | |||||||||||||||
Production taxes |
77,893 | | | | 77,893 | |||||||||||||||
General and administrative |
18,802 | 3,453 | 1,498 | | 23,753 | |||||||||||||||
Oil and gas marketing expenses |
| 1,285,550 | | (875,262 | ) | 410,288 | ||||||||||||||
Oil and gas depreciation, depletion and amortization |
369,465 | | | | 369,465 | |||||||||||||||
Depreciation and amortization of other assets |
8,715 | 3,193 | 4,885 | | 16,793 | |||||||||||||||
Provision for legal settlements |
6,402 | | | | 6,402 | |||||||||||||||
Total Operating Costs |
618,860 | 1,292,196 | 6,383 | (875,262 | ) | 1,042,177 | ||||||||||||||
INCOME (LOSS) FROM OPERATIONS |
677,962 | 3,676 | (6,383 | ) | | 675,255 | ||||||||||||||
OTHER INCOME (EXPENSE): |
||||||||||||||||||||
Interest and other income |
515 | 1,154 | 157,978 | (156,820 | ) | 2,827 | ||||||||||||||
Interest expense |
(148,102 | ) | (11 | ) | (163,063 | ) | 156,820 | (154,356 | ) | |||||||||||
Loss on investment in Seven Seas |
| | (2,015 | ) | | (2,015 | ) | |||||||||||||
Loss on repurchases of Chesapeake debt |
| | (20,759 | ) | | (20,759 | ) | |||||||||||||
Equity in net earnings of subsidiaries |
| | 334,211 | (334,211 | ) | | ||||||||||||||
Total Other Income (Expense) |
(147,587 | ) | 1,143 | 306,352 | (334,211 | ) | (174,303 | ) | ||||||||||||
INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE |
530,375 | 4,819 | 299,969 | (334,211 | ) | 500,952 | ||||||||||||||
Income tax expense (benefit) |
201,541 | 1,831 | (13,012 | ) | | 190,360 | ||||||||||||||
NET INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE |
328,834 | 2,988 | 312,981 | (334,211 | ) | 310,592 | ||||||||||||||
CUMULATIVE EFFECT OF ACCOUNTING CHANGE, NET OF TAXES |
2,389 | | | | 2,389 | |||||||||||||||
NET INCOME |
$ | 331,223 | $ | 2,988 | $ | 312,981 | $ | (334,211 | ) | $ | 312,981 | |||||||||
For the Year Ended December 31, 2002: |
||||||||||||||||||||
REVENUES: |
||||||||||||||||||||
Oil and gas sales |
$ | 568,187 | $ | | $ | | $ | | $ | 568,187 | ||||||||||
Oil and gas marketing sales |
| 548,388 | | (378,073 | ) | 170,315 | ||||||||||||||
Total Revenues |
568,187 | 548,388 | | (378,073 | ) | 738,502 | ||||||||||||||
OPERATING COSTS: |
||||||||||||||||||||
Production expenses |
98,191 | | | | 98,191 | |||||||||||||||
Production taxes |
30,101 | | | | 30,101 | |||||||||||||||
General and administrative |
15,069 | 1,934 | 615 | | 17,618 | |||||||||||||||
Oil and gas marketing expenses |
| 543,809 | | (378,073 | ) | 165,736 | ||||||||||||||
Oil and gas depreciation, depletion and amortization |
221,189 | | | | 221,189 | |||||||||||||||
Depreciation and amortization of other assets |
9,515 | 1,820 | 2,674 | | 14,009 | |||||||||||||||
Total Operating Costs |
374,065 | 547,563 | 3,289 | (378,073 | ) | 546,844 | ||||||||||||||
INCOME (LOSS) FROM OPERATIONS |
194,122 | 825 | (3,289 | ) | | 191,658 | ||||||||||||||
OTHER INCOME (EXPENSE): |
||||||||||||||||||||
Interest and other income |
1,580 | 597 | 120,046 | (114,883 | ) | 7,340 | ||||||||||||||
Interest expense |
(111,943 | ) | (10 | ) | (114,961 | ) | 114,883 | (112,031 | ) | |||||||||||
Loss on investment in Seven Seas |
| | (17,201 | ) | | (17,201 | ) | |||||||||||||
Loss on repurchases of Chesapeake debt |
| | (2,626 | ) | | (2,626 | ) | |||||||||||||
Equity in net earnings of subsidiaries |
| | 51,104 | (51,104 | ) | | ||||||||||||||
Total Other Income (Expense) |
(110,363 | ) | 587 | 36,362 | (51,104 | ) | (124,518 | ) | ||||||||||||
INCOME BEFORE INCOME TAXES |
83,759 | 1,412 | 33,073 | (51,104 | ) | 67,140 | ||||||||||||||
Income tax expense (benefit) |
33,502 | 565 | (7,213 | ) | | 26,854 | ||||||||||||||
NET INCOME |
$ | 50,257 | $ | 847 | $ | 40,286 | $ | (51,104 | ) | $ | 40,286 | |||||||||
74
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
($ in thousands)
Guarantor Subsidiaries |
Non- Guarantor Subsidiaries |
Parent |
Eliminations |
Consolidated |
||||||||||||||||
For the Year Ended December 31, 2001: |
||||||||||||||||||||
REVENUES: |
||||||||||||||||||||
Oil and gas sales |
$ | 820,318 | $ | | $ | | $ | | $ | 820,318 | ||||||||||
Oil and gas marketing sales |
| 419,279 | | (270,546 | ) | 148,733 | ||||||||||||||
Total Revenues |
820,318 | 419,279 | | (270,546 | ) | 969,051 | ||||||||||||||
OPERATING COSTS: |
||||||||||||||||||||
Production expenses |
75,374 | | | | 75,374 | |||||||||||||||
Production taxes |
33,010 | | | | 33,010 | |||||||||||||||
General and administrative |
12,201 | 1,311 | 937 | | 14,449 | |||||||||||||||
Oil and gas marketing expenses |
| 414,919 | | (270,546 | ) | 144,373 | ||||||||||||||
Oil and gas depreciation, depletion and amortization |
172,902 | | | | 172,902 | |||||||||||||||
Depreciation and amortization of other assets |
6,035 | 80 | 2,548 | | 8,663 | |||||||||||||||
Total Operating Costs |
299,522 | 416,310 | 3,485 | (270,546 | ) | 448,771 | ||||||||||||||
INCOME (LOSS) FROM OPERATIONS |
520,796 | 2,969 | (3,485 | ) | | 520,280 | ||||||||||||||
OTHER INCOME (EXPENSE): |
||||||||||||||||||||
Interest and other income |
(130 | ) | 473 | 96,665 | (94,131 | ) | 2,877 | |||||||||||||
Interest expense |
(100,531 | ) | (2 | ) | (91,919 | ) | 94,131 | (98,321 | ) | |||||||||||
Loss on repurchases of Chesapeake debt |
(13,618 | ) | | (63,049 | ) | | (76,667 | ) | ||||||||||||
Impairments of investments in securities |
(8,579 | ) | | (1,500 | ) | | (10,079 | ) | ||||||||||||
Gain on sale of Canadian subsidiary |
| | 27,000 | | 27,000 | |||||||||||||||
Gothic standby credit facility costs |
| | (3,392 | ) | | (3,392 | ) | |||||||||||||
Equity in net earnings of subsidiaries |
| | 239,968 | (239,968 | ) | | ||||||||||||||
Total Other Income (Expense) |
(122,858 | ) | 471 | 203,773 | (239,968 | ) | (158,582 | ) | ||||||||||||
INCOME BEFORE INCOME TAXES |
397,938 | 3,440 | 200,288 | (239,968 | ) | 361,698 | ||||||||||||||
Income tax expense (benefit) |
160,034 | 1,376 | (17,118 | ) | | 144,292 | ||||||||||||||
NET INCOME |
$ | 237,904 | $ | 2,064 | $ | 217,406 | $ | (239,968 | ) | $ | 217,406 | |||||||||
75
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
($ in thousands)
Guarantor Subsidiaries |
Non- Guarantor Subsidiaries |
Parent |
Eliminations |
Consolidated |
||||||||||||||||
For the Year Ended December 31, 2003: |
||||||||||||||||||||
CASH FLOWS FROM OPERATING ACTIVITIES |
$ | 981,939 | $ | (44,660 | ) | $ | 342,534 | $ | (334,211 | ) | $ | 945,602 | ||||||||
CASH FLOWS FROM INVESTING ACTIVITIES: |
||||||||||||||||||||
Oil and gas properties, net |
(838,908 | ) | | (1,127,442 | ) | | (1,966,350 | ) | ||||||||||||
Additions to buildings and other fixed assets |
(18,631 | ) | (27,265 | ) | (26,779 | ) | | (72,675 | ) | |||||||||||
Additions to long-term investments |
(5,000 | ) | | (25,750 | ) | | (30,750 | ) | ||||||||||||
Deposit for Concho acquisition |
| | (10,000 | ) | | (10,000 | ) | |||||||||||||
Deposit for South Texas asset acquisition |
(3,250 | ) | | | | (3,250 | ) | |||||||||||||
Sale of non-oil and gas assets and recoveries of investments |
314 | | 5,485 | | 5,799 | |||||||||||||||
Other investments |
9 | | | | 9 | |||||||||||||||
Cash (used in) provided by investing activities |
(865,466 | ) | (27,265 | ) | (1,184,486 | ) | | (2,077,217 | ) | |||||||||||
CASH FLOWS FROM FINANCING ACTIVITIES: |
||||||||||||||||||||
Proceeds from long-term borrowing |
738,000 | | | | 738,000 | |||||||||||||||
Payments on long-term borrowings |
(738,000 | ) | | | | (738,000 | ) | |||||||||||||
Cash received from issuance of senior notes, net of costs |
| | 485,445 | | 485,445 | |||||||||||||||
Proceeds from issuance of preferred stock, net of costs |
| | 390,365 | | 390,365 | |||||||||||||||
Proceeds from issuance of common stock, net of costs |
| | 177,427 | | 177,427 | |||||||||||||||
Cash paid to repurchase senior notes, including redemption premium |
| | (113,074 | ) | | (113,074 | ) | |||||||||||||
Cash paid for common stock dividends |
| | (27,253 | ) | | (27,253 | ) | |||||||||||||
Cash paid for preferred stock dividends |
| | (20,916 | ) | | (20,916 | ) | |||||||||||||
Cash paid for financing cost of credit facility |
(2,474 | ) | | | | (2,474 | ) | |||||||||||||
Cash paid for treasury stock |
| | (2,109 | ) | | (2,109 | ) | |||||||||||||
Net increase in outstanding payments in excess of cash balances |
28,315 | | | | 28,315 | |||||||||||||||
Additions to other financing costs |
| | (496 | ) | | (496 | ) | |||||||||||||
Cash received from exercise of stock options |
| | 9,329 | | 9,329 | |||||||||||||||
Intercompany advances, net |
(110,091 | ) | 79,608 | (303,728 | ) | 334,211 | | |||||||||||||
Cash provided by (used in) financing activities |
(84,250 | ) | 79,608 | 594,990 | 334,211 | 924,559 | ||||||||||||||
NET INCREASE IN CASH AND CASH EQUIVALENTS |
32,223 | 7,683 | (246,962 | ) | | (207,056 | ) | |||||||||||||
CASH, BEGINNING OF PERIOD |
(31,975 | ) | 24,448 | 255,164 | | 247,637 | ||||||||||||||
CASH, END OF PERIOD |
$ | 248 | $ | 32,131 | $ | 8,202 | $ | | $ | 40,581 | ||||||||||
76
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
Guarantor Subsidiaries |
Non- Guarantor |
Parent |
Eliminations |
Consolidated |
||||||||||||||||
For the Year Ended December 31, 2002: |
||||||||||||||||||||
CASH FLOWS FROM OPERATING ACTIVITIES |
$ | 397,211 | $ | 1,360 | $ | 85,064 | $ | (51,104 | ) | $ | 432,531 | |||||||||
CASH FLOWS FROM INVESTING ACTIVITIES: |
||||||||||||||||||||
Oil and gas properties, net |
(419,100 | ) | | (311,892 | ) | | (730,992 | ) | ||||||||||||
Additions to buildings and other fixes assets |
(12,927 | ) | (3,860 | ) | (20,323 | ) | | (37,110 | ) | |||||||||||
Deposit for ONEOK acquisition |
(15,000 | ) | | | | (15,000 | ) | |||||||||||||
Sale of non-oil and gas assets |
1,559 | | 4,215 | | 5,774 | |||||||||||||||
Additions to long-term investments |
| | (2,408 | ) | | (2,408 | ) | |||||||||||||
Other investments |
(9 | ) | | | | (9 | ) | |||||||||||||
Cash (used in) provided by investing activities |
(445,477 | ) | (3,860 | ) | (330,408 | ) | | (779,745 | ) | |||||||||||
CASH FLOWS FROM FINANCING ACTIVITIES: |
||||||||||||||||||||
Proceeds from long-term borrowings |
252,500 | | | | 252,500 | |||||||||||||||
Payments on long-term borrowings |
(252,500 | ) | | | | (252,500 | ) | |||||||||||||
Cash received from issuance of senior notes, net of costs |
| | 439,427 | | 439,427 | |||||||||||||||
Proceeds from issuance of common stock, net of costs |
| | 164,104 | | 164,104 | |||||||||||||||
Cash paid to repurchase senior notes, including redemption premium |
| | (111,597 | ) | | (111,597 | ) | |||||||||||||
Cash dividends paid on preferred stock and common stock |
| | (15,164 | ) | | (15,164 | ) | |||||||||||||
Additions to other financing costs |
(2,902 | ) | | (421 | ) | | (3,323 | ) | ||||||||||||
Cash received from exercise of stock options |
| | 3,810 | | 3,810 | |||||||||||||||
Intercompany advances, net |
30,506 | 7,234 | (88,844 | ) | 51,104 | | ||||||||||||||
Cash provided by (used in) financing activities |
27,604 | 7,234 | 391,315 | 51,104 | 477,257 | |||||||||||||||
NET INCREASE IN CASH AND CASH EQUIVALENTS |
(20,662 | ) | 4,734 | 145,971 | | 130,043 | ||||||||||||||
CASH, BEGINNING OF PERIOD |
(11,313 | ) | 19,714 | 109,193 | | 117,594 | ||||||||||||||
CASH, END OF PERIOD |
$ | (31,975 | ) | $ | 24,448 | $ | 255,164 | $ | | $ | 247,637 | |||||||||
77
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
($ in thousands)
Guarantor Subsidiaries |
Non- Guarantor |
Parent |
Eliminations |
Consolidated |
||||||||||||||||
For the Year Ended December 31, 2001: |
||||||||||||||||||||
CASH FLOWS FROM OPERATING ACTIVITIES |
$ | 526,589 | $ | 22,484 | $ | 244,632 | $ | (239,968 | ) | $ | 553,737 | |||||||||
CASH FLOWS FROM INVESTING ACTIVITIES: |
||||||||||||||||||||
Oil and gas properties, net |
(736,280 | ) | | 142,906 | | (593,374 | ) | |||||||||||||
Additions to buildings and other fixes assets |
(26,212 | ) | (292 | ) | (12,494 | ) | | (38,998 | ) | |||||||||||
Sale of non-oil and gas assets |
3,204 | | | | 3,204 | |||||||||||||||
Additions to long-term investments |
| | (40,239 | ) | | (40,239 | ) | |||||||||||||
Other investments |
(825 | ) | 127 | | | (698 | ) | |||||||||||||
Cash (used in) provided by investing activities |
(760,113 | ) | (165 | ) | 90,173 | | (670,105 | ) | ||||||||||||
CASH FLOWS FROM FINANCING ACTIVITIES: |
||||||||||||||||||||
Proceeds from long-term borrowings |
433,500 | | | | 433,500 | |||||||||||||||
Payments on long-term borrowings |
(458,500 | ) | | | | (458,500 | ) | |||||||||||||
Cash received on issuance of senior notes, net of costs |
| | 1,028,275 | | 1,028,275 | |||||||||||||||
Cash received from issuance of preferred stock, net of costs |
| | 145,086 | | 145,086 | |||||||||||||||
Cash paid to purchase senior notes. including redemption premium |
| | (906,021 | ) | | (906,021 | ) | |||||||||||||
Cash dividends paid on preferred stock |
| | (1,092 | ) | | (1,092 | ) | |||||||||||||
Additions to other financing costs |
(5,984 | ) | | (627 | ) | | (6,611 | ) | ||||||||||||
Cash paid for purchase of preferred stock |
| | (10 | ) | | (10 | ) | |||||||||||||
Cash paid on make whole provision |
| | (3,336 | ) | | (3,336 | ) | |||||||||||||
Cash received from exercise of stock options |
| | 3,216 | | 3,216 | |||||||||||||||
Intercompany advances, net |
273,608 | (9,805 | ) | (503,771 | ) | 239,968 | | |||||||||||||
Cash provided by (used in) financing activities |
242,624 | (9,805 | ) | (238,280 | ) | 239,968 | 234,507 | |||||||||||||
EFFECT OF EXCHANGE RATE CHANGES ON CASH |
(545 | ) | | | | (545 | ) | |||||||||||||
NET INCREASE IN CASH AND CASH EQUIVALENTS |
8,555 | 12,514 | 96,525 | | 117,594 | |||||||||||||||
CASH, BEGINNING OF PERIOD |
(19,868 | ) | 7,200 | 12,668 | | | ||||||||||||||
CASH, END OF PERIOD |
$ | (11,313 | ) | $ | 19,714 | $ | 109,193 | $ | | $ | 117,594 | |||||||||
78
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
($ in thousands)
Guarantor Subsidiaries |
Non- Guarantor |
Parent |
Eliminations |
Consolidated |
|||||||||||||||
For the Year Ended December 31, 2003: |
|||||||||||||||||||
NET INCOME |
$ | 331,223 | $ | 2,988 | $ | 312,981 | $ | (334,211 | ) | $ | 312,981 | ||||||||
Other comprehensive income (loss)net of income tax: |
|||||||||||||||||||
Change in fair value of derivative instruments |
(24,917 | ) | | | | (24,917 | ) | ||||||||||||
Reclassification of gain on settled contracts |
2,363 | | | | 2,363 | ||||||||||||||
Ineffective portion of derivatives qualifying for hedge accounting |
5,703 | | | | 5,703 | ||||||||||||||
Equity in net other comprehensive income (loss) of subsidiaries |
| | (16,851 | ) | 16,851 | | |||||||||||||
Comprehensive income (loss) |
$ | 314,372 | $ | 2,988 | $ | 296,130 | $ | (317,360 | ) | $ | 296,130 | ||||||||
For the Year Ended December 31, 2002: |
|||||||||||||||||||
NET INCOME |
$ | 50,257 | $ | 847 | $ | 40,286 | $ | (51,104 | ) | $ | 40,286 | ||||||||
Other comprehensive income (loss)net of income tax: |
|||||||||||||||||||
Change in fair value of derivative instruments |
(27,041 | ) | | | | (27,041 | ) | ||||||||||||
Reclassification of gain on settled contracts |
(22,066 | ) | | | | (22,066 | ) | ||||||||||||
Ineffective portion of derivatives qualifying for hedge accounting |
2,135 | | | | 2,135 | ||||||||||||||
Equity in net other comprehensive income (loss) of subsidiaries |
| | (46,972 | ) | 46,972 | | |||||||||||||
Comprehensive income (loss) |
$ | 3,285 | $ | 847 | $ | (6,686 | ) | $ | (4,132 | ) | $ | (6,686 | ) | ||||||
For the Year Ended December 31, 2001: |
|||||||||||||||||||
NET INCOME |
$ | 237,904 | $ | 2,064 | $ | 217,406 | $ | (239,968 | ) | $ | 217,406 | ||||||||
Other comprehensive income (loss)net of income tax: |
|||||||||||||||||||
Change in fair value of derivative instruments |
147,210 | | | | 147,210 | ||||||||||||||
Reclassification of gain on settled contracts |
(48,623 | ) | | | | (48,623 | ) | ||||||||||||
Ineffective portion of derivatives qualifying for hedge accounting |
(1,503 | ) | | | | (1,503 | ) | ||||||||||||
Foreign currency translation adjustments |
(3,551 | ) | | | | (3,551 | ) | ||||||||||||
Transfer of translation adjustments related to sale of Canadian subsidiary |
7,452 | | | | 7,452 | ||||||||||||||
Cumulative effect of accounting change for financial derivatives |
(53,573 | ) | | | | (53,573 | ) | ||||||||||||
Equity in net other comprehensive income (loss) of subsidiaries |
| | 47,412 | (47,412 | ) | | |||||||||||||
Comprehensive income |
$ | 285,316 | $ | 2,064 | $ | 264,818 | $ | (287,380 | ) | $ | 264,818 | ||||||||
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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
3. Notes Payable and Long-Term Debt
Notes payable and long-term debt consist of the following:
December 31, |
||||||||
2003 |
2002 |
|||||||
($ in thousands) | ||||||||
7.875% Senior Notes due 2004 (a) |
$ | 42,137 | $ | 42,137 | ||||
8.5% Senior Notes due 2012 |
4,290 | 142,665 | ||||||
8.125% Senior Notes due 2011 |
728,255 | 800,000 | ||||||
8.375% Senior Notes due 2008 |
209,815 | 250,000 | ||||||
9.0% Senior Notes due 2012 |
300,000 | 300,000 | ||||||
7.5% Senior Notes due 2013 |
363,823 | | ||||||
7.75% Senior Notes due 2015 |
236,691 | 150,000 | ||||||
6.875% Senior Notes due 2016 |
200,000 | | ||||||
Discount on senior notes |
(26,959 | ) | (15,482 | ) | ||||
Discount for interest rate swap and swaption (b) |
(339 | ) | (18,122 | ) | ||||
Total notes payable and long-term debt |
$ | 2,057,713 | $ | 1,651,198 | ||||
(a) | This amount was classified as long-term debt based on our ability and intent to satisfy this obligation with funding from our bank credit facility. |
(b) | See Note 10 for further discussion related to these instruments. |
We have a $350 million revolving bank credit facility (with a committed borrowing base of $350 million) which matures in May 2007. As of December 31, 2003, we had no outstanding borrowings under this facility and utilized $35.8 million of the facility for various letters of credit. Borrowings under the facility are collateralized by certain producing oil and gas properties and bear interest at either the reference rate of Union Bank of California, N.A., or London Interbank Offered Rate (LIBOR), at our option, plus a margin that varies according to our senior unsecured long-term debt rating. The unused portion of the facility is subject to an annual commitment fee of 0.375%. Interest is payable quarterly. The collateral value and borrowing base are redetermined periodically.
The credit facility agreement contains various covenants and restrictive provisions which limit our ability to incur additional indebtedness, sell properties, pay dividends, purchase or redeem our capital stock, make investments or loans, purchase certain of our senior notes and create liens. The credit facility agreement requires us to maintain a current ratio (as defined) of at least 1 to 1 and a fixed charge coverage ratio (as defined) of at least 2.5 to 1. At December 31, 2003, our current ratio was 1.6 to 1 and our fixed charge coverage ratio was 4.8 to 1. If we should fail to perform our obligations under these and other covenants, the revolving credit commitment could be terminated and any outstanding borrowings under the facility could be declared immediately due and payable. Such acceleration, if involving a principal amount of $10 million or more, would constitute an event of default under our senior note indentures, which could in turn result in the acceleration of our senior note indebtedness. The credit facility agreement also has cross default provisions that apply to other indebtedness we may have with an outstanding principal amount in excess of $25.0 million.
80
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
The aggregate scheduled maturities of notes payable and long-term debt for the five fiscal years ending December 31, 2008 and thereafter were as follows as of December 31, 2003 ($ in thousands):
2004 |
$ | 42,137 | |
2005 |
| ||
2006 |
| ||
2007 |
| ||
2008 |
209,815 | ||
After 2008 |
1,833,059 | ||
$ | 2,085,011 | ||
4. Contingencies and Commitments
Royalty Owner Litigation. Royalty owners have commenced litigation against a number of oil and gas producers claiming that amounts paid for production attributable to the royalty owners interest violates the terms of applicable leases and state law, that deductions from the proceeds of oil and gas production are unauthorized under the leases, and that amounts received by upstream sellers should be used to compute the amounts paid to the royalty owners. Typically this litigation has taken the form of class action suits.
In one such lawsuit that has been filed against Chesapeake and a subsidiary, the parties have entered into a settlement agreement, effective December 31, 2003, pursuant to which we have agreed to refund Oklahoma royalty owners $10.5 million, including interest. The refund amount includes $3.6 million relating to marketing fees which we have previously paid into the court ($0.3 million and $3.3 million were charged to provisions for legal settlements in 2003 and 2002, respectively), $2.4 million relating to gathering, compression, dehydration, field fuel or transportation costs with respect to certain of our gathering systems, and $4.5 million relating to other such gathering system costs and other claims. The lawsuit has been certified for settlement as a class action, and the court has preliminarily approved the settlement for the purpose of giving class members notice of the proposed settlement and setting a fairness hearing on May 6, 2004. Assuming the settlement is approved and is not appealed, the distribution of settlement proceeds is scheduled to occur prior to October 5, 2004. The class members are substantially all royalty owners under Oklahoma oil and gas leases or pooling orders covering wells in which any of Chesapeake, its subsidiaries or their predecessors is a joint working interest owner or operator. In connection with the settlement, we incurred a $6.9 million charge in the third and fourth quarter of 2003 for litigation and settlement costs. We believe the potential liability associated with post-production claims made against us by royalty owners in three other pending lawsuits filed as class actions is not material. There has been no class certification in any of these cases.
Other Litigation. Chesapeake is currently involved in various other disputes incidental to its business operations. Management, after consultation with legal counsel, is of the opinion that the final resolution of all such currently pending or threatened litigation is not likely to have a material adverse effect on our consolidated financial position or results of operations.
Employment Agreements with Officers. Chesapeake has employment agreements with its chief executive officer, chief operating officer, chief financial officer and various other senior management personnel, which provide for annual base salaries, bonus compensation and various benefits. The agreements provide for the continuation of salary and benefits for varying terms in the event of termination of employment without cause. The agreements with the chief executive officer and chief operating officer have terms of five years commencing January 1, 2004. The term of each agreement is automatically extended for one additional year on each January 31 unless one of the parties provides 30 days notice of non-extension. The agreements with the chief
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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
financial officer and other senior managers expire on September 30, 2006. The companys employment agreements with the executive officers provide for payments in the event of a change in control. The chief executive officer and chief operating officer are each entitled to receive a payment in the amount of five times his base compensation and the prior years benefits, plus a tax gross-up payment, and the chief financial officer and other officers are each entitled to receive a payment in the amount of two times his or her base compensation plus bonuses paid during the prior year.
Environmental Risk. Due to the nature of the oil and gas business, Chesapeake and its subsidiaries are exposed to possible environmental risks. Chesapeake has implemented various policies and procedures to avoid environmental contamination and risks from environmental contamination. Chesapeake conducts periodic reviews, on a company-wide basis, to identify changes in our environmental risk profile. These reviews evaluate whether there is a probable liability, its amount, and the likelihood that the liability will be incurred. The amount of any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate cost of employees who are expected to devote a significant amount of time directly to any possible remediation effort. We manage our exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. Depending on the extent of an identified environmental problem, Chesapeake may exclude a property from the acquisition, require the seller to remediate the property to our satisfaction, or agree to assume liability for the remediation of the property. Chesapeake has historically not experienced any significant environmental liability, and is not aware of any potential material environmental issues or claims at December 31, 2003.
Other. We completed an acquisition of Permian Basin and Mid-Continent oil and gas assets from Concho Resources Inc. in January 2004. We paid approximately $420 million in cash for these assets, $10 million of which was paid in 2003.
We also completed an acquisition of South Texas gas assets in January 2004. We paid approximately $65 million for these assets, $3.3 million of which was paid in 2003.
Chesapeake has entered into various operating leases for office space and equipment. Future minimum lease payments required as of December 31, 2003 related to these operating leases are as follows ($ in thousands):
2004 |
$ | 2,353 | |
2005 |
1,547 | ||
2006 |
622 | ||
2007 |
316 | ||
2008 |
184 | ||
After 2008 |
415 | ||
Total |
$ | 5,437 | |
Rent expense, including short-term rentals, for the years ended December 31, 2003, 2002 and 2001 was $13.1 million, $7.7 million and $6.4 million, respectively.
82
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
5. Income Taxes
The components of the income tax provision (benefit) for each of the periods presented below are as follows:
Years Ended December 31, | |||||||||||
2003 |
2002 |
2001 | |||||||||
($ in thousands) | |||||||||||
Current |
$ | 5,000 | $ | (1,822 | ) | $ | 3,565 | ||||
Deferred: |
|||||||||||
United States |
186,824 | 28,676 | 136,991 | ||||||||
Foreign |
| | 3,736 | ||||||||
Total |
$ | 191,824 | (1) | $ | 26,854 | $ | 144,292 | ||||
(1) | Includes $1,464,000 of tax expense related to the change in accounting principle. |
The effective income tax expense (benefit) differed from the computed expected federal income tax expense (benefit) on earnings before income taxes for the following reasons:
Years Ended December 31, |
||||||||||||
2003 |
2002 |
2001 |
||||||||||
($ in thousands) | ||||||||||||
Computed expected federal income tax provision |
$ | 176,682 | $ | 23,499 | $ | 126,594 | ||||||
State income taxes and other |
10,968 | 3,492 | 15,061 | |||||||||
Change in valuation allowance |
4,364 | | 2,441 | |||||||||
Tax percentage depletion |
(190 | ) | (137 | ) | (195 | ) | ||||||
Foreign taxes in excess of U.S. statutory rate |
| | 391 | |||||||||
$ | 191,824 | $ | 26,854 | $ | 144,292 | |||||||
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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
Deferred income taxes are provided to reflect temporary differences in the basis of net assets for income tax and financial reporting purposes. The tax-effected temporary differences and tax loss carryforwards which comprise deferred taxes are as follows:
Years Ended December 31, |
||||||||
2003 |
2002 |
|||||||
($ in thousands) | ||||||||
Deferred tax liabilities: |
||||||||
Acquisition, exploration and development costs and related depreciation, depletion and amortization |
$ | (342,396 | ) | $ | (265,837 | ) | ||
Deferred tax assets: |
||||||||
Net operating loss carryforwards |
$ | 154,784 | $ | 256,547 | ||||
Derivative liabilities and other |
31,857 | 18,837 | ||||||
Percentage depletion carryforwards |
3,228 | 3,063 | ||||||
Alternative minimum tax credits |
5,011 | 11 | ||||||
Deferred tax assets |
$ | 194,880 | $ | 278,458 | ||||
Net deferred tax asset (liability) |
(147,516 | ) | 12,621 | |||||
Less: Valuation allowance |
(6,805 | ) | (2,441 | ) | ||||
Total deferred tax asset (liability) |
$ | (154,321 | )(1) | $ | 10,180 | |||
Reflected in accompanying balance sheets as: |
||||||||
Current deferred income tax asset |
$ | 36,705 | $ | 8,109 | ||||
Non-current deferred income tax asset |
| 2,071 | ||||||
Non-current deferred income tax liability |
(191,026 | ) | | |||||
$ | (154,321 | ) | $ | 10,180 | ||||
(1) | Activity during 2003 includes a net asset of $4.9 million related to acquisitions, a benefit of $10.2 million related to derivative instruments, and a benefit of $7.2 million related to stock option compensation. These items were not recorded as part of the provision for deferred income taxes. |
SFAS 109 requires that we record a valuation allowance when it is more likely than not that some portion or all of deferred tax assets will not be realized. As of December 31, 2001, we determined that it is more likely than not that $2.4 million of the net deferred tax assets related to Louisiana net operating losses generated by Louisiana properties will not be realized and have recorded a valuation allowance equal to such amounts. During 2003, we determined that it was more likely than not that an additional $4.4 million of the deferred tax assets related to Louisiana net operating losses will not be realized and we recorded an additional valuation allowance equal to such amounts.
As of December 31, 2003, we classified $36.7 million of deferred tax assets as current that were attributable to the current portion of derivative liabilities and other current temporary differences. As of December 31, 2002, we classified $8.1 million of deferred tax assets as current that were attributable to the current portion of derivative liabilities and other current temporary differences.
At December 31, 2003, Chesapeake had federal income tax net operating loss (NOL) carryforwards of approximately $403.8 million. Additionally, we had $71.5 million of alternative minimum tax (AMT) NOL carryforwards available as a deduction against future AMT income and approximately $8.5 million of percentage depletion carryforwards. During 2003, we estimate that we will be able to utilize approximately $253.3 million of NOLs to reduce our 2003 federal taxable income. The NOL carryforwards expire from 2012 through 2022.
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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
The value of these carryforwards depends on the ability of Chesapeake to generate taxable income. In addition, for AMT purposes, only 90% of AMT income in any given year may be offset by AMT NOLs. A summary of our NOLs follows:
NOL |
AMT NOL | |||||
($ in thousands) | ||||||
Expiration Date: |
||||||
December 31, 2012 |
$ | 171,586 | $ | | ||
December 31, 2018 |
42,187 | | ||||
December 31, 2019 |
139,222 | 57,414 | ||||
December 31, 2020 |
5,156 | 1,393 | ||||
December 31, 2021 |
12,701 | 5,313 | ||||
December 31, 2022 |
32,988 | 7,399 | ||||
Total |
$ | 403,840 | $ | 71,519 | ||
The ability of Chesapeake to utilize NOL carryforwards to reduce future federal taxable income and federal income tax of Chesapeake is subject to various limitations under the Internal Revenue Code of 1986, as amended. The utilization of such carryforwards may be limited upon the occurrence of certain ownership changes, including the issuance or exercise of rights to acquire stock, the purchase or sale of stock by 5% stockholders, as defined in the Treasury regulations, and the offering of stock by us during any three-year period resulting in an aggregate change of more than 50% in the beneficial ownership of Chesapeake.
In the event of an ownership change (as defined for income tax purposes), Section 382 of the Code imposes an annual limitation on the amount of a corporations taxable income that can be offset by these carryforwards. The limitation is generally equal to the product of (i) the fair market value of the equity of the company multiplied by (ii) a percentage approximately equivalent to the yield on long-term tax exempt bonds during the month in which an ownership change occurs. In addition, the limitation is increased if there are recognized built-in gains during any post-change year, but only to the extent of any net unrealized built-in gains (as defined in the Code) inherent in the assets sold. Chesapeake had an ownership change in March 1998 which triggered a limitation. Certain NOLs acquired through various acquisitions are also subject to limitations.
The following table summarizes our net operating losses as of December 31, 2003 and any related limitations:
Total |
Limited |
Annual Limitation | |||||||
($ in thousands) | |||||||||
Net operating loss |
$ | 403,840 | $ | 312,140 | $ | 46,658 | |||
AMT net operating loss |
$ | 71,519 | $ | 71,519 | $ | 21,081 |
Although no assurances can be made, we do not believe that an additional ownership change has occurred as of December 31, 2003. Equity transactions after the date hereof by Chesapeake or by 5% stockholders (including relatively small transactions and transactions beyond our control) could cause an ownership change and therefore a limitation on the annual utilization of NOLs.
6. Related Party Transactions
As of December 31, 2003, we had accrued accounts receivable from our chief executive officer and chief operating officer $0.3 million and $2.6 million, respectively, representing billings for December 2003 which
85
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
were paid in January 2004. Since Chesapeake was founded in 1989, our CEO and COO have acquired small working interests in certain of our oil and gas properties by participating in our drilling activities. Joint interest billing accounts of the CEO and COO are settled in cash. Under their employment agreements, the CEO and COO are permitted to participate in all, or none, of the wells drilled by or on behalf of Chesapeake during each calendar quarter, but they are not allowed to participate only in selected wells. A participation election is required to be received by the Compensation Committee of Chesapeakes board of directors 30 days prior to the start of a quarter. Their participation is permitted only under the terms outlined in their employment agreements, which, among other things, limit their individual participation to a maximum working interest of 2.5% in a well and prohibits participation in situations where Chesapeakes working interest would be reduced below 12.5% as a result of their participation.
In October 2001, we sold Chesapeake Canada Corporation, a wholly-owned subsidiary, for net proceeds of approximately $143.0 million. Our CEO and COO each received $2.0 million related to their fractional ownership interest in these Canadian assets, which they acquired and paid for pursuant to the terms of their employment agreements. The portion of the proceeds allocated to our CEO and COO was based upon the estimated fair values of the assets sold as determined by management and the independent members of our board of directors using a methodology similar to that used by Chesapeake for acquisitions of assets from disinterested third parties.
During 2003, 2002 and 2001, we paid legal fees of $2,123,000, $600,000, and $391,000, respectively, for legal services provided by a law firm of which a director is a member.
7. Employee Benefit Plans
We maintain three deferred compensation plans. They include the following:
| The Chesapeake Energy Corporation Savings and Incentive Stock Bonus Plan, |
| The 401(k) Make-Up Plan and |
| The Deferred Compensation Plan. |
The Chesapeake Energy Corporation Savings and Incentive Stock Bonus Plan is a qualified 401(k) profit sharing plan. Eligible employees may elect to defer voluntary contributions to the plan. The amount an employee can contribute is subject to the plan contribution limitations and annual dollar limits as set out by the IRS. Chesapeake currently matches up to 15% of the employees annual compensation dollar for dollar with Chesapeakes common stock purchased in the open-market. The Company contributed $4.0 million, $2.9 million and $2.0 million to this plan during 2003, 2002 and 2001, respectively.
In January 2003, Chesapeake established the 401(k) Make-Up Plan and the Deferred Compensation Plan, both of which are nonqualified deferred compensation plans as defined by the Internal Revenue Service. Eligible employees that complete a timely election to defer compensation to Chesapeakes 401(k) plan in excess of the Internal Revenue Service imposed maximum, may defer compensation up to a total of 60% of their salary and 100% of performance bonus in the aggregate for the 401(k) Plan, 401(k) Make-Up Plan and the Deferred Compensation Plan.
The 401(k) Make-Up Plan allows employees receiving a base salary and bonus compensation of at least $90,000 during the prior 12 month period, and having a minimum of five years of service, to defer additional compensation beyond the IRS imposed limit applicable to our Savings and Incentive Stock Bonus Plan. The Company provides a matching contribution equal to 100%, up to 15% of the participating employees compensation. The employer match is payable in common stock. The 401(k) Make-Up Plan is an unsecured
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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
deferred compensation plan and participants are general creditors of the Company as to their deferred compensation in the plan. We contributed $1.2 million to this plan during 2003.
Under the Deferred Compensation Plan, eligible employees and non-employee directors that complete a timely election may defer receipt of a portion of their compensation to some future date. Chesapeake has no requirement to make a matching contribution to the Deferred Compensation Plan.
Any assets placed in trust by Chesapeake to fund future obligations of the 401(k) Make-Up Plan and the Deferred Compensation Plan are subject to the claims of creditors in the event of insolvency or bankruptcy.
8. Major Customers and Segment Information
Sales to individual customers constituting 10% or more of total revenues were as follows:
Year Ended December 31, |
Customer |
Amount |
Percent of Total Revenues |
|||||
($ in thousands) | ||||||||
2003 |
Reliant Energy Services | $ | 189,140 | 11 | % | |||
2003 |
Duke Energy Field Services | $ | 163,329 | 10 | % | |||
2002 |
Continental Natural Gas | $ | 123,813 | 17 | % | |||
2002 |
Reliant Energy Services | $ | 96,682 | 13 | % | |||
2002 |
Duke Energy Field Services | $ | 83,115 | 11 | % | |||
2001 |
Reliant Energy Services | $ | 131,885 | 14 | % | |||
2001 |
Continental Natural Gas | $ | 120,500 | 12 | % |
Chesapeake has two reportable segments under SFAS No. 131, Disclosures about Segments of an Enterprise and Related Information, consisting of exploration and production and marketing. The reportable segment information can be derived from Note 2 as Chesapeake Energy Marketing, Inc., Mayfield Processing, L.L.C. and MidCon Compression, L.P., which are our marketing subsidiaries, are the only non-guarantor subsidiaries. Chesapeake Energy Marketing, Inc. was a non-guarantor subsidiary for all periods presented. Mayfield Processing, L.L.C. and MidCon Compression, L.P. were established as non-guarantor subsidiaries during 2003.
9. Stockholders Equity and Stock-Based Compensation
In November 2003, we issued 1,725,000 shares of 5.00% cumulative convertible preferred stock, par value $.01 per share and liquidation preference $100 per share, in a public offering. As of December 31, 2003, 1,725,000 shares remain outstanding. The net proceeds from the offering were $167.6 million. Each preferred share is convertible at any time at the option of the holder into 6.0962 shares of common stock, subject to adjustment. At December 31, 2003, 10,515,945 shares of our common stock were reserved for issuance upon conversion. The conversion rate is based on an initial conversion price of $16.40 per common share, plus cash in lieu of fractional shares. The preferred stock is subject to mandatory conversion, at our option, (1) on or after November 18, 2006 at the same rate, if the market price of the common stock equals or exceeds 130% of the conversion price, or $21.32, for a specified time period and (2) on or after November 18, 2008, at the lower of conversion price and the then current market price of common stock if there are less than 250,000 shares of preferred stock outstanding at the time. Annual cumulative cash dividends of $5.00 per share are payable quarterly on the fifteenth day of each February, May, August and November.
In March 2003, we issued 23,000,000 shares of Chesapeake common stock at $8.10 per share in a public offering for net proceeds of $177.4 million.
In March 2003, we issued 4,600,000 shares of 6.00% cumulative convertible preferred stock, par value $.01 per share and liquidation preference $50 per share, in a private offering, all of which are outstanding as of
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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
December 31, 2003. The net proceeds from the offering were $222.8 million. Each preferred share is convertible at any time at the option of the holder into 4.8605 shares of common stock, subject to adjustment. At December 31, 2003, 22,358,300 shares of common stock were reserved for issuance upon conversion. The conversion rate is based on an initial conversion price of $10.287 per common share, plus cash in lieu of fractional shares. The preferred stock is subject to mandatory conversion at our option, (1) on or after March 20, 2006 at the same rate if the market price of the common stock equals or exceeds 130% of the conversion price, or $13.37, at the time and (2) on or after March 20, 2008 at the lower of the conversion price and the then current market price of the common stock if there are less than 250,000 shares of preferred stock outstanding at the time. Annual cumulative cash dividends of $3.00 per share are payable quarterly on the fifteenth day of March, June, September and December.
In December 2002, we issued 23,000,000 shares of Chesapeake common stock at $7.50 per share in a public offering for net proceeds of $164.1 million.
On November 13, 2001, we issued 3,000,000 shares of 6.75% cumulative convertible preferred stock, par value $.01 per share and liquidation preference $50 per share, in a private offering. As of December 31, 2003, 2,998,000 shares remain outstanding. The net proceeds from the offering were $145.1 million. Each preferred share is convertible at any time at the option of the holder into 6.4935 shares of our common stock, subject to adjustment. At December 31, 2003, 19,467,513 shares of our common stock were reserved for issuance upon conversion. The conversion rate is based on an initial conversion price of $7.70 per common share, plus cash in lieu of fractional shares. The preferred stock is subject to mandatory conversion, at our option, (1) on or after November 20, 2004 at the same rate if the market price of the common stock equals or exceeds 130% of the conversion price, or $10.01, at the time and (2) on or after November 20, 2006 at the lower of the conversion price and the then current market price of the common stock if there are less than 250,000 shares of preferred stock outstanding at the time. Annual cumulative cash dividends of $3.375 per share are payable quarterly on the fifteenth day of each February, May, August and November.
On March 30, 2001, we issued 1,117,216 shares of Chesapeake common stock in exchange for 49.5% of RAM Energy, Inc.s, outstanding common stock. Our shares were valued at $8.854 each, or $9.9 million in total. In the third quarter of 2001, we made make-whole cash payments of $3.3 million to the former RAM shareholders. In December 2001, we sold all the RAM shares we owned for minimal consideration.
In January 2001, we acquired Gothic Energy Corporation in a stock merger. We issued 3,989,813 common shares in exchange for Gothic common shares at the rate of 0.1908 of a share of Chesapeake common stock for each share of Gothic common stock. In addition, outstanding warrants and options to purchase Gothic common stock were converted to the right to purchase Chesapeake common stock based on the merger exchange ratio. As of December 31, 2003, 0.4 million shares of Chesapeake common stock may be purchased upon the exercise of such warrants and options at an average price of $14.55 per share.
In 2001, holders of our 7% cumulative convertible preferred stock converted 622,768 shares into 4,480,171 shares of common stock (at a conversion price of $6.95 per share), and we redeemed the remaining 1,269 shares of preferred stock for 7,239 shares of common stock and $3,000 of cash (at a redemption price of $52.45 per share, paid in 5.7 shares of common stock and cash of $2.45).
Stock-Based Compensation Plans
Under Chesapeakes 2003 Stock Incentive Plan, restricted stock and incentive and nonqualified stock options to purchase our common stock may be awarded to employees and consultants of Chesapeake. Subject to
88
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
any adjustments as provided by the plan, the aggregate number of shares which may be issued and sold may not exceed 10 million shares. The maximum period for exercise of an option may not be more than ten years from the date of grant and the exercise price may not be less than the fair market value of the shares underlying the option on the date of grant. Restricted stock and options granted become vested at dates determined by the compensation committee of the board of directors. No restricted stock or option can be granted under this plan after April 14, 2013. This plan has been approved by our shareholders. No options or restricted shares were issued during 2003 from this plan.
Under Chesapeakes 2003 Stock Award Plan for Non-Employee Directors, 10,000 shares of Chesapeakes common stock will be awarded to each newly appointed non-employee director on his or her first day of service. Subject to any adjustments as provided by the plan, the aggregate number of shares which may be issued may not exceed 50,000 shares. This plan was not required to be approved by our shareholders. In 2003, 10,000 shares of common stock were awarded to a new director from this plan.
Under Chesapeakes 2002 Non-Employee Director Stock Option Plan, non-qualified options to purchase our common stock may be granted to members of our board of directors who are not Chesapeake employees. Subject to any adjustments as provided by this plan, the aggregate number of shares which may be issued and sold may not exceed 500,000 shares. The maximum period for exercise of an option may not be more than ten years from the date of grant, and the exercise price may not be less than the fair market value of the shares underlying the options on the date of grant. Options granted become exercisable at dates determined by the compensation committee of the board of directors. This plan also contains a formula award provision pursuant to which each non-employee director receives every quarter a ten-year immediately exercisable option to purchase 10,000 shares of common stock at an exercise price equal to the fair market value of the shares on the date of grant. No options can be granted under this plan after April 14, 2012. This plan has been approved by our shareholders.
Under Chesapeakes 2001 and 2002 Stock Option Plans, incentive and nonqualified stock options to purchase our common stock may be granted to employees and consultants of Chesapeake. Subject to any adjustment as provided by the plans, the aggregate number of shares which may be issued and sold may not exceed 3,200,000 and 3,000,000 shares, respectively. The maximum period for exercise of an option may not be more than ten years from the date of grant and the exercise price may not be less than the fair market value of the shares underlying the options on the date of grant; provided, however, nonqualified stock options not exceeding 10% of the options issuable under each plan may be granted at an exercise price which is not less than 85% of the grant date fair market value. Options granted become exercisable at dates determined by the compensation committee of the board of directors. No options can be granted under the 2001 plan after February 28, 2011 and under the 2002 plan after February 29, 2012. These plans have been approved by our shareholders.
Under Chesapeakes 2000 and 2001 Executive Officer Stock Option Plans, nonqualified stock options to purchase our common stock may be granted to executive officers of Chesapeake. Subject to any adjustment as provided by the plan, the aggregate number of shares which may be sold may not exceed 2,500,000 shares under the 2000 plan and 4,000,000 shares under the 2001 plan and must represent issued shares which have been reacquired by Chesapeake. The maximum period for exercise of an option may not be more than ten years from the date of grant and the exercise price may not be less than the fair market value of the shares underlying the options on the date of grant; provided, however, nonqualified stock options not exceeding 10% of the options issuable under this plan may be granted at an exercise price which is not less than 85% of the grant date fair market value. Options granted become exercisable at dates determined by the compensation committee of the board of directors. No options can be granted under the 2000 plan after April 25, 2010 or after April 14, 2011 under the 2001 plan. These plans were not required to be approved by our shareholders.
89
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
Under Chesapeakes 1999 Stock Option Plan, 2000 Employee Stock Option Plan, 2001 Nonqualified Stock Option Plan and 2002 Nonqualified Stock Option Plan, nonqualified stock options to purchase our common stock may be granted to employees and consultants of Chesapeake. Subject to any adjustment as provided by the respective plans, the aggregate number of shares which may be issued and sold may not exceed 3,000,000 shares from each of the 1999, 2000 and 2001 plans and 4,000,000 from the 2002 plan. The maximum period for exercise of an option may not be more than ten years from the date of grant and the exercise price may not be less than the fair market value of the shares underlying the options on the date of grant; provided, however, nonqualified stock options not exceeding 10% of the options issuable under this plan may be granted at an exercise price which is not less than 85% of the grant date fair market value. Options granted become exercisable at dates determined by the compensation committee of the board of directors. No options can be granted after March 4, 2009 under the 1999 plan, after April 25, 2010 under the 2000 plan, after April 14, 2011 under the 2001 plan, and after February 29, 2012 under the 2002 plan. These plans were not required to be approved by our shareholders.
Under Chesapeakes 1994 Stock Option Plan and 1996 Stock Option Plan, incentive and nonqualified stock options to purchase our common stock may be granted to employees and consultants of Chesapeake. Subject to any adjustment as provided by the respective plans, the aggregate number of shares which may be issued and sold may not exceed 4,886,910 shares under the 1994 plan and 6,000,000 shares under the 1996 plan. The maximum period for exercise of an option may not be more than ten years from the date of grant and the exercise price of incentive stock options may not be less than the fair market value of the shares underlying the options on the date of grant. The exercise price of nonqualified stock options under the 1996 plan must be at least 85% of the fair market value of the shares underlying the options on the date of grant. Options granted become exercisable at dates determined by the compensation committee of the board of directors. No options can be granted under the 1994 plan after October 17, 2004 or under the 1996 plan after October 14, 2006. These plans were approved by our shareholders.
Chesapeakes 1992 Nonstatutory Stock Option Plan terminated on December 10, 2002. The last option grants under this plan were made in April 2002. The plan permitted grants of nonqualified stock options to purchase our common stock to directors of Chesapeake. Subject to any adjustment as provided by the plan, the aggregate number of shares which may be issued and sold may not exceed 3,132,000 shares. All options granted under the plan were made pursuant to a formula set forth in the plan. Under this provision, each director who was not an executive officer received every quarter a ten-year immediately exercisable option to purchase a specified number of shares of common stock at an option price equal to the fair market value of the shares on the date of grant. This plan was approved by our shareholders.
90
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
A summary of our stock option activity and related information follows:
Years Ended December 31, | |||||||||||||||||||||
2003 |
2002 |
2001 | |||||||||||||||||||
Options |
Weighted-Avg. Exercise Price |
Options |
Weighted-Avg. Exercise Price |
Options |
Weighted-Avg. Exercise Price | ||||||||||||||||
Outstanding beginning of period |
24,576,775 | $ | 4.40 | 23,232,655 | $ | 3.96 | 18,399,162 | $ | 2.83 | ||||||||||||
Granted |
7,168,623 | 8.98 | 4,170,700 | 5.38 | 7,422,300 | 6.18 | |||||||||||||||
Exercised |
(4,262,915 | ) | 3.04 | (2,519,429 | ) | 1.83 | (2,264,374 | ) | 1.83 | ||||||||||||
Canceled/forfeited |
(249,198 | ) | 8.51 | (307,151 | ) | 5.30 | (324,433 | ) | 5.68 | ||||||||||||
Outstanding end of period |
27,233,285 | $ | 5.78 | 24,576,775 | $ | 4.40 | 23,232,655 | $ | 3.96 | ||||||||||||
Exercisable end of period |
12,131,098 | $ | 4.26 | 11,014,775 | $ | 3.55 | 7,495,255 | $ | 2.88 | ||||||||||||
Shares authorized for future grants |
11,018,225 | 7,602,339 | 3,836,856 | ||||||||||||||||||
Fair value of options granted during the period |
$ | 3.36 | $ | 2.31 | $ | 3.34 | |||||||||||||||
The following table summarizes information about stock options outstanding at December 31, 2003:
Options Outstanding |
Options Exercisable | |||||||||||
Range of Exercise Prices |
Number Outstanding |
Weighted-Avg. Remaining Contractual Life |
Weighted- Exercise Price |
Number Exercisable |
Weighted-Avg. Exercise Price | |||||||
$ 0.56 $ 1.13 | 3,124,783 | 4.78 | $ | 1.07 | 3,124,783 | $ | 1.07 | |||||
1.38 4.00 | 4,048,937 | 5.36 | 3.16 | 2,877,588 | 3.16 | |||||||
4.06 5.20 | 3,511,411 | 8.53 | 5.19 | 779,478 | 5.17 | |||||||
5.35 5.56 | 2,362,240 | 6.87 | 5.56 | 1,637,858 | 5.56 | |||||||
5.60 6.11 | 6,381,917 | 7.72 | 6.10 | 2,912,535 | 6.10 | |||||||
6.13 7.74 | 511,185 | 6.27 | 6.91 | 376,226 | 6.87 | |||||||
7.80 7.80 | 3,325,150 | 9.02 | 7.80 | | | |||||||
7.81 10.01 | 418,437 | 8.58 | 8.56 | 244,505 | 8.73 | |||||||
10.08 10.08 | 3,077,850 | 9.48 | 10.08 | | | |||||||
10.10 30.63 | 471,375 | 8.04 | 14.49 | 178,125 | 20.24 | |||||||
$ 0.56 $ 30.63 | 27,233,285 | 7.41 | $ | 5.78 | 12,131,098 | $ | 4.26 | |||||
The exercise of certain stock options results in state and federal income tax benefits to us related to the difference between the market price of the common stock at the date of disposition and the option price. During 2003, 2002 and 2001, we recognized tax benefits of $7.1 million, $2.4 million and $5.4 million, which were recorded as adjustments to additional paid-in capital and deferred income taxes with respect to such benefits.
91
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
Shareholder Rights Plan
Chesapeake maintains a shareholder rights plan designed to deter coercive or unfair takeover tactics, to prevent a person or group from gaining control of Chesapeake without offering fair value to all shareholders and to deter other abusive takeover tactics which are not in the best interest of shareholders.
Under the terms of the plan, each share of common stock is accompanied by one right, which given certain acquisition and business combination criteria, entitles the shareholder to purchase from Chesapeake one one-thousandth of a newly issued share of Series A preferred stock at a price of $25.00, subject to adjustment by Chesapeake.
The rights become exercisable 10 days after Chesapeake learns that an acquiring person (as defined in the plan) has acquired 15% or more of the outstanding common stock of Chesapeake or 10 business days after the commencement of a tender offer which would result in a person owning 15% or more of such shares. Chesapeake may redeem the rights for $0.01 per right within ten days following the time Chesapeake learns that a person has become an acquiring person. The rights will expire on July 27, 2008, unless redeemed earlier by Chesapeake.
10. Financial Instruments and Hedging Activities
Oil and Gas Hedging Activities
Our results of operations and operating cash flows are impacted by changes in market prices for oil and gas. To mitigate a portion of the exposure to adverse market changes, we have entered into various derivative instruments. As of December 31, 2003, our oil and gas derivative instruments were comprised of swaps, cap-swaps, basis protection swaps and call options. These instruments allow us to predict with greater certainty the effective oil and gas prices to be received for our hedged production. Although derivatives often fail to achieve 100% effectiveness for accounting purposes, we believe our derivative instruments continue to be highly effective in achieving the risk management objectives for which they were intended.
| For swap instruments, we receive a fixed price for the hedged commodity and pay a floating market price, as defined in each instrument, to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty. |
| For cap-swaps, Chesapeake receives a fixed price and pays a floating market price. The fixed price received by Chesapeake includes a premium in exchange for a cap limiting the counterpartys exposure. In other words, there is no limit to Chesapeakes exposure but there is a limit to the downside exposure of the counterparty. Because this derivative includes a written put option (i.e., the cap), cap-swaps do not qualify for designation as cash flow hedges (in accordance with SFAS 133) since the combination of the hedged item and the written put option does not provide as much potential for favorable cash flows as exposure to unfavorable cash flows. |
| Basis protection swaps are arrangements that guarantee a price differential of oil or gas from a specified delivery point. Chesapeake receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract. |
| For call options, Chesapeake receives a cash premium from the counterparty in exchange for the sale of a call option. If the market price exceeds the fixed price of the call option, then Chesapeake pays the counterparty such excess. If the market price settles below the fixed price of the call option, no payment is due from Chesapeake. |
92
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
Chesapeake enters into counter-swaps from time to time for the purpose of locking in the value of a swap. Under the counter-swap, Chesapeake receives a floating price for the hedged commodity and pays a fixed price to the counterparty. The counter-swap is 100% effective in locking in the value of a swap since subsequent changes in the market value of the swap are entirely offset by subsequent changes in the market value of the counter-swap. We refer to this locked-in value as a locked swap. At the time Chesapeake enters into a counter-swap, Chesapeake removes the original swaps designation as a cash flow hedge and classifies the original swap as a non-qualifying hedge under SFAS 133. The reason for this new designation is that collectively the swap and the counter-swap no longer hedge the exposure to variability in expected future cash flows. Instead, the swap and counter-swap effectively lock in a specific gain (or loss) that will be unaffected by subsequent variability in oil and gas prices. Any locked-in gain or loss is recorded in accumulated other comprehensive income and reclassified to oil and gas sales in the month of related production.
In accordance with FASB Interpretation No. 39, Chesapeake nets the value of its derivative arrangements with the same counterparty in the accompanying consolidated balance sheets, to the extent that a legal right of set off exists.
Gains or losses from derivative transactions are reflected as adjustments to oil and gas sales on the consolidated statements of operations. Pursuant to SFAS 133, certain derivatives do not qualify for designation as cash flow hedges. Changes in the fair value of these non-qualifying derivatives that occur prior to their maturity (i.e., temporary fluctuations in value) are reported currently in the consolidated statements of operations as unrealized gains (losses) within oil and gas sales. Unrealized gains (losses) included in oil and gas sales in 2003, 2002 and 2001 were $10.5 million, $(87.3) million and $84.8 million, respectively.
Following provisions of SFAS 133, changes in the fair value of derivative instruments designated as cash flow hedges, to the extent they are effective in offsetting cash flows attributable to the hedged risk, are recorded in other comprehensive income until the hedged item is recognized in earnings. Any change in fair value resulting from ineffectiveness is recognized currently in oil and gas sales. We recorded a gain (loss) on ineffectiveness of $(9.2) million, $(3.6) million and $2.5 million in 2003, 2002 and 2001, respectively.
93
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
The estimated fair values of our oil and gas derivative instruments as of December 31, 2003 and 2002 are provided below. The associated carrying values of these instruments are equal to the estimated fair values.
December 31, |
||||||||
2003 |
2002 |
|||||||
($ in thousands) | ||||||||
Derivative assets (liabilities): |
||||||||
Fixed-price gas swaps |
$ | (44,794 | ) | $ | (21,523 | ) | ||
Fixed-price gas cap-swaps |
(18,608 | ) | (50,732 | ) | ||||
Gas basis protection swaps |
46,205 | 8,227 | ||||||
Fixed-price gas counter-swaps |
| 37,048 | ||||||
Gas call options |
(17,876 | ) | | |||||
Fixed-price gas locked swaps |
1,777 | 16,498 | ||||||
Fixed-price crude oil swaps |
| (1,799 | ) | |||||
Fixed-price crude oil cap-swaps |
(11,692 | ) | (2,252 | ) | ||||
Estimated fair value |
$ | (44,988 | ) | $ | (14,533 | ) | ||
Based upon the market prices at December 31, 2003, we expect to transfer a loss of approximately $17.6 million from accumulated other comprehensive income to earnings during the next 12 months when the transactions actually close. All transactions hedged as of December 31, 2003 are expected to mature by December 31, 2007, with the exception of the basis protection swaps which extend through 2009.
Interest Rate Hedging
We also utilize hedging strategies to manage the exposure our fixed-rate senior notes have to interest rate changes. By entering into interest rate swaps, we convert a portion of our fixed rate debt to floating rate debt. To the extent the interest rate swaps have been designated as fair value hedges, changes in the fair value of the derivative instrument and the corresponding debt are reflected as adjustments to interest expense in the corresponding months covered by the derivative agreement.
The following describes interest rate swaps entered into during 2002 and 2003, all of which were terminated prior to contractual maturity for cash settlements ($ in thousands):
Date |
Fair Value at December 31, 2003 |
Date |
Cash Settlement Received |
Gains Recognized in 2002 |
Gains in 2003 |
Gains to be Recognized in 2004 | ||||||||||||
March 2002(a) |
$ | | July 2002 | $ | 7,500 | $ | 6,778 | (c) | $ | 599 | $ | 123 | ||||||
June 2002(b) |
| July 2002 | 1,130 | 1,130 | | | ||||||||||||
August 2003(b) |
870 | January 2004 | 940 | | 870 | 70 | ||||||||||||
August 2003(b) |
1,292 | January 2004 | 1,370 | | 1,292 | 78 |
(a) | This instrument was designated as a fair value hedge with changes in the fair value recorded as an adjustment to the debt. Upon termination of the hedging relationship, the previously recorded changes in the fair value of the debt are amortized to earnings over the term of the debt. |
(b) | These instruments were not designated as fair value hedges; therefore, changes in the fair value were recorded as adjustments to interest expense. |
(c) | Of this amount, $1.7 million was recognized as a reduction to the loss on repurchases of debt upon retirement of 7.875% notes. |
94
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
In April 2002, Chesapeake entered into a swaption with an unrelated counterparty with respect to its 8.5% senior notes due 2012. The notional amount of the swaption was $142.7 million, which was the principal amount then outstanding under the 8.5% senior notes. The 8.5% senior notes included a call option whereby Chesapeake may redeem the debt at declining redemption prices beginning in March 2004. Under the swaption, the counterparty received the option to elect whether or not to enter into an interest rate swap with Chesapeake in March 2004, and Chesapeake received $7.8 million. The interest rate swap, if executed by the counterparty, requires Chesapeake to pay a fixed rate of 8.5% while the counterparty pays Chesapeake a floating rate of 6 month LIBOR plus 0.75%. Additionally, if the counterparty elects to enter into the interest rate swap, it may also elect to force Chesapeake to settle the transaction at the then current value of the interest rate swap.
According to SFAS 133, a fair value hedge relationship exists between the embedded call option in the 8.5% senior notes and the swaption. The fair value of the swaption is recorded on the consolidated balance sheets as a liability, and the carrying amount of the debt is adjusted by the change in the fair value of the call option subsequent to the initiation of the swaption. Any resulting differences are recorded currently as ineffectiveness in the consolidated statements of operations as an adjustment to interest expense.
During the third quarter 2003, we exchanged and subsequently retired $32.0 million of our 8.5% senior notes. The exchange of debt was treated as a modification rather than an extinguishment. Accordingly, the adjustment to the carrying value of the debt of $3.3 million related to the application of hedge accounting was reflected as a discount on the notes issued in the exchange transaction and will be amortized to interest expense using the effective interest method. During the fourth quarter 2003, we purchased and subsequently retired $106.4 million of the remaining $110.7 million of 8.5% senior notes pursuant to a tender offer and recorded a $12.0 million loss related to the removal of the fair value designation of the corresponding amount of the swaption. Temporary fluctuations in the fair value of the portion of the swaption no longer designated as a fair value hedge are recorded as adjustments to interest expense. We recorded a $3.3 million unrealized loss in interest expense during 2003 due to a decline in the fair value of the portion of the swapion no longer designated as a fair value hedge.
As of December 31, 2003, the remaining notional amount of the swaption designated as a fair value hedge was $4.3 million. We have recorded an adjustment to the carrying amount of the debt of $0.5 million which represents the temporary fluctuations in the fair value of the call option included in the $4.3 million principal amount of 8.5% senior notes. Since the inception of the swaption, we have recorded a change in the fair market value of the swaption from a $7.8 million liability to a $32.6 million liability, an increase of $24.8 million. We have recorded as additional interest expense $5.6 million to reflect ineffectiveness after giving effect to the removal of the designation of a portion of the swaption as a fair value hedge under SFAS 133 as described previously.
On February 27, 2004, Chesapeake and the counterparty agreed to extend the counterpartys right to require Chesapeake to settle the transaction on March 15, 2004 to April 15, 2004. On March 10, 2004, the counterparty exercised its option to enter into the interest rate swap effective March 15, 2004. On April 15, 2004 and each succeeding March 15, the counterparty may elect to terminate the swap and cause it to be settled at the then current value of the interest rate swap. We may elect to terminate the swap and cause it to be settled at the then current value of the interest rate swap at any time during the term of the swap. Cash payments related to the interest rate swap, if initiated, or as a result of cash settlement at termination will be recorded as adjustments to interest expense.
95
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
Fair Value of Financial Instruments
The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of Statement of Financial Accounting Standards No. 107, Disclosures About Fair Value of Financial Instruments. We have determined the estimated fair value amounts by using available market information and valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.
The carrying values of items comprising current assets and current liabilities approximate fair values due to the short-term maturities of these instruments. We estimate the fair value of our long-term, fixed-rate debt using primarily quoted market prices. Our carrying amount for such debt, excluding discounts for interest rate swaps and the swaption, at December 31, 2003 and 2002 was $2,058.1 million and $1,669.3 million, respectively, compared to approximate fair values of $2,279.5 million and $1,744.7 million, respectively. The carrying amount for our 6.75% convertible preferred stock at December 31, 2003 was $149.9 million, with a fair value of $275.8 million. The carrying amount and fair value for our 6.00% convertible preferred stock at December 31, 2003 was $230.0 million. The carrying amount and fair value for our 5.00% preferred stock at December 31, 2003 was $172.5 million.
Concentration of Credit Risk
A significant portion of our liquidity is concentrated in cash and cash equivalents and derivative instruments that enable us to hedge a portion of our exposure to price volatility from producing oil and natural gas. These arrangements expose us to credit risk from our counterparties. Other financial instruments which potentially subject us to concentrations of credit risk consist principally of investments in equity instruments and accounts receivables. Our accounts receivable are primarily from purchasers of oil and natural gas products and exploration and production companies which own interests in properties we operate. The industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers may be similarly affected by changes in economic, industry or other conditions. We generally require letters of credit for receivables from customers which are judged to have sub-standard credit, unless the credit risk can otherwise be mitigated. Cash and cash equivalents are deposited with major banks or institutions and may at times exceed the federally insured limits.
96
11. Disclosures About Oil And Gas Producing Activities
Net Capitalized Costs
Evaluated and unevaluated capitalized costs related to Chesapeakes oil and gas producing activities are summarized as follows:
2003 |
||||
($ in thousands) | ||||
Oil and gas properties: |
||||
Proved |
$ | 6,221,576 | ||
Unproved |
227,331 | |||
Total |
6,488,907 | |||
Less accumulated depreciation, depletion and amortization |
(2,480,261 | ) | ||
Net capitalized costs |
$ | 3,968,646 | ||
2002 |
||||
($ in thousands) | ||||
Oil and gas properties: |
||||
Proved |
$ | 4,334,833 | ||
Unproved |
72,506 | |||
Total |
4,407,339 | |||
Less accumulated depreciation, depletion and amortization |
(2,123,773 | ) | ||
Net capitalized costs |
$ | 2,283,566 | ||
Unproved properties not subject to amortization at December 31, 2003 and 2002 consisted mainly of leasehold acquired through acquisitions and lease acquisition costs. We capitalized approximately $13.0 million, $5.0 million and $4.7 million of interest during 2003, 2002 and 2001, respectively, on significant investments in unproved properties that were not yet included in the amortization base of the full-cost pool. We will continue to evaluate our unevaluated properties; however, the timing of the ultimate evaluation and disposition of the properties has not been determined.
97
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
Costs Incurred in Oil and Gas Acquisition, Exploration and Development
Costs incurred in oil and gas property acquisition, exploration and development activities which have been capitalized are summarized as follows:
Year Ended December 31, 2003 |
U.S. |
Canada |
Combined |
|||||||||
($ in thousands) | ||||||||||||
Development and leasehold costs |
$ | 543,371 | $ | | $ | 543,371 | ||||||
Exploration costs |
103,424 | | 103,424 | |||||||||
Acquisition costs: |
||||||||||||
Proved properties |
1,110,077 | | 1,110,077 | |||||||||
Unproved properties |
198,394 | | 198,394 | |||||||||
Deferred tax adjustments |
(4,903 | ) | | (4,903 | ) | |||||||
Sales of oil and gas properties |
(22,156 | ) | | (22,156 | ) | |||||||
Geological and geophysical costs |
38,181 | | 38,181 | |||||||||
Asset retirement obligation (a) |
39,686 | | 39,686 | |||||||||
Capitalized internal costs |
35,494 | | 35,494 | |||||||||
Total |
$ | 2,041,568 | $ | | $ | 2,041,568 | ||||||
Year Ended December 31, 2002 |
U.S. |
Canada |
Combined |
|||||||||
($ in thousands) | ||||||||||||
Development and leasehold costs |
$ | 266,291 | $ | | $ | 266,291 | ||||||
Exploration costs |
89,422 | | 89,422 | |||||||||
Acquisition costs: |
||||||||||||
Proved properties |
316,583 | | 316,583 | |||||||||
Unproved properties |
14,000 | | 14,000 | |||||||||
Deferred tax adjustments |
62,398 | | 62,398 | |||||||||
Sales of oil and gas properties |
(839 | ) | | (839 | ) | |||||||
Geological and geophysical costs |
22,798 | | 22,798 | |||||||||
Capitalized internal costs |
24,318 | | 24,318 | |||||||||
Total |
$ | 794,971 | $ | | $ | 794,971 | ||||||
Year Ended December 31, 2001 |
U.S. |
Canada(b) |
Combined |
|||||||||
($ in thousands) | ||||||||||||
Development and leasehold costs |
$ | 322,582 | $ | 11,090 | $ | 333,672 | ||||||
Exploration costs |
47,937 | 8 | 47,945 | |||||||||
Acquisition costs: |
||||||||||||
Proved properties |
669,201 | | 669,201 | |||||||||
Unproved properties |
35,132 | | 35,132 | |||||||||
Deferred tax adjustments |
36,309 | | 36,309 | |||||||||
Sales of oil and gas properties |
(1,138 | ) | (150,306 | ) | (151,444 | ) | ||||||
Geological and geophysical costs |
7,131 | | 7,131 | |||||||||
Capitalized internal costs |
18,225 | | 18,225 | |||||||||
Total |
$ | 1,135,379 | $ | (139,208 | ) | $ | 996,171 | |||||
(a) | The amount includes $24.1 million of asset retirement costs recorded as a result of implementation of SFAS 143 effective January 1, 2003. |
(b) | In October 2001, we sold our Canadian subsidiary which had oil and gas operations primarily in Northeast British Columbia for net proceeds of approximately $143.0 million. |
98
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
Results of Operations from Oil and Gas Producing Activities (unaudited)
Chesapeakes results of operations from oil and gas producing activities are presented below for 2003, 2002 and 2001. The following table includes revenues and expenses associated directly with our oil and gas producing activities. It does not include any interest costs and general and administrative costs and, therefore, is not necessarily indicative of the contribution to consolidated net operating results of our oil and gas operations.
Year Ended December 31, 2003 |
U.S. |
Canada |
Combined |
|||||||||
($ in thousands) | ||||||||||||
Oil and gas sales (b) |
$ | 1,296,822 | $ | | $ | 1,296,822 | ||||||
Production expenses |
(137,583 | ) | | (137,583 | ) | |||||||
Production taxes |
(77,893 | ) | | (77,893 | ) | |||||||
Depletion and depreciation |
(369,465 | ) | | (369,465 | ) | |||||||
Imputed income tax provision (a) |
(270,515 | ) | | (270,515 | ) | |||||||
Results of operations from oil and gas producing activities |
$ | 441,366 | $ | | $ | 441,366 | ||||||
Year Ended December 31, 2002 |
||||||||||||
Oil and gas sales (c) |
$ | 568,187 | $ | | $ | 568,187 | ||||||
Production expenses |
(98,191 | ) | | (98,191 | ) | |||||||
Production taxes |
(30,101 | ) | | (30,101 | ) | |||||||
Depletion and depreciation |
(221,189 | ) | | (221,189 | ) | |||||||
Imputed income tax provision (a) |
(87,482 | ) | | (87,482 | ) | |||||||
Results of operations from oil and gas producing activities |
$ | 131,224 | $ | | $ | 131,224 | ||||||
Year Ended December 31, 2001 |
||||||||||||
Oil and gas sales (d) |
$ | 788,390 | $ | 31,928 | $ | 820,318 | ||||||
Production expenses |
(73,016 | ) | (2,358 | ) | (75,374 | ) | ||||||
Production taxes |
(33,010 | ) | | (33,010 | ) | |||||||
Depletion and depreciation |
(164,693 | ) | (8,209 | ) | (172,902 | ) | ||||||
Imputed income tax provision (a) |
(207,068 | ) | (9,612 | ) | (216,680 | ) | ||||||
Results of operations from oil and gas producing activities |
$ | 310,603 | $ | 11,749 | $ | 322,352 | ||||||
(a) | The imputed income tax provision is hypothetical (at the statutory rate) and determined without regard to our deduction for general and administrative expenses, interest costs and other income tax credits and deductions, nor whether the hypothetical tax provision will be payable. |
(b) | Includes $10.5 million of unrealized gains on oil and gas derivatives. |
(c) | Includes $87.3 million of unrealized losses on oil and gas derivatives. |
(d) | Includes $84.8 million of unrealized gains on oil and gas derivatives. |
99
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
Oil and Gas Reserve Quantities (unaudited)
The reserve information presented below is based upon reports prepared by independent petroleum engineers and Chesapeakes petroleum engineers.
| As of December 31, 2003, Ryder Scott Company L.P., Netherland, Sewell & Associates, Inc., Lee Keeling and Associates and our internal reservoir engineers evaluated 31%, 26%, 17% and 26%, respectively, of the combined discounted future net revenues from our estimated proved reserves. |
| As of December 31, 2002, Lee Keeling and Associates, Ryder Scott Company L.P., Netherland, Sewell & Associates, Inc., Williamson Petroleum Consultants, Inc. and our internal reservoir engineers evaluated 23%, 20%, 20%, 10% and 27%, respectively, of the combined discounted future net revenues from our estimated proved reserves. |
| As of December 31, 2001, Ryder Scott Company L.P., Lee Keeling and Associates, Williamson Petroleum Consultants, Inc. and our internal reservoir engineers evaluated 26%, 24%, 22% and 28%, respectively, of the combined discounted future net revenues from our estimated proved reserves. |
The information is presented in accordance with regulations prescribed by the Securities and Exchange Commission. Chesapeake emphasizes that reserve estimates are inherently imprecise. Our reserve estimates were generally based upon extrapolation of historical production trends, analogy to similar properties and volumetric calculations. Accordingly, these estimates are expected to change, and such changes could be material and occur in the near term as future information becomes available.
Proved oil and gas reserves represent the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (a) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the proved classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.
Proved developed oil and gas reserves are those expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as proved developed reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production responses that increased recovery will be achieved.
100
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
Presented below is a summary of changes in estimated reserves of Chesapeake for 2003, 2002 and 2001:
U.S. |
Canada |
Combined |
||||||||||||||||||||||||
Oil (mbbl) |
Gas (mmcf) |
Total (mmcfe) |
Oil (mbbl) |
Gas (mmcf) |
Total (mmcfe) |
Oil (mbbl) |
Gas (mmcf) |
Total (mmcfe) |
||||||||||||||||||
December 31, 2003 |
||||||||||||||||||||||||||
Proved reserves, beginning of period |
37,587 | 1,979,601 | 2,205,125 | | | | 37,587 | 1,979,601 | 2,205,125 | |||||||||||||||||
Extensions, discoveries and other additions |
3,574 | 359,681 | 381,123 | | | | 3,574 | 359,681 | 381,123 | |||||||||||||||||
Revisions of previous estimates |
1,329 | 48,388 | 56,365 | | | | 1,329 | 48,388 | 56,365 | |||||||||||||||||
Production |
(4,665 | ) | (240,366 | ) | (268,356 | ) | | | | (4,665 | ) | (240,366 | ) | (268,356 | ) | |||||||||||
Sale of reserves-in-place |
(183 | ) | (9,626 | ) | (10,723 | ) | | | | (183 | ) | (9,626 | ) | (10,723 | ) | |||||||||||
Purchase of reserves-in-place |
13,780 | 722,362 | 805,041 | | | | 13,780 | 722,362 | 805,041 | |||||||||||||||||
Proved reserves, end of period |
51,422 | 2,860,040 | 3,168,575 | | | | 51,422 | 2,860,040 | 3,168,575 | |||||||||||||||||
Proved developed reserves: |
||||||||||||||||||||||||||
Beginning of period |
28,111 | 1,458,284 | 1,626,952 | | | | 28,111 | 1,458,284 | 1,626,952 | |||||||||||||||||
End of period |
38,442 | 2,121,734 | 2,352,389 | | | | 38,442 | 2,121,734 | 2,352,389 | |||||||||||||||||
December 31, 2002 |
||||||||||||||||||||||||||
Proved reserves, beginning of period |
30,093 | 1,599,386 | 1,779,946 | | | | 30,093 | 1,599,386 | 1,779,946 | |||||||||||||||||
Extensions, discoveries and other additions |
4,348 | 217,116 | 243,205 | | | | 4,348 | 217,116 | 243,205 | |||||||||||||||||
Revisions of previous estimates |
3,189 | 70,359 | 89,493 | | | | 3,189 | 70,359 | 89,493 | |||||||||||||||||
Production |
(3,466 | ) | (160,682 | ) | (181,478 | ) | | | | (3,466 | ) | (160,682 | ) | (181,478 | ) | |||||||||||
Sale of reserves-in-place |
(24 | ) | (1,003 | ) | (1,146 | ) | | | | (24 | ) | (1,003 | ) | (1,146 | ) | |||||||||||
Purchase of reserves-in-place |
3,447 | 254,425 | 275,105 | | | | 3,447 | 254,425 | 275,105 | |||||||||||||||||
Proved reserves, end of period |
37,587 | 1,979,601 | 2,205,125 | | | | 37,587 | 1,979,601 | 2,205,125 | |||||||||||||||||
Proved developed reserves: |
||||||||||||||||||||||||||
Beginning of period |
22,496 | 1,134,381 | 1,269,359 | | | | 22,496 | 1,134,381 | 1,269,359 | |||||||||||||||||
End of period |
28,111 | 1,458,284 | 1,626,952 | | | | 28,111 | 1,458,284 | 1,626,952 | |||||||||||||||||
December 31, 2001 |
||||||||||||||||||||||||||
Proved reserves, beginning of period |
23,797 | 1,053,069 | 1,195,849 | | 158,964 | 158,964 | 23,797 | 1,212,033 | 1,354,813 | |||||||||||||||||
Extensions, discoveries and other additions |
2,425 | 256,616 | 271,167 | | | | 2,425 | 256,616 | 271,167 | |||||||||||||||||
Revisions of previous estimates |
(2,750 | ) | (166,146 | ) | (182,644 | ) | | | | (2,750 | ) | (166,146 | ) | (182,644 | ) | |||||||||||
Production |
(2,880 | ) | (135,096 | ) | (152,376 | ) | | (9,075 | ) | (9,075 | ) | (2,880 | ) | (144,171 | ) | (161,451 | ) | |||||||||
Sale of reserves-in-place |
| | | | (149,889 | ) | (149,889 | ) | | (149,889 | ) | (149,889 | ) | |||||||||||||
Purchase of reserves-in-place |
9,501 | 590,943 | 647,950 | | | | 9,501 | 590,943 | 647,950 | |||||||||||||||||
Proved reserves, end of period |
30,093 | 1,599,386 | 1,779,946 | | | | 30,093 | 1,599,386 | 1,779,946 | |||||||||||||||||
Proved developed reserves: |
||||||||||||||||||||||||||
Beginning of period |
15,445 | 739,775 | 832,445 | | 118,688 | 118,688 | 15,445 | 858,463 | 951,133 | |||||||||||||||||
End of period |
22,496 | 1,134,381 | 1,269,359 | | | | 22,496 | 1,134,381 | 1,269,359 | |||||||||||||||||
During 2003, Chesapeake acquired approximately 805 bcfe of proved reserves through purchases of oil and gas properties for consideration of $1,105 million (primarily in nine separate transactions of greater than $10 million each). We also sold 11 bcfe of proved reserves for consideration of approximately $22.2 million or $2.07 per mcfe. During 2003, we recorded upward revisions of 56 bcfe to the December 31, 2002 estimates of our reserves. Approximately 11.1 bcfe of the upward revisions was caused by higher oil and gas prices at December 31, 2003. Higher prices extend the economic lives of the underlying oil and gas properties and thereby increase the estimated future reserves. The weighted average oil and gas wellhead prices used in computing our reserves were $30.22 per bbl and $5.68 per mcf at December 31, 2003, compared to $30.18 per bbl and $4.28 per mcf at December 31, 2002.
101
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
During 2002, Chesapeake acquired approximately 275 bcfe of proved reserves through purchases of oil and gas properties for consideration of $379 million (primarily in six separate transactions of greater than $10 million each). We also sold 1 bcfe of proved reserves for consideration of approximately $0.8 million. During 2002, we recorded upward revisions of 89 bcfe to the December 31, 2001 estimates of our reserves. Approximately 76 bcfe of the upward revisions was caused by higher oil and gas prices at December 31, 2002. Higher prices extend the economic lives of the underlying oil and gas properties and thereby increase the estimated future reserves. The weighted average oil and gas wellhead prices used in computing our reserves were $30.18 per bbl and $4.28 per mcf at December 31, 2002, compared to $18.82 per bbl and $2.51 per mcf at December 31, 2001.
During 2001, Chesapeake acquired 648 bcfe of proved reserves for consideration of $706 million in approximately 160 separate transactions (primarily in six separate transactions of greater than $10 million each). In October 2001, we sold our Canadian subsidiary, which had oil and gas operations primarily in northeast British Columbia, for approximately $143.0 million. Also during 2001, we recorded downward revisions to our U.S. oil and gas reserves of 183 bcfe. Approximately 156 bcfe of the downward revisions to our reserves was related to significantly lower gas and oil prices at December 31, 2001, which had the effect of reducing the economic life of our properties. The weighted average oil and gas wellhead prices used in computing our reserves were $18.82 per bbl and $2.51 per mcf at December 31, 2001, compared to $26.41 per bbl and $10.12 per mcf at December 31, 2000.
Standardized Measure of Discounted Future Net Cash Flows (unaudited)
Statement of Financial Accounting Standards No. 69 prescribes guidelines for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. Chesapeake has followed these guidelines which are briefly discussed below.
Future cash inflows and future production and development costs are determined by applying year-end prices and costs to the estimated quantities of oil and gas to be produced. Actual future prices and costs may be materially higher or lower than the year-end prices and costs used. Estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on year-end economic conditions. Estimated future income taxes are computed using current statutory income tax rates including consideration for the current tax basis of the properties and related carryforwards, giving effect to permanent differences and tax credits. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor.
The assumptions used to compute the standardized measure are those prescribed by the Financial Accounting Standards Board and, as such, do not necessarily reflect our expectations of actual revenue to be derived from those reserves nor their present worth. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates are the basis for the valuation process.
102
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
The following summary sets forth our future net cash flows relating to proved oil and gas reserves based on the standardized measure prescribed in SFAS 69 ($ in thousands):
December 31, 2003 |
||||
Future cash inflows(a) |
$ | 17,807,624 | ||
Future production costs |
(3,816,607 | ) | ||
Future development costs |
(912,594 | ) | ||
Future income tax provision |
(3,827,408 | ) | ||
Net future cash flows |
9,251,015 | |||
Less effect of a 10% discount factor |
(3,924,262 | ) | ||
Standardized measure of discounted future net cash flows |
$ | 5,326,753 | ||
Discounted (at 10%) future net cash flows before income taxes |
$ | 7,333,142 | ||
December 31, 2002 |
||||
Future cash inflows(b) |
$ | 9,640,070 | ||
Future production costs |
(2,273,610 | ) | ||
Future development costs |
(606,042 | ) | ||
Future income tax provision |
(1,867,315 | ) | ||
Net future cash flows |
4,893,103 | |||
Less effect of a 10% discount factor |
(2,059,185 | ) | ||
Standardized measure of discounted future net cash flows |
$ | 2,833,918 | ||
Discounted (at 10%) future net cash flows before income taxes |
$ | 3,717,645 | ||
December 31, 2001 |
||||
Future cash inflows(c) |
$ | 4,586,743 | ||
Future production costs |
(1,169,199 | ) | ||
Future development costs |
(450,181 | ) | ||
Future income tax provision |
(484,474 | ) | ||
Net future cash flows |
2,482,889 | |||
Less effect of a 10% discount factor |
(1,021,916 | ) | ||
Standardized measure of discounted future net cash flows |
$ | 1,460,973 | ||
Discounted (at 10%) future net cash flows before income taxes |
$ | 1,646,667 | ||
(a) | Calculated using weighted average prices of $30.22 per barrel of oil and $5.68 per mcf of gas. |
(b) | Calculated using weighted average prices of $30.18 per barrel of oil and $4.28 per mcf of gas. |
(c) | Calculated using weighted average prices of $18.82 per barrel of oil and $2.51 per mcf of gas. |
In October 2001, we sold our Canadian subsidiary, which had oil and gas operations primarily in northeast British Columbia, for net proceeds of approximately $143.0 million.
103
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
The principal sources of change in the standardized measure of discounted future net cash flows are as follows:
December 31, 2003
U.S. |
Canada |
Combined |
|||||||||
($ in thousands) | |||||||||||
Standardized measure, beginning of period |
$ | 2,833,918 | $ | | $ | 2,833,918 | |||||
Sales of oil and gas produced, net of production costs(a) |
(1,088,184 | ) | | (1,088,184 | ) | ||||||
Net changes in prices and production costs |
(2,364 | ) | | (2,364 | ) | ||||||
Extensions and discoveries, net of production and development costs |
1,041,108 | | 1,041,108 | ||||||||
Changes in future development costs |
74,719 | | 74,719 | ||||||||
Development costs incurred during the period that reduced future development costs |
130,195 | | 130,195 | ||||||||
Revisions of previous quantity estimates |
99,927 | | 99,927 | ||||||||
Purchase of reserves-in-place (b) |
2,012,686 | | 2,012,686 | ||||||||
Sales of reserves-in-place (b) |
(827 | ) | | (827 | ) | ||||||
Accretion of discount |
371,765 | | 371,765 | ||||||||
Net change in income taxes |
(1,122,661 | ) | | (1,122,661 | ) | ||||||
Changes in production rates and other |
976,471 | | 976,471 | ||||||||
Standardized measure, end of period (c) |
$ | 5,326,753 | $ | | $ | 5,326,753 | |||||
December 31, 2002
U.S. |
Canada |
Combined |
|||||||||
($ in thousands) | |||||||||||
Standardized measure, beginning of period |
$ | 1,460,973 | $ | | $ | 1,460,973 | |||||
Sales of oil and gas produced, net of production costs(a) |
(431,116 | ) | | (431,116 | ) | ||||||
Net changes in prices and production costs |
779,756 | | 779,756 | ||||||||
Extensions and discoveries, net of production and development costs |
463,674 | | 463,674 | ||||||||
Changes in future development costs |
32,812 | | 32,812 | ||||||||
Development costs incurred during the period that reduced future development costs |
68,387 | | 68,387 | ||||||||
Revisions of previous quantity estimates |
137,639 | | 137,639 | ||||||||
Purchase of reserves-in-place |
528,734 | | 528,734 | ||||||||
Sales of reserves-in-place |
(535 | ) | | (535 | ) | ||||||
Accretion of discount |
164,667 | | 164,667 | ||||||||
Net change in income taxes |
(698,033 | ) | | (698,033 | ) | ||||||
Changes in production rates and other |
326,960 | | 326,960 | ||||||||
Standardized measure, end of period (c) |
$ | 2,833,918 | $ | | $ | 2,833,918 | |||||
104
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
December 31, 2001
U.S. |
Canada |
Combined |
||||||||||
($ in thousands) | ||||||||||||
Standardized measure, beginning of period |
$ | 3,575,320 | $ | 487,941 | $ | 4,063,261 | ||||||
Sales of oil and gas produced, net of production costs(a) |
(492,184 | ) | (29,570 | ) | (521,754 | ) | ||||||
Net changes in prices and production costs |
(4,390,317 | ) | | (4,390,317 | ) | |||||||
Extensions and discoveries, net of production and development costs |
292,051 | | 292,051 | |||||||||
Changes in future development costs |
75,694 | | 75,694 | |||||||||
Development costs incurred during the period that reduced future development costs |
32,955 | | 32,955 | |||||||||
Revisions of previous quantity estimates |
(151,455 | ) | | (151,455 | ) | |||||||
Purchase of reserves-in-place |
816,865 | | 816,865 | |||||||||
Sales of reserves-in-place |
(157 | ) | (458,371 | ) | (458,528 | ) | ||||||
Accretion of discount |
536,523 | | 536,523 | |||||||||
Net change in income taxes |
1,604,216 | | 1,604,216 | |||||||||
Changes in production rates and other |
(438,538 | ) | | (438,538 | ) | |||||||
Standardized measure, end of period (c) |
$ | 1,460,973 | $ | | $ | 1,460,973 | ||||||
(a) | Excluding unrealized gains (losses) on derivatives. |
(b) | Purchases and sales of reserves are shown net of the 9.9 bcfe which was acquired and immediately sold for $19 million. |
(c) | The discounted amounts related to cash flow hedges that would affect future net cash flows have not been included in any of the periods presented. |
12. Asset Retirement Obligations
Effective January 1, 2003, Chesapeake adopted SFAS No. 143, Accounting for Asset Retirement Obligations. This statement applies to obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction and development of the assets.
We identified and estimated all of our asset retirement obligations for tangible, long-lived assets as of January 1, 2003. These obligations were for future plugging and abandonment costs for depleted oil and gas wells. Prior to the adoption of SFAS 143, we included an estimate of our asset retirement obligations related to our oil and gas properties in our calculation of oil and gas depreciation, depletion and amortization expense. Upon adoption of SFAS 143, we recorded the discounted fair value of our expected future obligations of $30.5 million, a cumulative effect of the change in accounting principle as an increase to earnings of $2.4 million (net of income taxes) and an increase in net oil and gas properties of $34.3 million. The pro-forma effect on prior periods financial position and results of operations was not material.
105
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
The components of the change in our asset retirement obligations are shown below:
Twelve Months Ended December 31, 2003 |
||||
($ in thousands) | ||||
Asset retirement obligations, beginning balance |
$ | 30,479 | ||
Additions and revisions |
19,445 | |||
Settlements and disposals |
(4,255 | ) | ||
Accretion expense |
3,143 | |||
Asset retirement obligations, ending balance |
$ | 48,812 | ||
13. Acquisitions and Divestitures
Acquisitions. In January 2003 we acquired the stock of a subsidiary of ONEOK, Inc., in May the stock of Oxley Petroleum Company and in October the partnership interests in Laredo Energy LP for an aggregate purchase price of approximately $638 million. The assets of these entities were comprised mainly of proved and unproved oil and gas properties. These acquisitions were accounted for using the purchase method of accounting and, accordingly, results of operations of these acquired entities have been included in our results of operations from the respective closing dates of these acquisitions. Had these acquisitions been consummated at January 1, 2003, the effect on revenues and operating costs for 2003 would not have been significant. In addition to the above noted business combinations, during 2003 we acquired interests in leaseholds and proved and unproved oil and gas properties for aggregate purchase consideration of approximately $654 million. The largest purchase of oil and gas assets was a purchase from a subsidiary of El Paso Corporation for $510 million in March 2003. Acquisitions of both companies and oil and gas assets during 2002 and 2001 amounted to $393 million and $741 million, respectively.
Divestiture of Chesapeake Canada Corporation. In October 2001, we sold Chesapeake Canada Corporation, a wholly-owned subsidiary, for net proceeds of approximately $143.0 million.
106
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
14. Quarterly Financial Data (unaudited)
Summarized unaudited quarterly financial data for 2003 and 2002 are as follows ($ in thousands except per share data):
Quarters Ended |
||||||||||||||
March 31, 2003 |
June 30, 2003 |
September 30, 2003 |
December 31, 2003 |
|||||||||||
Total revenues |
$ | 376,327 | (b) | $ | 429,815 | $ | 454,549 | $ | 456,741 | |||||
Gross profit(a) |
150,952 | 169,902 | 182,741 | 171,660 | ||||||||||
Net income before cumulative effect of accounting change, net of tax |
71,120 | 82,240 | 87,859 | 69,373 | ||||||||||
Cumulative effect of accounting change, net of tax |
2,389 | | | | ||||||||||
Net income |
$ | 73,509 | $ | 82,240 | $ | 87,859 | $ | 69,373 | (c) | |||||
Net earnings per share basic: |
||||||||||||||
Income before cumulative effect of accounting change |
$ | 0.34 | $ | 0.36 | $ | 0.38 | $ | 0.29 | ||||||
Cumulative effect of accounting change |
0.01 | | | | ||||||||||
$ | 0.35 | $ | 0.36 | $ | 0.38 | $ | 0.29 | |||||||
Net earnings per share assuming dilution: |
||||||||||||||
Income before cumulative effect of accounting change |
$ | 0.31 | $ | 0.31 | $ | 0.33 | $ | 0.25 | ||||||
Cumulative effect of accounting change |
0.01 | | | | ||||||||||
$ | 0.32 | $ | 0.31 | $ | 0.33 | $ | 0.25 | |||||||
Quarters Ended |
||||||||||||||
March 31, 2002 |
June 30, 2002 |
September 30, 2002 |
December 31, 2002 |
|||||||||||
Total revenues |
$ | 89,989 | $ | 193,690 | $ | 196,466 | $ | 258,357 | ||||||
Gross profit(a) |
(19,817 | ) | 62,067 | 57,723 | 91,685 | |||||||||
Net income |
(27,586 | ) | 25,033 | 16,600 | 26,239 | |||||||||
Net earnings per common share: |
||||||||||||||
Basic |
$ | (0.18 | ) | $ | 0.14 | $ | 0.08 | $ | 0.14 | |||||
Diluted |
$ | (0.18 | ) | $ | 0.13 | $ | 0.08 | $ | 0.13 |
(a) | Total revenue less total operating costs. |
(b) | Gives effect to reclassification of unrealized gains (losses) on interest rate derivatives from risk management income (loss) to interest expense as discussed in Note 16 of the 2002 Form 10-K/A. |
(c) | Includes a pre-tax loss on repurchases of debt of $20.8 million. |
15. Recent Accounting Pronouncements
During 2002 and 2003, the Financial Accounting Standards Board issued the following Statements of Financial Accounting Standards which were reviewed by Chesapeake to determine the potential impact on our financial statements upon adoption.
107
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
In July 2002, the FASB issued SFAS No. 146, Accounting For Costs Associated with Exit or Disposal Activities. SFAS 146 is effective for exit or disposal activities initiated after December 31, 2002. We adopted this standard during the quarter ended March 31, 2003 and it did not have any impact on our financial position or results of operations.
In November 2002, the FASB issued FASB Interpretation, or FIN 45, Guarantors Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantee of Indebtedness of Others. FIN 45 requires that upon issuance of a guarantee, the guarantor must recognize a liability for the fair value of the obligation it assumes under that guarantee. FIN 45s provisions for initial recognition and measurement should be applied on a prospective basis to guarantees issued or modified after December 31, 2002. The guarantors previous accounting for guarantees that were issued before the date of FIN 45s initial application may not be revised or restated to reflect the effect of the recognition and measurement provisions of the Interpretation. The disclosure requirements are effective for financial statements of both interim and annual periods that end after December 15, 2002. Chesapeake is not a guarantor under any significant guarantees and thus this interpretation did not have a significant effect on the companys financial position or results of operations.
In January 2003, the FASB issued Financial Interpretation No. 46, Consolidation of Variable Interest Entities An Interpretation of ARB No. 51. FIN 46 is an interpretation of Accounting Research Bulletin 51, Consolidated Financial Statements, and addresses consolidation of variable interest entities (VIEs) by business enterprises. The primary objective of FIN 46 is to provide guidance on the identification and financial reporting of entities over which control is achieved through means other than voting rights; such entities are known as VIEs. FIN 46 requires an enterprise to consolidate a VIE if that enterprise has a variable interest that will absorb a majority of the entitys expected losses, receive a majority of the entitys expected residual returns, or both. An enterprise shall consider the rights and obligations conveyed by its variable interest in making this determination. At December 31, 2003, Chesapeake did not have any entities that would qualify for consolidation in accordance with the provisions of FIN 46, as amended. Therefore, the adoption of FIN 46, as amended, did not have an impact on our consolidated financial statements.
In March 2003, the FASB issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. SFAS 149 is effective for contracts entered into or modified after June 30, 2003. This statement amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts (collectively referred to as derivatives) and for hedging activities under SFAS 133, Accounting for Derivative Instruments and Hedging Activities. We adopted this standard during the quarter ended September 30, 2003 and it did not have any impact on our financial position or results of operations.
In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity. SFAS 150 is effective for financial instruments entered into or modified after May 31, 2003 and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. This statement establishes new standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. SFAS 150 requires that an issuer classify a financial instrument that is within the scope of this statement as a liability because the financial instrument embodies an obligation of the issuer. This statement applies to certain forms of mandatorily redeemable financial instruments including certain types of preferred stock, written put options and forward contracts. Adoption of this standard did not have any significant impact on our financial position or results of operations.
In December 2003, the Securities and Exchange Commission issued Staff Accounting Bulletin 104, Revenue Recognition. SAB 104 revises or rescinds certain guidance included in previously issued staff accounting
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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)
bulletins in order to make this interpretive guidance consistent with current authoritative accounting and auditing guidance and SEC rules and regulations relating to revenue recognition. This bulletin was effective immediately upon issuance. Chesapeakes current revenue recognition policies comply with SAB 104.
16. Subsequent Events
We completed an acquisition of Permian Basin and Mid-Continent oil and gas assets from Concho Resources Inc. in January 2004. We paid approximately $420 million in cash for these assets, $10 million of which was paid in 2003.
We also completed an acquisition of South Texas gas assets in January 2004. We paid $65 million for these assets, $3.3 million of which was paid in 2003.
On January 14, 2004, we issued 23,000,000 shares of common stock at a price to the public of $13.51 per share. We used the net proceeds from this offering of approximately $298.3 million to finance a portion of the acquisitions completed in January 2004.
On January 14, 2004, we completed a public exchange offer in which we retired $458.5 million of our 8.125% notes due 2011 and $10.8 million of accrued interest and issued $72.8 million of our 7.75% notes due 2015 and $2.8 million of accrued interest and $433.5 million of our 6.875% notes due 2016 and $4.1 million of accrued interest. The exchange of notes did not represent a substantial change in the terms of the debt instruments in accordance with EITF 96-19, accordingly, no gain or loss on debt extinguishment was recorded. We recognized transaction costs related to the exchange of approximately $6 million.
In January and February of 2004, we issued an additional $37.0 million of our 6.875% notes due 2016 and $0.5 million of accrued interest in exchange for $24.3 million of our 8.125% notes due 2011 and $0.7 million of accrued interest and $9.1 million of our 7.75% notes due 2015 and $0.1 million of accrued interest in four private exchange transactions.
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CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
($ in thousands)
Balance at Beginning Of Period |
Additions |
Deductions |
Balance at End of Period | |||||||||||||
Description |
Charged To Expense |
Charged To Other Accounts |
||||||||||||||
December 31, 2003: |
||||||||||||||||
Allowance for doubtful accounts |
$ | 1,433 | $ | 156 | $ | 1,202 | $ | 122 | $ | 2,669 | ||||||
Valuation allowance for deferred tax assets |
$ | 2,441 | $ | 4,364 | (a) | $ | | $ | | $ | 6,805 | |||||
December 31, 2002: |
||||||||||||||||
Allowance for doubtful accounts |
$ | 947 | $ | 315 | $ | 171 | $ | | $ | 1,433 | ||||||
Valuation allowance for deferred tax assets |
$ | 2,441 | $ | | $ | | $ | | $ | 2,441 | ||||||
December 31, 2001: |
||||||||||||||||
Allowance for doubtful accounts |
$ | 1,085 | $ | 69 | $ | 44 | $ | 251 | $ | 947 | ||||||
Valuation allowance for deferred tax assets |
$ | | $ | 2,441 | (a) | $ | | $ | | $ | 2,441 |
(a) | As of December 31, 2001, we determined that it is more likely than not that $2.4 million of the net deferred tax assets related to Louisiana net operating losses generated by Louisiana properties would not be realized and recorded a valuation allowance equal to such amount. During 2003, we determined that it was more likely than not that an additional $4.4 million of the deferred tax assets related to Louisiana net operating losses would not be realized and we recorded an additional valuation allowance equal to such amount. |
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ITEM 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Not applicable.
ITEM 9A. Controls and Procedures
Our chief executive officer and chief financial officer have evaluated the effectiveness of the companys disclosure controls and procedures (as defined in Rule 13a-15 (e) under the Securities Exchange Act of 1934). Based on this evaluation, they have concluded the companys disclosure controls and procedures are effective as of December 31, 2003. No changes in the companys internal control over financial reporting occurred during the quarter ended December 31, 2003 that have materially affected, or are reasonably likely to materially affect, the companys internal control over financial reporting.
PART III
ITEM 10. Directors and Executive Officers of the Registrant
Directors
The following persons serve as directors of the Company as of the date of this report.
Aubrey K. McClendon, 44, has served as Chairman of the Board, Chief Executive Officer and a director since co-founding the Company in 1989. From 1982 to 1989, Mr. McClendon was an independent producer of oil and gas in affiliation with Tom L. Ward, the Companys President and Chief Operating Officer. Mr. McClendon is a member of the Board of Visitors of the Fuqua School of Business at Duke University. Mr. McClendon graduated from Duke University in 1981.
Tom L. Ward, 44, has served as President, Chief Operating Officer and a director of Chesapeake since co-founding the Company in 1989. From 1982 to 1989, Mr. Ward was an independent producer of oil and gas in affiliation with Aubrey K. McClendon, the Companys Chairman and Chief Executive Officer. Mr. Ward is a member of the Board of Trustees of Anderson University in Anderson, Indiana. Mr. Ward graduated from the University of Oklahoma in 1981.
Frank A. Keating, 59, has been a director of the Company since June 2003. Governor Keating has been the President and CEO of the American Council of Life Insurers, a large trade organization based in Washington, D.C., since January 2003. Governor Keating became a special agent in the Federal Bureau of Investigation in 1966 and then served as Assistant District Attorney in Tulsa County, Oklahoma. In 1972, Governor Keating was elected to the Oklahoma State House of Representatives and two years later was elected to the Oklahoma State Senate. In 1981 Governor Keating was appointed as the U.S. Attorney for the Northern District of Oklahoma and in 1985 he began seven years of service in the Ronald Reagan and George H. Bush administrations serving as Assistant Secretary of the Treasury, Associate Attorney General in the Justice Department and as General Counsel and Acting Deputy Secretary of the Department of Housing and Urban Development. In 1994, Governor Keating was elected as Oklahomas 25th Governor and served two consecutive four year terms. Governor Keating is a director of American Management Systems, Incorporated, a business and information technology consulting firm in Fairfax, Virginia. Governor Keating graduated from Georgetown University in 1966 and from the University of Oklahoma College of Law in 1969.
Breene M. Kerr, 75, has been a director of the Company since 1993. He is President of Brookside Company, Easton, Maryland. Mr. Kerr founded Kerr Consolidated, Inc. in 1969 and was the chief executive officer until 1996 when it was sold. The company operated heavy duty truck dealerships in Oklahoma, a truck leasing firm and various real estate interests. In 1969, Mr. Kerr co-founded the Resource Analysis and Management Group and remained its senior partner until 1982. From 1967 to 1969, he was Vice President of Kerr-McGee Chemical Corporation. From 1951 through 1967, Mr. Kerr worked for Kerr-McGee Corporation as a geologist and land
111
manager. Mr. Kerr has served as chairman of the Investment Committee for the Massachusetts Institute of Technology and is a life member of the Corporation (Board of Trustees) of that university. He served as a director of Kerr-McGee Corporation from 1957 to 1981 and was a member of its audit committee from 1973 to 1981. He was a director and audit committee member of Pan-American Properties from 1987 to 1990. Mr. Kerr currently is a trustee of the Brookings Institution in Washington, D.C. and the Woods Hole Oceanographic Institution in Woods Hole, Massachusetts, and has been an associate director since 1987 of Aven Gas & Oil, Inc., an oil and gas property management company located in Oklahoma City. Mr. Kerr graduated from the Massachusetts Institute of Technology in 1951.
Charles T. Maxwell, 72, has been a director of the company since September 2002. From 1999 to the present, Mr. Maxwell has been the Senior Energy Analyst at Weeden & Co., an institutional research and brokerage firm located in Greenwich, Connecticut. Entering the oil and natural gas industry in 1957, Mr. Maxwell worked for Mobil Oil Corporation for twelve years in the U.S., Europe, the Middle East and Africa. In 1968, Mr. Maxwell joined C.J. Lawrence, an institutional research and brokerage firm, as an oil analyst and was ranked by Institutional Investor magazine as No. 1 in his field in 1972, 1974, 1977, and 1981 through 1986. He rose to the position of Managing Director of C. J. Lawrence/Morgan Grenfell and retired from the firm in 1997, several years after it was acquired by Deutsche Bank. In addition, for the past 20 years he has been an active member of an Oxford (UK)-based organization comprised of OPEC officials and oil industry executives from 30 countries who meet twice a year to discuss trends in the energy industry. Mr. Maxwell is a director of Tipperary Corporation, an independent energy company in Denver, Colorado; Lescarden, Inc., a biotechnology company in New York; and American Distributed Generation Inc., a privately held company in Waltham, Massachusetts. Mr. Maxwell graduated from Princeton University in 1953 and Oxford University in 1957.
Shannon T. Self, 47, has been a director of the Company since 1993. He is a shareholder and co-founder of the law firm of Commercial Law Group, P.C., formerly Self, Giddens & Lees, Inc., a professional corporation, in Oklahoma City. Mr. Self was an associate and shareholder in the law firm of Hastie and Kirschner, Oklahoma City, from 1984 to 1991 and was employed by Arthur Young & Co. from 1979 to 1980. Mr. Self is a member of the Law Board of Northwestern University School of Law, a director of Piedra Capital, Ltd., a money management firm in Houston, Texas, and a director of Critical Technologies, Inc., a computer software company in Oklahoma City, Oklahoma. Mr. Self is a Certified Public Accountant. He graduated from the University of Oklahoma in 1979 and from Northwestern University Law School in 1984.
Frederick B. Whittemore, 73, has been a director of the Company since 1993. Mr. Whittemore has been an advisory director of Morgan Stanley Dean Witter & Co. since 1989 and was a managing director or partner of the predecessor firms of Morgan Stanley Dean Witter & Co. from 1967 to 1989. He was Vice-Chairman of the American Stock Exchange from 1982 to 1984. Mr. Whittemore is a director of Partner Reinsurance Company, Bermuda; Maxcor Financial Group Inc., New York; SunLife of New York, New York; KOS Pharmaceuticals, Inc., Miami, Florida; and Southern Pacific Petroleum, Australia, NL. Mr. Whittemore graduated from Dartmouth College in 1953 and from the Amos Tuck School of Business Administration in 1954.
Executive Officers
In addition to Messrs. McClendon and Ward, the following also serve as executive officers of the Company as of the date of this report.
Marcus C. Rowland, 51, was appointed Executive Vice President in 1998 and has been the Companys Chief Financial Officer since 1993. He served as Senior Vice President from 1997 to 1998 and as Vice President Finance from 1993 until 1997. From 1990 until his association with the Company, Mr. Rowland was Chief Operating Officer of Anglo-Suisse, L.P. assigned to the White Nights Russian Enterprise, a joint venture of Anglo-Suisse, L.P. and Phibro Energy Corporation, a major foreign operation which was granted the right to engage in oil and gas operations in Russia. Prior to his association with White Nights Russian Enterprise, Mr. Rowland owned and managed his own oil and gas company and prior to that was Chief Financial Officer of a
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private exploration company in Oklahoma City from 1981 to 1985. Mr. Rowland is a Certified Public Accountant. Mr. Rowland graduated from Wichita State University in 1975.
Martha A. Burger, 51, has served as Treasurer since 1995 and as Senior Vice President Human Resources since March 2000. She was the Companys Vice President Human Resources from 1998 until March 2000, Human Resources Manager from 1996 to 1998 and Corporate Secretary from November 1999 until July 2000. From 1994 to 1995, she served in various accounting positions with the Company, including Assistant Controller Operations. From 1989 to 1993, Ms. Burger was employed by Hadson Corporation as Assistant Treasurer and from 1993 to 1994 served as Vice President and Controller of Hadson Corporation. Prior to joining Hadson Corporation, Ms. Burger was employed by The Phoenix Resource Companies, Inc. as Assistant Treasurer and by Arthur Andersen & Co. Ms. Burger is a Certified Public Accountant and graduated from the University of Central Oklahoma in 1982 and from Oklahoma City University in 1992.
Michael A. Johnson, 38, has served as Senior Vice President Accounting, Controller and Chief Accounting Officer since March 2000. He served as Vice President of Accounting and Financial Reporting from March 1998 to March 2000 and as Assistant Controller from 1993 to 1998. From 1991 to 1993, Mr. Johnson served as Project Manager for Phibro Energy Production, Inc., a Russian joint venture. From 1987 to 1991, he served as audit manager for Arthur Andersen & Co. Mr. Johnson is a Certified Public Accountant and graduated from the University of Texas at Austin in 1987.
Other Officers
Steven C. Dixon, 45, has been Senior Vice President Production since 1995 and served as Vice President Exploration from 1991 to 1995. Mr. Dixon was a self-employed geological consultant in Wichita, Kansas from 1983 through 1990. He was employed by Beren Corporation in Wichita, Kansas from 1980 to 1983 as a geologist. Mr. Dixon graduated from the University of Kansas in 1980.
J. Mark Lester, 51, has been Senior Vice President Exploration since 1995 and served as Vice President Exploration from 1989 to 1995. From 1986 to 1989, Mr. Lester was self-employed and acted as a consultant to Messrs. McClendon and Ward. He was employed by various independent oil companies in Oklahoma City from 1980 to 1986, and was employed by Union Oil Company of California from 1977 to 1980 as a geophysicist. Mr. Lester graduated from Purdue University in 1975 with a B.S. in Engineering Geology and in 1977 with an M.S. in Geophysics.
Henry J. Hood, 43, was appointed Senior Vice President Land and Legal in 1997 and served as Vice President Land and Legal from 1995 to 1997. Mr. Hood was retained as a consultant to the Company during the two years prior to his joining the Company, and he was associated with the law firm of White, Coffey, Galt & Fite from 1992 to 1995. Mr. Hood was associated with or a partner of the law firm of Watson & McKenzie from 1987 to 1992. Mr. Hood is a member of the Oklahoma and Texas Bar Associations. Mr. Hood graduated from Duke University in 1982 and from the University of Oklahoma College of Law in 1985.
Thomas L. Winton, 57, has served as Senior Vice President Information Technology and Chief Information Officer since 1998. From 1985 until his association with the Company, Mr. Winton served as the Director, Information Services Department, at Union Pacific Resources Company. Prior to that period Mr. Winton held the positions of Regional Manager Information Services from 1984 until 1985 and Manager Technical Applications Planning and Development from 1980 until 1984 with UPRC. Mr. Winton also served as an analyst and supervisor in the Operations Research Division, Conoco Inc., from 1973 until 1980. Mr. Winton graduated from Oklahoma Christian University in 1969, Creighton University in 1973 and the University of Houston in 1980. Mr. Winton also completed the Tuck Executive Program, Amos Tuck School of Business, Dartmouth College in 1987.
Douglas J. Jacobson, 50, has served as Senior Vice President Acquisitions and Divestitures since August 1999. Prior to joining the Company, Mr. Jacobson was employed by Samson Investment Company from 1980
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until August 1999, where he served as Senior Vice President Project Development and Marketing from 1996 until August 1999. Prior to joining Samson, Mr. Jacobson was employed by Peat, Marwick, Mitchell & Co. Mr. Jacobson has served on various Oklahoma legislative commissions which have addressed issues in the oil and gas industry, including the Commission of Oil and Gas Production Practices and the Natural Gas Policy Commission. Mr. Jacobson is a Certified Public Accountant and graduated from John Brown University in 1976 and from the University of Arkansas in 1977.
Thomas S. Price, Jr., 51, has served as Senior Vice President Investor and Government Relations since April 2003. He was Senior Vice PresidentCorporate Development from March 2000 to April 2003, Vice President Corporate Development from 1992 to March 2000 and a consultant to the Company during the prior three years. He was employed by Kerr-McGee Corporation from 1988 to 1989 and by Flag-Redfern Oil Company from 1984 to 1988. Mr. Price is a member of the Independent Petroleum Association of America, the Mid-Continent Oil and Gas Association, the Oklahoma Independent Petroleum Association, the Texas Independent Producers and Royalty Owners Association, and the National Investor Relations Institute. Mr. Price graduated from the University of Central Oklahoma in 1983, from the University of Oklahoma in 1989 and from the American Graduate School of International Management in 1992.
James C. Johnson, 46, has served as President of Chesapeake Energy Marketing, Inc., a wholly-owned subsidiary of Chesapeake Energy Corporation, since January 2000. He served as Vice President Contract Administration for the Company from 1997 to 2000 and as Manager Contract Administration from 1996 to 1997. From 1980 to 1996, Mr. Johnson held various gas marketing and land positions with Enogex, Inc., Delhi Gas Pipeline Corporation, TXO Production Corp. and Gulf Oil Corporation. Mr. Johnson is a member of the Natural Gas Association of Oklahoma and graduated from the University of Oklahoma in 1980.
Stephen W. Miller, 47, was named Senior Vice President Drilling in September 2001 after serving as Vice President Drilling since 1996 and as District Manager College Station District from 1994 to 1996. Mr. Miller held various engineering positions in the oil and gas industry from 1980 to 1993. Mr. Miller is a registered Professional Engineer in Texas, is a member of the Society of Petroleum Engineers and graduated from Texas A&M University in 1980.
Audit Committee Financial Expert
The Board has an audit committee consisting of Messrs. Kerr, Keating and Maxwell. All of the members of the audit committee are independent, as determined by the Board in accordance with Section 10A of the Securities Exchange Act of 1934 and the New York Stock Exchanges corporate governance listing standards. Messrs. Kerr and Maxwell have been designated by the Board as audit committee financial experts, as defined in Item 401(h) of Regulation S-K. For the relevant experience of Messrs. Kerr and Maxwell, please refer to their respective biographies set forth above.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934 requires our directors and executive officers and persons who beneficially own more than 10% of the Companys common stock to file reports of ownership and subsequent changes with the Securities and Exchange Commission. Based only on a review of copies of such reports and written representations delivered to the Company by such persons, the Company believes that there were no violations of Section 16(a) by such persons during 2003.
Code of Business Conduct and Ethics
The Board has adopted a Code of Business Conduct and Ethics applicable to all directors, officers and employees of the Company, including our principal executive officer, principal financial officer and principal accounting officer. The Code of Business Conduct and Ethics is also posted on the Companys website at www.chkenergy.com.
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If the Company makes any amendments to the Code of Business Conduct and Ethics that relate to the standards enumerated in Item 406(b) of Regulation S-K, other than technical, administrative, or other non-substantive amendments, or grants any waivers, from such provisions of the Code to the Companys principal executive officer, principal financial officer and principal accounting officer, we will disclose the nature of the amendment or waiver, its effective date and to whom it applies on our website.
ITEM 11. Executive Compensation
Summary Compensation Table
The following table sets forth for the years ended December 31, 2003, 2002 and 2001 the compensation earned in each period by (i) our chief executive officer and (ii) the four other most highly compensated executive officers.
Annual Compensation |
Securities Underlying Options (# of Shares)(b) |
All Other | ||||||||||||||
Name and Principal Position |
Year |
Salary |
Bonus |
Other Annual |
||||||||||||
Aubrey K. McClendon Chairman of the Board and Chief Executive Officer |
2003 2002 2001 |
$ $ $ |
737,500 650,000 537,500 |
$ $ $ |
877,500 686,000 575,000 |
$ $ $ |
209,579 192,972 199,158 |
1,375,000 860,000 1,600,000 |
$ $ $ |
243,015 52,687 11,180 | ||||||
Tom L. Ward President and Chief Operating Officer |
2003 2002 2001 |
$ $ $ |
737,500 650,000 537,000 |
$ $ $ |
877,500 686,000 575,000 |
$ $ $ |
209,637 180,310 174,614 |
1,375,000 860,000 1,600,000 |
$ $ $ |
243,015 52,687 11,180 | ||||||
Marcus C. Rowland Executive Vice President - Finance & Chief Financial Officer |
2003 2002 2001 |
$ $ $ |
362,500 320,000 282,500 |
$ $ $ |
387,000 291,000 215,000 |
|
(d) (d) (d) |
160,000 100,000 175,000 |
$ $ $ |
113,247 23,931 14,270 | ||||||
Martha A. Burger Treasurer and Senior Vice President - Human Resources |
2003 2002 2001 |
$ $ $ |
287,500 245,000 200,000 |
$ $ $ |
236,500 151,000 90,000 |
|
(d) (d) (d) |
85,000 45,000 85,000 |
$ $ $ |
80,875 17,681 14,756 | ||||||
Michael A. Johnson Senior Vice President - Accounting & Controller |
2003 2002 2001 |
$ $ $ |
217,500 185,000 170,000 |
$ $ $ |
157,500 111,000 65,000 |
|
(d) (d) (d) |
65,000 35,000 55,000 |
$ $ $ |
56,549 16,652 11,130 |
(a) | Includes the cost of personal benefits provided by the Company, including for 2003, 2002 and 2001, respectively, personal accounting support ($106,347, $89,740 and $73,926 for Mr. McClendon and $106,385, $89,774 and $73,949 for Mr. Ward) and travel allowances ($75,000, $75,000 and $100,000 for Mr. McClendon and $75,000, $62,284 and $75,413 for Mr. Ward). |
(b) | No awards of restricted stock or payments under long-term incentive plans were made by the Company to any of the named executives in any period covered by the table. |
(c) | Represents our matching contributions to the Chesapeake Energy Corporation Savings and Incentive Stock Bonus Plan and the Chesapeake Energy Corporation 401(k) Make-Up Plan and premiums paid by the Company for term life insurance. In 2003, such amounts were $13,000, $228,875 and $1,140 for each of Messrs. McClendon and Ward; $16,000, $94,625 and $2,622 for Mr. Rowland; $17,250, $61,125 and $2,500 for Ms. Burger; and $15,000, $40,875 and $674 for Mr. Johnson, respectively. |
(d) | Perquisites and other personal benefits, securities or property did not exceed the lesser of $50,000 or 10% of the executive officers salary and bonus during the year. |
Stock Options Granted During 2003
The following table sets forth information concerning options to purchase our common stock granted during 2003 to the executive officers named in the Summary Compensation Table. Amounts represent stock options
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granted under the Companys 1994, 1996, 2000, 2001 and 2002 stock option plans and include incentive and nonqualified stock options. One-fourth of the number of shares represented by each option grant becomes exercisable on each of the first four grant date anniversaries. The exercise price of each option represents the market price of the common stock on the date of grant. The respective plans provide for appropriate adjustments in the number of shares and option price in the event of a merger, consolidation, recapitalization, stock split, combination of shares, stock dividend or similar transaction involving the Company. Upon the Companys dissolution or a business combination of the Company with another corporation, if the options are not assumed by the acquirer, all outstanding options become automatically vested and are fully exercisable immediately prior to the transaction.
Individual Grants |
Potential Realizable Value at Assumed Annual Rates of Stock Price Appreciation | |||||||||||||||
Name |
Number of Securities Underlying Options Granted |
Percent of Total Options |
Exercise Price Per Share |
Expiration Date |
5% |
10% | ||||||||||
Aubrey K. McClendon |
750,000 625,000 |
10.80 9.00 |
% % |
$ $ |
7.80 10.08 |
01/08/13 06/24/13 |
$ $ |
3,679,034 3,962,036 |
$ $ |
9,323,393 10,040,578 | ||||||
Tom L. Ward |
750,000 625,000 |
10.80 9.00 |
% % |
$ $ |
7.80 10.08 |
01/08/13 06/24/13 |
$ $ |
3,679,034 3,962,036 |
$ $ |
9,323,393 10,040,578 | ||||||
Marcus C. Rowland |
85,000 75,000 |
1.22 1.08 |
% % |
$ $ |
7.80 10.08 |
01/08/13 06/24/13 |
$ $ |
416,957 475,444 |
$ $ |
1,056,651 1,204,869 | ||||||
Martha A. Burger |
45,000 40,000 |
0.64 0.58 |
% % |
$ $ |
7.80 10.08 |
01/08/13 06/24/13 |
$ $ |
220,742 253,570 |
$ $ |
559,404 642,597 | ||||||
Michael A. Johnson |
30,000 35,000 |
0.43 0.50 |
% % |
$ $ |
7.80 10.08 |
01/08/13 06/24/13 |
$ $ |
147,161 221,874 |
$ $ |
372,996 562,272 |
(a) | The assumed annual rates of stock price appreciation of 5% and 10% are set by the Securities and Exchange Commission and are not intended as a forecast of possible future appreciation in stock prices. |
Aggregated Option Exercises in 2003 and December 31, 2003 Option Values
The following table sets forth information about options exercised by the named executive officers during 2003 and the unexercised options to purchase common stock held by them at December 31, 2003.
Name |
Shares Acquired On Exercise |
Value Realized(b) |
Number of Securities Underlying Unexercised Options at 12/31/03 |
Value of Unexercised In-the-Money Options at 12/31/03(a) | ||||||||||||
Exercisable |
Unexercisable |
Exercisable |
Unexercisable | |||||||||||||
Aubrey K. McClendon |
994,607 | (c) | $ | 8,530,419 | 1,977,500 | 3,313,750 | $ | 16,257,450 | $ | 22,634,163 | ||||||
Tom L. Ward |
| $ | | 4,772,058 | 3,313,750 | $ | 50,095,500 | $ | 22,634,163 | |||||||
Marcus C. Rowland |
197,500 | $ | 930,200 | 22,500 | 351,250 | $ | 168,075 | $ | 2,282,100 | |||||||
Martha A. Burger |
4,100 | $ | 49,282 | 219,715 | 188,750 | $ | 2,239,514 | $ | 1,261,375 | |||||||
Michael A. Johnson |
80,977 | $ | 538,922 | 2,500 | 135,000 | $ | 18,675 | $ | 873,788 |
(a) | At December 31, 2003, the closing price of our common stock on the New York Stock Exchange was $13.58. In-the-money options are stock options with respect to which the market value of the underlying shares of common stock exceeded the exercise price at December 31, 2003. The values shown were determined by subtracting the aggregate exercise price of such options from the aggregate market value of the underlying shares of common stock on December 31, 2003. |
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(b) | Represents amounts determined by subtracting the aggregate exercise price of such options from the aggregate market value of the underlying shares of common stock on the exercise date. |
(c) | Mr. McClendon continues to hold the shares acquired upon exercise as part of his common stock holdings. |
Employment Agreements
We have employment agreements with Messrs. McClendon and Ward, each of which provides, among other things, for an annual base salary of not less than $800,000, bonuses at the discretion of the Board of Directors, through its Compensation Committee, eligibility for stock options and benefits, including an automobile allowance, personal use of company-owned aircraft, club membership and personal accounting support. Each agreement has a term of five years commencing January 1, 2004, which term is automatically extended for one additional year on each January 31 unless one of the parties provides 30 days prior notice of non-extension. In addition, for each calendar year during which the employment agreements are in effect, Messrs. McClendon and Ward each agree to hold shares of the Companys common stock having an aggregate investment value equal to 500% of his annual base salary and bonus.
Under the employment agreements, Messrs. McClendon and Ward are permitted to participate in all of the wells spudded by or on behalf of the Company during each calendar quarter during the term of the agreement and continuing five years after termination of employment without cause or following a change in control. In order to participate, at least 30 days prior to the beginning of a calendar quarter the executive must notify the members of the Compensation Committee whether the executive elects to participate and, if so, the percentage working interest the executive will take in each well spudded by or on behalf of the Company during such quarter. The participation election by each of Messrs. McClendon and Ward may not exceed a 2.5% working interest in a well and is not effective for any well where the Companys working interest after elections by Messrs. McClendon and Ward to participate would be reduced to below 12.5%. Once an executive elects to participate, the percentage cannot be adjusted during the calendar quarter without the prior written consent of the Compensation Committee. No such adjustment has ever been requested or granted. For each well in which the executive participates, the Company bills to the executive an amount equal to the executives participation percentage multiplied by the drilling and operating costs incurred in drilling the well, together with leasehold costs in an amount determined by the Company to approximate what third parties pay, on average, for similar leasehold across the Companys operating areas. Payment is due for such costs promptly upon receipt of an invoice. The executive also receives a proportionate share of revenue from the well, less certain charges by the Company for marketing the oil and natural gas production.
The agreements permit Messrs. McClendon and Ward to continue to conduct oil and gas activities individually or through their affiliates, but only to the extent such activities are conducted on oil and gas leases or interests they owned, or had the right to acquire as of July 1, 2001, or acquired from the Company pursuant to their employment or other agreements. Messrs. McClendon and Ward have participated in all wells drilled by the Company since its initial public offering in February 1993, except during the period from January 1, 1999 to March 31, 2000.
The Company has an employment agreement with Mr. Rowland that is in effect through September 30, 2006. It provides for an annual base salary of not less than $375,000. Mr. Rowlands employment agreement requires him to hold not less than 25,000 shares of the Companys common stock throughout the term of the agreement. Mr. Rowlands agreement provides for bonuses at the discretion of the Compensation Committee of the Board of Directors and eligibility for stock options and benefits, including an automobile allowance and club membership. Mr. Rowlands employment agreement permits him to continue to conduct oil and gas activities individually and through various related or family-owned entities, but prohibits him from acquiring, attempting to acquire or aiding another person in acquiring an interest in oil and gas exploration, development or production activities other than certain permitted activities without the Companys approval.
The Company also has employment agreements with Mr. Johnson and Ms. Burger in effect through September 30, 2006, with minimum annual base salaries of $230,000 for Mr. Johnson and $300,000 for
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Ms. Burger. Each agreement provides that the executive officer is eligible for bonuses, stock options and other benefits. The agreements require each executive to acquire and continue to hold at least 10,000 shares of the Companys common stock.
The Company may terminate any of the employment agreements with its executive officers at any time without cause; however, upon such termination Messrs. McClendon and Ward are entitled to continue to receive base compensation (defined as salary equal to the executives base salary on the date of termination plus annual bonus compensation equal to the bonus compensation received by the executive during the twelve month period preceding the termination date) and benefits for the balance of the contract term. Messrs. Rowland and Johnson and Ms. Burger are entitled to continue to receive base salary (defined as salary equal to the executives base salary on the date of termination) and benefits for 180 days. Each of the employment agreements for Messrs. McClendon and Ward further provides that if, during the term of the agreement, there is a change of control and within three years thereafter (a) the agreement expires; (b) the agreement is not extended and the executive resigns within one year after the nonextension; (c) the executive is terminated other than for cause, death or incapacity; (d) the executive resigns as a result of (i) a change in his duties or title, (ii) a reduction in his compensation, (iii) a required relocation more than 25 miles from his then current place of employment, or (iv) a default by the Company under the agreement; (e) the agreement has not been assumed by any successor to or parent of the Company; or (f) the executive has agreed to remain employed by the Company for a period of three months to assist in the transition and thereafter resigns, then the executive officer will be entitled to a severance payment in an amount equal to five times his base compensation, plus five times the value of his benefits provided during the preceding twelve months, plus a grossup amount to be paid with respect to any excise or income taxes or penalties imposed on the severance payment. Change of control is defined in these agreements to include:
(1) a person acquiring beneficial ownership of 20% or more of the Companys outstanding common stock or the voting power of the Companys existing voting securities unless one of the circumstances described in clause 3(i), (ii) and (iii) below exists,
(2) a majority of the members of the Incumbent Board is replaced by directors who were not nominated or elected by the Incumbent Board (the current directors and directors later nominated or elected by a majority of such directors are referred to as the Incumbent Board),
(3) the consummation of a business combination such as a reorganization, merger, consolidation or sale of all or substantially all of the Companys assets unless following such business combination (i) the persons who beneficially owned the Companys common stock and voting securities immediately prior to the business combination beneficially own more than 60% of such securities of the corporation resulting from the business combination in substantially the same proportions, (ii) no person beneficially owns 20% or more of such securities of the corporation resulting from the business combination unless such ownership existed prior to the business combination, or (iii) a majority of the members of the board of directors of the corporation resulting from the business combination were members of the Incumbent Board at the time of the execution or approval of the business combination agreement, and
(4) the approval by the shareholders of a complete liquidation or dissolution of the Company.
The employment agreements for Messrs. Rowland and Johnson and Ms. Burger further provide that if, during the term of the agreement, there is a change of control, then the executive officer will be entitled to a severance payment in an amount equal to 200 percent of the sum of the executive officers base salary as of the date of the change of control plus annual bonus compensation paid to the executive during the twelve month period immediately prior to the change of control. The right to such compensation is subject to the executive officers continued compliance with the terms of the employment agreement. Change of control is defined in these agreements as defined in Messrs. McClendon and Ward agreements.
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Directors Compensation
Currently, non-employee director compensation consists of (1) an annual retainer of $15,000, payable in quarterly installments of $3,750, (2) $6,250 and $1,250 payable for each board meeting attended in person and telephonically, respectively, not to exceed $45,000 per year for board meetings attended, and (3) a quarterly grant of stock options to purchase 11,250 shares of our common stock. Nonqualified stock options are granted under the Companys 2002 Non-Employee Director Stock Option Plan on the first business day of each calendar quarter, have a term of ten years, are granted at an exercise price equal to the market price on the date of grant and are fully exercisable upon grant.
During 2003, each non-employee director received cash compensation of $43,750, comprised of an annual retainer of $15,000 and meeting fees of $28,750. In addition, during 2003, non-employee directors received nonqualified stock options to purchase a total of 42,500 shares of our common stock at exercise prices equal to the market price on the dates of grant. Directors were also reimbursed for travel and other expenses.
Directors are also eligible to defer all, or a portion, of their annual retainers and/or meeting fees into the Chesapeake Energy Corporation Deferred Compensation Plan on a tax-favored basis.
Under the Companys 2003 Stock Award Plan for Non-Employee Directors, 10,000 shares of the Companys common stock will be awarded to each newly appointed non-employee director on his or her first day of service. In 2003, Mr. Keating was awarded 10,000 shares of common stock subsequent to his appointment as a director.
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ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The table below sets forth (i) the name and address and beneficial ownership of each person known by management to own beneficially more than 5% of our outstanding common stock, and (ii) the beneficial ownership of common stock of our nominees, directors and executive officers listed in the foregoing Summary Compensation Table and by all directors and executive officers of the Company as a group. Unless otherwise noted, information is given as of March 10, 2004 and the persons named below have sole voting and/or investment power with respect to such shares.
Common Stock |
|||||||||||
Beneficial Owner |
Outstanding Shares |
Share Equivalents |
Total Ownership |
Percent of Class |
|||||||
Tom L. Ward(1)(2) 6100 North Western Avenue Oklahoma City, OK 73118 |
10,040,910 | (a) | 6,961,243 | (b) | 17,164,653 | 6.90 | % | ||||
Aubrey K. McClendon(1)(2) 6100 North Western Avenue Oklahoma City, OK 73118 |
11,330,508 | (c) | 4,166,685 | (d) | 15,659,693 | 6.37 | % | ||||
FMR Corp. 82 Devonshire Street Boston, MA 02109 |
8,941,180 | 3,318,383 | (e) | 12,259,563 | 5.08 | % | |||||
Frederick B. Whittemore(1) |
716,700 | (f) | 977,500 | (g) | 1,694,200 | (3 | ) | ||||
Shannon T. Self(1) |
124,742 | (h) | 357,500 | (i) | 482,242 | (3 | ) | ||||
Breene M. Kerr(1) |
253,524 | (j) | 31,250 | (i) | 284,774 | (3 | ) | ||||
Charles T. Maxwell(1) |
15,000 | (k) | 58,750 | (i) | 73,750 | (3 | ) | ||||
Frank A. Keating(1) |
10,000 | 33,750 | (i) | 43,750 | (3 | ) | |||||
Martha A. Burger(2) |
34,225 | (l) | 248,465 | (i) | 282,690 | (3 | ) | ||||
Marcus C. Rowland(2) |
58,460 | (l) | 10,000 | 68,460 | (3 | ) | |||||
Michael A. Johnson(2) |
32,301 | (l) | 20,000 | (i) | 52,301 | (3 | ) | ||||
All directors and executive officers as a group |
22,616,370 | 12,440,143 | 35,056,513 | 14.01 | % |
(1) | Director |
(2) | Executive officer |
(3) | Less than 1% |
(a) | Includes (i) 1,563,510 shares held by TLW Investments, Inc., an Oklahoma corporation of which Mr. Ward is sole shareholder and chief executive (ii) 21,435 shares held by Mr. Wards immediate family sharing the same household, (iii) 43,452 shares purchased on behalf of the executive officer in the Chesapeake Energy Corporation Savings and Incentive Stock Bonus Plan and (iv) 22,812 phantom shares allocated to the executive officer in the Chesapeake Energy Corporation 401(k) Make-Up Plan. Excluded are the shares of our common stock beneficially owned by Mr. McClendon which may be attributed to Mr. Ward based on a jointly filed Schedule 13D. Mr. Ward disclaims such ownership. |
(b) | Includes (i) 5,275,103 shares of common stock which can be acquired on March 10, 2004 or within 60 days thereafter through the exercise of stock options, (ii) 1,543,830 shares of common stock issuable upon conversion of 6.75% preferred stock and (iii) 304, 810 shares of common stock issuable upon conversion of 5.0% preferred stock. |
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(c) | Includes (i) 13,560 shares held by Chesapeake Investments, an Oklahoma limited partnership of which Mr. McClendon is sole general partner, (ii) 91,109 shares purchased on behalf of the executive officer in the Chesapeake Energy Corporation Savings and Incentive Stock Bonus Plan and (iii) 22,812 phantom shares allocated to the executive officer in the Chesapeake Energy Corporation 401(k) Make-Up Plan. Excluded are the shares beneficially owned by Mr. Ward which may be attributed to Mr. McClendon based on a jointly filed Schedule 13D. Mr. McClendon disclaims such ownership. |
(d) | Includes (i) 2,480,545 shares of common stock which can be acquired on March 10, 2004 or within 60 days thereafter through the exercise of stock options, (ii) 1,543,830 shares of common stock issuable upon conversion of 6.75% preferred stock and (iii) 304,810 shares of common stock issuable upon conversion of 5.0% preferred stock. |
(e) | Consists of 586,300 shares of the Companys 6.75% and 6.0% convertible preferred stock which is convertible into 3,318,383 shares of the Companys common stock based upon a Schedule 13G filed on February 17, 2004. The Schedule 13G reports sole power to vote 863,075 shares and sole power to dispose or to direct the disposition of all shares. |
(f) | Includes 41,750 shares held by Mr. Whittemore as trustee of the Whittemore Foundation. |
(g) | Includes 227,500 shares of common stock which can be acquired through the exercise of stock options and options to purchase 750,000 shares of our common stock owned by Messrs. Ward and McClendon issued to Mr. Whittemore (394,688 shares from Mr. McClendon and 355,312 shares from Mr. Ward). |
(h) | Includes 97,242 shares held by Pearson Street Limited Partnership, an Oklahoma limited partnership of which Mr. Self is general partner and the remaining partner is Mr. Selfs spouse. |
(i) | Represents shares of common stock which can be acquired through the exercise of stock options on March 10, 2004 or within 60 days thereafter. |
(j) | Includes 113,500 shares held by Talbot Fairfield II Limited Partnership, of which Mr. Kerr is a general partner. |
(k) | Includes 15,000 shares held by Maxwell Family Living Trust. |
(l) | Includes shares purchased on behalf of the executive officer in the Chesapeake Energy Corporation Savings and Incentive Stock Bonus Plan and phantom shares allocated to each executive officer in the Chesapeake Energy Corporation 401(k) Make-Up Plan (Martha A. Burger, 24,165 shares; Marcus C. Rowland, 30,952 shares; and Michael A. Johnson, 21,471 shares). |
Equity Compensation Plan Information
The following table provides information as of December 31, 2003 about shares of the Companys common stock issuable under the equity compensation plans we maintain for our employees, consultants and/or directors:
Number of securities to be issued upon exercise of outstanding options, warrants and rights |
Weighted-average exercise price of outstanding options, warrants and rights |
Number of securities remaining available for future issuance under equity compensation plans (excluding securities |
|||||||
(a) | (b) | (c) | |||||||
Equity compensation plans approved by shareholders |
10,715,037 | $ | 5.79 | 10,223,527 | |||||
Equity compensation plans not approved by shareholders |
16,485,455 | (1) | $ | 5.77 | 834,698 | ||||
Total (2) |
27,200,492 | $ | 5.78 | 11,058,225 | |||||
(1) | Does not include common stock issuable under our 401(k) Make-Up Plan. |
(2) | Does not include 32,793 shares of common stock issuable upon the exercise of stock options assumed by the Company in connection with its acquisition of Hugoton Energy Corporation. The weighted average exercise price of these assumed options is $7.63. |
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We have not obtained shareholder approval of stock option plans which cover only treasury shares or are broadly-based plans under the rules of the NYSE. Our treasury share plans are the 2000 and 2001 Executive Officer Stock Option Plans. Only executive officers are eligible to receive nonqualified stock options under these plans. Under our broadly-based plans, nonqualified stock options may be granted to employees and consultants. These plans are the 1999 Stock Option Plan, the 2000 Employee Stock Option Plan, and the 2001 and 2002 Nonqualified Stock Option Plans. The maximum period for exercise of an option granted under any of these plans may not be more than ten years from the date of grant and the exercise price may not be less than the fair market value of the shares underlying the options on the date of grant; provided, however, nonqualified stock options not exceeding 10% of the options issuable under a plan may be granted at an exercise price which is not less than 85% of the grant date fair market value. Options granted become exercisable at dates determined by the Compensation Committee of the Board of Directors. The plans provide for appropriate adjustments in the number of shares and option price in the event of a merger, consolidation, recapitalization, stock split, combination of shares, stock dividend or similar transaction involving the Company. Upon the Companys dissolution or a business combination of the Company with another corporation, if the options are not assumed by the acquirer, all outstanding options become automatically vested and are fully exercisable immediately prior to the transaction.
In 2003, the Board of Directors adopted our 2003 Stock Award Plan for Non-Employee Directors and 401(k) Make-Up Plan without shareholder approval. The 2003 Stock Award Plan for Non-Employee Directors provides that 10,000 shares of our common stock will be awarded to each newly appointed director on his or her first day of service. Up to a total of 50,000 shares may be issued under this plan. The 401(k) Make-Up Plan allows employees receiving combined base salary and bonus compensation of $90,000 and having at least five years of service to defer additional compensation beyond limit applicable to our Savings and Incentive Stock Bonus Plan and receive a company match payable in common stock on up to 15% of each employees aggregate compensation deferred in the Savings and Incentive Stock Bonus Plan and the 401(k) Make-Up Plan. The 401(k) Make-Up Plan is an unfunded deferred compensation plan and participants are general creditors of the Company as to their deferred compensation in the plan.
ITEM 13. Certain Relationships and Related Transactions
Legal Counsel. Shannon T. Self, a director of the Company, is a shareholder in the law firm Commercial Law Group, P.C. (CLG). CLG acts as special counsel to the Company on an ongoing basis with respect to general corporate matters, corporate structure, mergers and acquisitions, bank credit facilities, indenture maintenance and other special projects. CLG has advised the Company that it provides these legal services to the Company on the same terms as it provides services to clients not related to the Company. For services rendered by CLG, the Company pays all amounts for fees and expenses to CLG and not to Mr. Self. The Company uses multiple law firms and believes that the legal services provided by CLG and the rates charged for such services are competitive with the services and rates provided to the Company by other law firms. During 2003, we paid $2,123,000 for such legal services.
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Oil and Gas Operations. The table below presents information about drilling, completion, equipping and operating costs billed to Messrs. McClendon and Ward from January 1, 2003 to December 31, 2003, the largest amount owed by them during the period and the balances owed by them at December 31, 2002 and 2003 with respect to working interests they own in Company wells. Such costs are accumulated at the end of each month, but are not billed to working interest owners until the following month. During 2003, Messrs. McClendon and Ward paid each invoice promptly upon receipt. See Employment Agreements in Item 11 of this report for a description of terms covering the participation by Messrs. McClendon and Ward in our wells.
Aubrey K. McClendon |
Tom L. Ward | |||||
(in thousands) | ||||||
Balance billed and unpaid at December 31, 2002 |
$ | | $ | | ||
Amount billed in 2003 |
$ | 22,440 | $ | 22,443 | ||
Largest outstanding balance (month end) |
$ | | $ | | ||
Balance billed and unpaid at December 31, 2003 |
$ | | $ | |
Other Relationships. Mr. Wards brother, Ronnie D. Ward, has served as the Companys Northern Mid-Continent Land Manager since 1994. He was paid an aggregate salary and bonus of $244,000 in 2003.
ITEM 14. Principal Accounting Fees and Services
Aggregate fees for professional services rendered for the Company by PricewaterhouseCoopers LLP in 2003 and 2002 were:
2003 |
2002 | |||||
Audit |
$ | 814,000 | $ | 530,000 | ||
Audit-Related |
25,000 | 16,000 | ||||
Tax |
103,000 | 182,000 | ||||
All Other |
1,000 | | ||||
Total |
$ | 943,000 | $ | 728,000 | ||
Audit Fees
Fees for the 2003 audit and quarterly reviews, as well as the preparation of comfort letters, consents and assistance with and review of documents filed with the SEC in 2003, were $814,000, of which $346,000 related to the annual audit, $50,000 related to interim reviews, $9,000 related to consultations on financial accounting and reporting matters in connection with the annual audit, and $409,000 related to services provided in connection with our issuance of senior notes, preferred stock and common stock. Fees for the 2002 audit and quarterly reviews, as well as the preparation of comfort letters, consents and assistance with and review of documents filed with the SEC, were $530,000, of which $305,000 related to the annual audit, $41,000 related to interim reviews, and $184,000 related to services provided in connection with our issuance of senior notes and common stock.
Audit-Related Fees
Fees for the audit of employee benefit plans in 2003 and 2002 were $18,000 and $16,000, respectively. Additionally, audit-related fees in 2003 included $7,000 for assistance with and documentation of the Companys internal control over financial reporting.
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Tax Fees
Aggregate fees billed for tax-related services in 2003 were $103,000. Of this amount, $77,000 related to tax consulting services and $26,000 related to the review of our internally prepared tax returns. Aggregate fees billed for tax-related services in 2002 were $182,000. Of this amount, $126,000 related to tax consulting services and $56,000 related to the review of our internally prepared tax returns.
All Other Fees
In 2003, PricewaterhouseCoopers LLP provided the Company with an accounting research information service for a fee of $1,000. There were no fees for other services in 2002.
The Audit Committee pre-approves all audit and non-audit services provided by the Companys independent auditor prior to the engagement of the independent auditor with respect to such services. In addition to separately approved services, the Audit Committees pre-approval policy provides for pre-approval of specifically described audit and non-audit services on an annual basis. The policy authorizes the Committee to delegate to one or more of its members pre-approval authority with respect to permitted services. None of the services described above were approved by the Audit Committee under the de minimus exception provided by Rule 2-01(c)(7)(i)(C) under Regulation S-X.
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PART IV
ITEM 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K
(a) | The following documents are filed as part of this report: |
1. Financial Statements. Chesapeakes consolidated financial statements are included in Item 8 of this report. Reference is made to the accompanying Index to Financial Statements.
2. Financial Statement Schedules. Schedule II is included in Item 8 of this report with our consolidated financial statements. No other financial statement schedules are applicable or required.
3. Exhibits. The following exhibits are filed herewith pursuant to the requirements of Item 601 of Regulation S-K:
Exhibit Number |
Description | |
3.1 | Chesapeakes Restated Certificate of Incorporation together with the Certificates of Designation for the 6.75% Cumulative Convertible Preferred Stock the 6.0% Cumulative Convertible Preferred Stock, and the Series A Junior Participating Preferred Stock, and the Certificate of Elimination filed November 4, 2002 with the Secretary of State of the State of Oklahoma. Incorporated herein by reference to Exhibit 3.1 to Chesapeakes registration statement on Form S-3 (No. 333-104394). | |
3.1.1 | Certificate of Designation for the 5.0% Cumulative Convertible Preferred Stock. Incorporated herein by reference to Exhibit 3.1 to Chesapeakes current report on Form 8-K filed November 18, 2003. | |
3.2* | Chesapeakes Amended and Restated Bylaws. | |
4.1 | Indenture dated as of March 15, 1997 among Chesapeake, as issuer, Chesapeake Operating, Inc., Chesapeake Gas Development Corporation
and Chesapeake Exploration Limited Partnership, as Subsidiary Guarantors, and The Bank of New York (formerly United States Trust Company of New York), as Trustee, with respect to 7.875% Senior Notes due 2004. Incorporated herein by reference to
Exhibit 4.1 to Chesapeakes registration statement on Form S-4 (No. 333-24995). First Supplemental Indenture dated December 17, 1997 and Second Supplemental Indenture dated February 16, 1998. Incorporated herein by reference to Exhibit 4.1.1 to
Chesapeakes transition report on Form 10-K for the six months ended December 31, 1997. Second [Third] Supplemental Indenture dated April 22, 1998. Incorporated herein by reference to Exhibit 4.1.1 to Chesapeakes registration statement on
Form S-3 (No. 333-57235). Fourth Supplemental Indenture dated July 1, 1998. Incorporated herein by reference to Exhibit 4.1.1 to Chesapeakes quarterly report on Form 10-Q for the quarter ended September 30, 1998. Fifth Supplemental Indenture
dated November 19, 1999. Incorporated herein by reference to Exhibit 4.1.1 to Chesapeakes quarterly report on Form 10-Q for the quarter ended March 31, 2001. Sixth Supplemental Indenture dated December 31, 1999. Incorporated herein by
reference to Exhibit 4.1.1 to Chesapeakes quarterly report on Form 10-Q for the quarter ended September 30, 2001. Seventh Supplemental Indenture dated September 12, 2001. Incorporated herein by reference to Exhibit 4.1.2 to Chesapeakes
quarterly report on Form 10-Q for the quarter ended September 30, 2001. Eighth Supplemental Indenture dated October 1, 2001. Incorporated herein by reference to Exhibit 4.1.3 to Chesapeakes quarterly report on Form 10-Q for the quarter ended
September 30, 2001. Ninth Supplemental Indenture dated December 17, 2001. Incorporated herein by reference to Exhibit 4.1.1 to Chesapeakes registration statement on Form S-3 (No. 333-76546). Tenth Supplemental Indenture dated as of June 28,
2002. Incorporated herein by reference to Exhibit 4.1.2 to Chesapeakes registration statement on Form S-4 (No. 333-99289). Eleventh Supplemental Indenture dated as of July 8, 2002. Incorporated herein by reference to Exhibit 4.1.3 to
Chesapeakes registration statement on Form S-4 (No. 333-99289). Twelfth Supplemental Indenture dated as of February 14, 2003. Incorporated herein by reference to Exhibit 4.1.1 to Chesapeakes annual report |
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Exhibit Number |
Description | |
on Form 10-K/A for the year ended December 31, 2002. Thirteenth Supplemental Indenture dated as of May 1, 2003. Incorporated herein by reference to Exhibit 4.1.1 to Chesapeakes quarterly report on Form 10-Q for the quarter ended March 31, 2003. Fourteenth Supplemental Indenture dated as of August 15, 2003. Incorporated herein by reference to Exhibit 4.1.1 to Chesapeakes quarterly report on Form 10-Q for the quarter ended September 30, 2003. | ||
4.2 | Indenture dated as of March 15, 1997 among Chesapeake, as issuer, Chesapeake Operating, Inc., Chesapeake Gas Development Corporation and Chesapeake Exploration Limited Partnership, as Subsidiary Guarantors, and The Bank of New York (formerly United States Trust Company of New York), as Trustee, with respect to 8.5% Senior Notes due 2012. Incorporated herein by reference to Exhibit 4.3 to Chesapeakes registration statement on Form S-4 (No. 333-24995). First Supplemental Indenture dated December 17, 1997 and Second Supplemental Indenture dated February 16, 1998. Incorporated herein by reference to Exhibit 4.2.1 to Chesapeakes transition report on Form 10-K for the six months ended December 31, 1997. Second [Third] Supplemental Indenture dated April 22, 1998. Incorporated herein by reference to Exhibit 4.2.1 to Chesapeakes registration statement on Form S-3 (No. 333-57235). Fourth Supplemental Indenture dated July 1, 1998. Incorporated herein by reference to Exhibit 4.2.1 to Chesapeakes quarterly report on Form 10-Q for the quarter ended September 30, 1998. Fifth Supplemental Indenture dated November 19, 1999. Incorporated herein by reference to Exhibit 4.2.1 to Chesapeakes quarterly report on Form 10-Q for the quarter ended March 31, 2001. Sixth Supplemental Indenture dated December 31, 1999. Incorporated herein by reference to Exhibit 4.2.1 to Chesapeakes quarterly report on Form 10-Q for the quarter ended September 30, 2001. Seventh Supplement Indenture dated September 12, 2001. Incorporated herein by reference to Exhibit 4.2.2 to Chesapeakes quarterly report on Form 10-Q for the quarter ended September 30, 2001. Eighth Supplemental Indenture dated October 1, 2001. Incorporated herein by reference to Exhibit 4.2.3 to Chesapeakes registration statement of Form S-3 (No. 333-76545). Tenth Supplemental Indenture dated as of June 28, 2002. Incorporated herein by reference to Exhibit 4.2.2 to Chesapeakes registration statement on Form S-4 (No. 333-99289). Eleventh Supplement Indenture dated as of July 8, 2002. Incorporated herein by reference to Exhibit 4.2.3 to Chesapeakes registration statement on Form S-4 (No. 333-99289). Twelfth Supplemental Indenture dated as of February 14, 2003. Incorporated herein by reference to Exhibit 4.2.1 to Chesapeakes annual report on Form 10-K/A for the year ended December 31, 2002. Thirteenth Supplemental Indenture dated as of August 15, 2003. Incorporated herein by reference to Exhibit 4.2.1 to Chesapeakes quarterly report on Form 10-Q for the quarter ended March 31, 2003. Fourteenth Supplemental Indenture dated as of August 15, 2003. Incorporated herein by reference to Chesapeakes quarterly report on Form 10-Q for the quarter ended September 30, 2003. | |
4.2.1* | Fifteenth Supplemental Indenture dated as of November 26, 2003 among Chesapeake, as issuer, its Subsidiaries Signatory thereto, as Subsidiary Guarantors and The Bank of New York (formerly United States Trust Company of New York), as Trustee, with respect to the 8.5% senior notes due 2012. | |
4.3 | Indenture dated as of April 6, 2001 among Chesapeake, as issuer, its subsidiaries signatory thereto, as Subsidiary Guarantors, and
The Bank of New York (formerly United States Trust Company of New York), as Trustee, with respect to 8.125% Senior Notes due 2011. Incorporated herein by reference to Exhibit 4.6 to Chesapeakes quarterly report on Form 10-Q for the quarter
ended March 31, 2001. Supplemental Indenture dated May 14, 2001. Incorporated herein by reference to Exhibit 4.6 to Chesapeakes quarterly report on Form 10-Q for the quarter ended March 31, 2001. Second Supplemental Indenture dated
September 12, 2001. Incorporated herein by reference to Exhibit 4.3.1 to Chesapeakes quarterly report on Form 10-Q for the quarter ended September 30, 2001. Third Supplemental Indenture dated October 1, 2001. Incorporated herein by reference
to Exhibit 4.3.2 to Chesapeakes quarterly report on Form 10-Q for the quarter ended September 30, 2001. Fourth Supplemental Indenture dated December 17, 2001. Incorporated herein by reference to Exhibit 4.3.1 to Chesapeakes registration
statement on Form S-3 (No. 333-76546). Fifth |
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Exhibit Number |
Description | |
Supplemental Indenture dated as of June 28, 2002. Incorporated herein by reference to Exhibit 4.3.2 to Chesapeakes registration statement on Form S-4 (No. 333-99289). Sixth Supplemental Indenture dated July 8, 2002. Incorporated herein by reference to Exhibit 4.3.3 to Chesapeakes registration statement on Form S-4 (No. 333-99289). Seventh Supplemental Indenture dated as of February 14, 2003. Incorporated herein by reference to Exhibit 4.3.1 to Chesapeakes annual report on Form 10-K/A for the year ended December 31, 2002. Eighth Supplemental Indenture dated as of May 1, 2003. Incorporated herein by reference to Exhibit 4.3.1 to Chesapeakes quarterly report on Form 10-Q for the quarter ended March 31, 2003. Ninth Supplemental Indenture dated as of August 15, 2003. Incorporated herein by reference to Exhibit 4.3.1 to Chesapeakes quarterly report on Form 10-Q for the quarter ended September 30, 2003. | ||
4.3.1* | Tenth Supplemental Indenture dated as of March 5, 2004 to Indenture dated as of April 6, 2001 among Chesapeake, as issuer, its subsidiaries signatory thereto, as Subsidiary Guarantors and The Bank of New York (formerly United States Trust Company of New York), as Trustee, with respect to the 8.125% senior notes due 2011. | |
4.4 | Indenture dated as of November 5, 2001 among Chesapeake, as issuer, its subsidiaries signatory thereto, as Subsidiary Guarantors, and The Bank of New York, as Trustee, with respect to 8.375% Senior Notes due 2008. Incorporated herein by reference to Exhibit 4.16 to Chesapeakes registration statement on Form S-4 (No. 333-74584). First Supplemental Indenture dated December 17, 2001. Incorporated herein by reference to Exhibit 4.16.1 to Chesapeakes registration statement on Form S-3 (No. 333-76546). Second Supplemental Indenture dated as of June 28, 2002. Incorporated herein by reference to Exhibit 4.4.2 to Chesapeakes registration statement on Form S-4 (No. 333-99289). Third Supplemental Indenture dated as of July 8, 2002. Incorporated herein by reference to Exhibit 4.4.3 to Chesapeakes registration statement on Form S-4 (No. 333-99289). Fourth Supplemental Indenture dated as of February 14, 2003. Incorporated herein by reference to Exhibit 4.4.1 to Chesapeakes annual report on Form 10-K/A for the year ended December 31, 2002. Fifth Supplemental Indenture dated as of May 1, 2003. Incorporated herein by reference to Exhibit 4.4.1 to Chesapeakes quarterly report on Form 10-Q for the quarter ended March 31, 2003. Sixth Supplemental Indenture dated as of August 15, 2003. Incorporated herein by reference to Exhibit 4.4.1 to Chesapeakes quarterly report on Form 10-Q for the quarter ended September 30, 2003. | |
4.4.1* | Seventh Supplemental Indenture dated March 5, 2004 to Indenture dated as of November 5, 2001 among Chesapeake, as issuer, its subsidiaries signatory thereto as Subsidiary Guarantors, and The Bank of New York, as Trustee, with respect to 8.375% Senior Notes due 2008. | |
4.5 | Indenture dated as of August 12, 2002 among Chesapeake, as issuer, its subsidiaries signatory thereto, as Subsidiary Guarantors and The Bank of New York, as Trustee, with respect to its 9.0% Senior Notes due 2012. Incorporated herein by reference to Exhibit 4.14 to Chesapeakes registration statement on Form S-4 (No. 333-99289). First Supplemental Indenture dated as of February 14, 2003.Incorporated herein by reference to Exhibit 4.5.1 to Chesapeakes annual report on Form 10-K/A for the year ended December 31, 2002. Second Supplemental Indenture dated May 1, 2003. Incorporated herein by reference to Exhibit 4.5.1 to Chesapeakes quarterly report on Form 10-Q for the quarter ended March 31, 2003 Third Supplemental Indenture dated August 15, 2003. Incorporated herein by reference to Exhibit 4.5.1 to Chesapeakes quarterly report on Form 10-Q for the quarter ended September 30, 2003. | |
4.5.1* | Fourth Supplemental Indenture dated March 5, 2004 to Indenture dated as of August 12, 2002 among Chesapeake, as issuer, subsidiaries signatory thereto, as Subsidiary Guarantors and The Bank of New York, as Trustee, with respect to 9.0% Senior Notes due 2012. |
127
Exhibit Number |
Description | |
4.6 | Indenture dated as of December 20, 2002 among Chesapeake, as issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors and The Bank of New York, as Trustee, with respect to our 7.75% Senior Notes due 2015. Incorporated herein by reference to Exhibit 4.5 to Chesapeakes registration statement on Form S-4 (No. 333-102445) First Supplemental Indenture dated as of February 14, 2003. Incorporated herein by reference to Exhibit 4.6.1 to Chesapeakes annual report on Form 10-K/A for the year ended December 31, 2002. Second Supplemental Indenture dated as of May 1, 2003. Incorporated herein by reference to Exhibit 4.6.1 to Chesapeakes quarterly report on Form 10-Q for the quarter ended March 31, 2003. Third Supplemental Indenture dated as of August 15, 2003. Incorporated herein by reference to Exhibit 4.6.1 to Chesapeakes quarterly report on Form 10-Q for the quarter ended September 30, 2003. | |
4.6.1 * | Fourth Supplemental Indenture dated March 5, 2004 to Indenture dated as of December 20, 2002 among Chesapeake, as issuer, its subsidiaries signatory thereto as Subsidiary Guarantors, and The Bank of New York, as Trustee, with respect to 7.75% Senior Notes due 2015. | |
4.7 | Agreement to furnish copies of unfiled long-term debt Instruments. Incorporated herein by reference to Chesapeakes transition report on Form 10-K for the six months ended December 31, 1997. | |
4.8 | Third Amended and Restated Credit Agreement, dated as of May 30, 2003, among Chesapeake Energy Corporation, Chesapeake Exploration Limited Partnership, as Borrower, Union Bank of California, N.A., as Administrative Agent and Collateral Agent, BNP Paribas and SunTrust Bank, as Co-Syndication Agents, Credit Lyonnais New York Branch and Toronto Dominion (Texas), Inc., as Co-Documentation Agents and the several lenders from time to time parties thereto. Incorporated herein by reference to Exhibit 4.8 to Chesapeakes quarterly report on Form 10-Q for the quarter ended June 30, 2003. | |
4.9 | Indenture dated as of March 5, 2003 among Chesapeake, as issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors and The Bank of New York, as Trustee, with respect to 7.5% Senior Notes due 2013. First Supplemental Indenture dated as of May 1, 2003. Incorporated herein by reference to Exhibit 4.7.1 to Chesapeakes quarterly report on Form 10-Q for the quarter ended March 31, 2003. Second Supplemental Indenture dated as of August 15, 2003. Incorporated herein by reference to Exhibit 4.7.1 to Chesapeakes quarterly report on Form 10-Q for the quarter ended September 30, 2003. | |
4.9.1 * | Third Supplemental Indenture dated March 5, 2004 to Indenture dated as of March 5, 2003 among Chesapeake, as issuer, its subsidiaries signatory thereto as Subsidiary Guarantors, and The Bank of New York, as Trustee, with respect to 7.5% Senior Notes due 2013 | |
4.10 | Indenture dated as of November 26, 2003 among Chesapeake, as issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors and The Bank of New York, as Trustee, with respect to 6.875% senior notes due 2016. Incorporated herein by reference to Exhibit 4.2 to Chesapeakes registration statement on Form S-4/A (No. 333-110668). | |
4.10.1 * | First Supplemental Indenture dated March 5, 2004 to Indenture dated as of November 26, 2003 among Chesapeake, as issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors and The Bank of New York, as Trustee, with respect to 6.875% senior notes due 2016. | |
4.15 | Warrant Registration Rights Agreement dated as of April 21, 1998 among Gothic Energy Corporation and purchasers of units consisting of its 14 1/8% senior secured discount notes due 2006 and warrants to purchase its common stock. Incorporated herein by reference to Exhibit 4.15 to Chesapeakes annual report on Form 10-K for the year ended December 31, 2000. | |
10.1.1 | Chesapeakes 2003 Stock Incentive Plan. Incorporated herein by reference to Exhibit A to Chesapeakes definitive proxy statement for its 2003 annual meeting of shareholders filed April 17, 2003. |
128
Exhibit Number |
Description | |
10.1.2 | Chesapeakes 1992 Nonstatutory Stock Option Plan, as Amended. Incorporated herein by reference to Exhibit 10.1.2 to Chesapeakes quarterly report on Form 10-Q for the quarter ended December 31, 1996. | |
10.1.3 | Chesapeakes 1994 Stock Option Plan, as amended. Incorporated herein by reference to Exhibit 10.1.3 to Chesapeakes quarterly report on Form 10-Q for the quarter ended December 31, 1996. | |
10.1.4 | Chesapeakes 1996 Stock Option Plan. Incorporated herein by reference to Exhibit B to Chesapeakes definitive proxy statement for its 1996 annual meeting of shareholders. | |
10.1.5 | Chesapeakes 1999 Stock Option Plan. Incorporated herein by reference to Exhibit 10.1.5 to Chesapeakes quarterly report on Form 10-Q for the quarter ended June 30, 1999. | |
10.1.6 | Chesapeakes 2000 Employee Stock Option Plan. Incorporated herein by reference to Exhibit 10.1.6 to Chesapeakes quarterly report on Form 10-Q for the quarter ended March 31, 2000. | |
10.1.7 | Chesapeakes 2000 Executive Officer Stock Option Plan. Incorporated herein by reference to Exhibit 10.1.7 to Chesapeakes quarterly report on Form 10-Q for the quarter ended March 31, 2000 | |
10.1.8 | Chesapeakes 2001 Stock Option Plan. Incorporated herein by reference to Exhibit B to Chesapeakes definitive proxy statement for its 2001 annual meeting of shareholders filed April 30, 2001 | |
10.1.9 | Chesapeakes 2001 Executive Officer Stock Option Plan. Incorporated herein by reference to Exhibit 10.1.9 to Chesapeakes quarterly report on Form 10-Q for the quarter ended June 30, 2001. | |
10.1.10 | Chesapeakes 2001 Nonqualified Stock Option Plan. Incorporated herein by reference to Exhibit 10.1.10 to Chesapeakes quarterly report on Form 10-Q for the quarter ended June 30, 2001. | |
10.1.11 | Chesapeakes 2002 Stock Option Plan. Incorporated herein by reference to Exhibit A to Chesapeakes definitive proxy statement for its 2002 annual meeting of shareholders filed April 29, 2002. | |
10.1.12 | Chesapeakes 2002 Non-Employee Director Stock Option Plan. Incorporated herein by reference to Exhibit B to Chesapeakes definitive proxy statement for its 2002 annual meeting of shareholders filed April 29, 2002 | |
10.1.13 | Chesapeakes 2002 Nonqualified Stock Option Plan. Incorporated herein by reference to Exhibit 10.1.11 to Chesapeakes quarterly report on Form 10-Q for the quarter ended June 30, 2002. | |
10.1.14 | Chesapeakes 2003 Stock Award Plan for Non-Employee Directors. Incorporated herein by reference to Exhibit 10.1.14 to Chesapeakes annual report on Form 10-K/A for the year ended December 31, 2002. | |
10.1.15 | Chesapeake Energy Corporation 401(k) Make-Up Plan. Incorporated herein by reference to Exhibit 10.1.15 to Chesapeakes annual report on Form 10-K/A for the year ended December 31, 2002 | |
10.1.16 | Chesapeake Energy Corporation Deferred Compensation Plan. Incorporated herein by reference to Exhibit 10.1.16 to Chesapeakes annual report on Form 10-K/A for the year ended December 31, 2002. | |
10.1.17* | First Amendment dated as of October 24, 2003, to Chesapeake Energy Corporation 401(K) Make-Up Plan. |
129
Exhibit Number |
Description | |
10.2.1* | Third Amended and Restated Employment Agreement dated as of January 1, 2004, between Aubrey K. McClendon and Chesapeake Energy Corporation. | |
10.2.2* | Third Amended and Restated Employment Agreement dated as of January 1, 2004, between Tom L. Ward and Chesapeake Energy Corporation. | |
10.2.3 | Amended and Restated Employment Agreement dated as of July 1, 2003 between Marcus C. Rowland and Chesapeake Energy Corporation. Incorporated herein by reference to Exhibit 10.2.3 to Chesapeakes quarterly report on Form 10-Q for the quarter ended September 30, 2003. | |
10.2.8 | Employment Agreement dated as of July 1, 2003 between Michael A. Johnson and Chesapeake Energy Corporation. Incorporated herein by reference to Exhibit 10.2.8 to Chesapeakes quarterly report on Form 10-Q for the quarter ended September 30, 2003. | |
10.2.9 | Employment Agreement dated as of July 1, 2003 between Martha A. Burger and Chesapeake Energy Corporation. Incorporated herein by reference to Exhibit 10.2.9 to Chesapeakes quarterly report on Form 10-Q for the quarter ended September 30, 2003. | |
10.3 | Form of Indemnity Agreement for officers and directors of Chesapeake and its subsidiaries. Incorporated herein by reference to Exhibit 10.30 to Chesapeakes registration statement on Form S-1 (No. 33-55600). | |
10.5 | Rights Agreement dated July 15, 1998 between Chesapeake and UMB Bank, N.A., as Rights Agent. Incorporated herein by reference to Exhibit 1 to Chesapeakes registration statement on Form 8-A filed July 16, 1998. Amendment No. 1 dated September 11, 1998. Incorporated herein by reference to Exhibit 10.3 to Chesapeakes quarterly report on Form 10-Q for the quarter ended September 30, 1998. | |
12* | Ratios of Earnings to Fixed Charges and Preferred Dividends. | |
21* | Subsidiaries of Chesapeake. | |
23.1* | Consent of PricewaterhouseCoopers LLP | |
23.2* | Consent of Ryder Scott Company L.P. | |
23.3* | Consent of Lee Keeling and Associates, Inc. | |
23.4* | Consent of Netherland, Sewell & Associates, Inc. | |
31.1* | Aubrey K. McClendon, Chairman and Chief Executive Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
31.2* | Marcus C. Rowland, Executive Vice President and Chief Financial Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
32.1* | Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | |
32.2* | Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 |
* | Filed herewith. |
| Management contract or compensatory plan or arrangement. |
(b) | Reports on Form 8-K |
During the quarter ended December 31, 2003, Chesapeake filed the following current reports on Form 8-K:
On October 7, 2003, we filed a current report on Form 8-K, reporting under Item 5 that we issued a press release on October 6, 2003 announcing our third quarter 2003 earnings release and conference call dates.
130
On October 30, 2003 we filed a current report on Form 8-K, furnishing under Item 12 a press release we issued on October 30, 2003 announcing financial and operating results for the third quarter of 2003, significant additions to our oil and natural gas hedging positions, $200 million of acquisitions of natural gas properties and updated 2003 and 2004 guidance.
On November 12, 2003, we filed a current report on Form 8-K, furnishing under Item 9 a press release we issued on November 11, 2003 announcing a $150 million cumulative convertible preferred stock offering.
On November 12, 2003, we filed a current report on Form 8-K, furnishing under Item 9 a press release we issued on November 11, 2003 announcing a cash tender offer and consent solicitation for our 8.50% senior notes due 2012.
On November 12, 2003, we filed a current report on Form 8-K, furnishing under Item 9 a press release we issued on November 11, 2003 announcing a private offering of senior notes and possible exchange offer.
On November 13, 2003, we filed a current report on Form 8-K, reporting under Item 5 that we issued a press release on November 12, 2003 announcing the pricing of $200 million of 6.875% senior notes due 2016 and the pricing of $150 million of 5% cumulative convertible preferred stock. In addition, we also furnished under Item 9 that we updated the 2003 and 2004 guidance on our website.
On November 18, 2003, we filed a current report on Form 8-K, reporting under Item 5 that we entered into an underwriting agreement on November 12, 2003 with Lehman Brothers Inc., Banc of America Securities LLC and Morgan Stanley & Co. Incorporated, as Representative of the Several Underwriters in connection with the issuance and sale of 1,725,000 shares of our 5.00% cumulative convertible preferred stock. In addition, we filed the underwriting agreement and the certificate of designation for the 5.00% cumulative convertible preferred stock under Item 7.
On November 26, 2003, we filed a current report on Form 8-K, reporting under Item 5 that we issued a press release on November 25, 2003 announcing that, pursuant to our cash tender offer and consent solicitation for our 8.5% senior notes due 2012, we received the consents necessary to adopt certain proposed amendments to the indenture governing the notes.
On November 26, 2003, we filed a current report on Form 8-K, reporting under Item 5 that we issued a press release on November 26, 2003 announcing the completion of the private placement of our 6.875% senior notes due 2016 and the acceptance of $104,845,000 principal amount of our 8.5% senior notes due 2012, tendered for early payment.
On December 2, 2003, we filed a current report on Form 8-K, reporting under Item 5 that we issued a press release on December 1, 2003 announcing an exchange offer for our 8.125% senior notes due 2011.
On December 12, 2003, we filed a current report on Form 8-K, reporting under Item 5 that we issued a press release on December 11, 2003 announcing the expiration of the cash tender offer for our 8.5% senior notes due 2012.
On December 16, 2003, we filed a current report on Form 8-K, reporting under Item 5 that we issued a press release on December 15, 2003 announcing the declaration of quarterly common and preferred stock dividends.
On December 16, 2003, we filed a current report on Form 8-K, reporting under Item 5 that we issued a press release on December 15, 2003 announcing early results of our exchange offer for our 8.125% senior notes due 2011.
131
On December 23, 2003, we filed a current report on Form 8-K, reporting under Item 5 that we issued two press releases on December 22, 2003 announcing $510 million of acquisitions, updates to our hedging positions and our intention to extend the expiration date of our exchange offer for our 8.125% senior notes due 2011. In addition, we furnished under Item 9 additional information concerning the proposed acquisitions, additional hedging information and updates to our 2004 production forecasts.
On December 24, 2003, we filed a current report on Form 8-K, reporting under Item 5 that we issued a press release on December 24, 2003 announcing the extension of our exchange offer for our 8.125% senior notes due 2011.
132
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
CHESAPEAKE ENERGY CORPORATION | ||
By |
/s/ AUBREY K. MCCLENDON | |
Aubrey K. McClendon Chairman of the Board and Chief Executive Officer |
Date: March 15, 2004
Pursuant to the requirements of the Securities Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature |
Capacity |
Date | ||
/s/ AUBREY K. MCCLENDON Aubrey K. McClendon |
Chairman of the Board, Chief Executive Officer and Director (Principal Executive Officer) |
March 15, 2004 | ||
/s/ TOM L. WARD Tom L. Ward |
President, Chief Operating Officer |
March 15, 2004 | ||
/s/ MARCUS C. ROWLAND Marcus C. Rowland |
Executive Vice President and Chief Financial Officer (Principal Financial Officer |
March 15, 2004 | ||
/s/ MICHAEL A. JOHNSON Michael A. Johnson |
Senior Vice PresidentAccounting, Controller and Chief Accounting Officer (Principal Accounting Officer) |
March 15, 2004 | ||
/s/ FRANK KEATING Frank Keating |
Director |
March 15, 2004 | ||
/s/ BREENE M. KERR Breene M. Kerr |
Director |
March 15, 2004 | ||
/s/ CHARLES T. MAXWELL Charles T. Maxwell |
Director |
March 15, 2004 | ||
/s/ SHANNON T. SELF Shannon T. Self |
Director |
March 15, 2004 | ||
/s/ FREDERICK B. WHITTEMORE Frederick B. Whittemore |
Director |
March 15, 2004 |
133
INDEX TO EXHIBITS
Exhibit Number |
Description | ||
3.1 | Chesapeakes Restated Certificate of Incorporation together with the Certificates of Designation for the 6.75% Cumulative Convertible Preferred Stock, the 6.0% Cumulative Convertible Preferred Stock, and the the Series A Junior Participating Preferred Stock and the Certificate of Elimination filed November 4, 2002 with the Secretary of State of the State of Oklahoma. Incorporated herein by reference to Exhibit 3.1 to Chesapeakes registration statement on Form S-3 (No. 333-104394). | ||
3.1.1 | Certificate of Designation for the 5.0% Cumulative Convertible Preferred Stock. Incorporated herein by reference to Exhibit 3.1 to Chesapeakes current report on Form 8-K filed November 18, 2003. | ||
3.2 | * | Chesapeakes Amended and Restated Bylaws. | |
4.1 | Indenture dated as of March 15, 1997 among Chesapeake, as issuer, Chesapeake Operating, Inc., Chesapeake Gas Development Corporation and Chesapeake Exploration Limited Partnership, as Subsidiary Guarantors, and The Bank of New York (formerly United States Trust Company of New York), as Trustee, with respect to 7.875% Senior Notes due 2004. Incorporated herein by reference to Exhibit 4.1 to Chesapeakes registration statement on Form S-4 (No. 333-24995). First Supplemental Indenture dated December 17, 1997 and Second Supplemental Indenture dated February 16, 1998. Incorporated herein by reference to Exhibit 4.1.1 to Chesapeakes transition report on Form 10-K for the six months ended December 31, 1997. Second [Third] Supplemental Indenture dated April 22, 1998. Incorporated herein by reference to Exhibit 4.1.1 to Chesapeakes registration statement on Form S-3 (No. 333-57235). Fourth Supplemental Indenture dated July 1, 1998. Incorporated herein by reference to Exhibit 4.1.1 to Chesapeakes quarterly report on Form 10-Q for the quarter ended September 30, 1998. Fifth Supplemental Indenture dated November 19, 1999. Incorporated herein by reference to Exhibit 4.1.1 to Chesapeakes quarterly report on Form 10-Q for the quarter ended March 31, 2001. Sixth Supplemental Indenture dated December 31, 1999. Incorporated herein by reference to Exhibit 4.1.1 to Chesapeakes quarterly report on Form 10-Q for the quarter ended September 30, 2001. Seventh Supplemental Indenture dated September 12, 2001. Incorporated herein by reference to Exhibit 4.1.2 to Chesapeakes quarterly report on Form 10-Q for the quarter ended September 30, 2001. Eighth Supplemental Indenture dated October 1, 2001. Incorporated herein by reference to Exhibit 4.1.3 to Chesapeakes quarterly report on Form 10-Q for the quarter ended September 30, 2001. Ninth Supplemental Indenture dated December 17, 2001. Incorporated herein by reference to Exhibit 4.1.1 to Chesapeakes registration statement on Form S-3 (No. 333-76546). Tenth Supplemental Indenture dated as of June 28, 2002. Incorporated herein by reference to Exhibit 4.1.2 to Chesapeakes registration statement on Form S-4 (No. 333-99289). Eleventh Supplemental Indenture dated as of July 8, 2002. Incorporated herein by reference to Exhibit 4.1.3 to Chesapeakes registration statement on Form S-4 (No. 333-99289). Twelfth Supplemental Indenture dated as of February 14, 2003. Incorporated herein by reference to Exhibit 4.1.1 to Chesapeakes annual report on Form 10-K/A for the year ended December 31, 2002. Thirteenth Supplemental Indenture dated as of May 1, 2003. Incorporated herein by reference to Exhibit 4.1.1 to Chesapeakes quarterly report on Form 10-Q for the quarter ended March 31, 2003. Fourteenth Supplemental Indenture dated as of August 15, 2003. Incorporated herein by reference to Exhibit 4.1.1 to Chesapeakes quarterly report on Form 10-Q for the quarter ended September 30, 2003. | ||
4.2 | Indenture dated as of March 15, 1997 among Chesapeake, as issuer, Chesapeake Operating, Inc., Chesapeake Gas Development Corporation
and Chesapeake Exploration Limited Partnership, as Subsidiary Guarantors, and The Bank of New York (formerly United States Trust Company of |
134
Exhibit Number |
Description | ||
New York), as Trustee, with respect to 8.5% Senior Notes due 2012. Incorporated herein by reference to Exhibit 4.3 to Chesapeakes registration statement on Form S-4 (No. 333-24995). First Supplemental Indenture dated December 17, 1997 and Second Supplemental Indenture dated February 16, 1998. Incorporated herein by reference to Exhibit 4.2.1 to Chesapeakes transition report on Form 10-K for the six months ended December 31, 1997. Second [Third] Supplemental Indenture dated April 22, 1998. Incorporated herein by reference to Exhibit 4.2.1 to Chesapeakes registration statement on Form S-3 (No. 333-57235). Fourth Supplemental Indenture dated July 1, 1998. Incorporated herein by reference to Exhibit 4.2.1 to Chesapeakes quarterly report on Form 10-Q for the quarter ended September 30, 1998. Fifth Supplemental Indenture dated November 19, 1999. Incorporated herein by reference to Exhibit 4.2.1 to Chesapeakes quarterly report on Form 10-Q for the quarter ended March 31, 2001. Sixth Supplemental Indenture dated December 31, 1999. Incorporated herein by reference to Exhibit 4.2.1 to Chesapeakes quarterly report on Form 10-Q for the quarter ended September 30, 2001. Seventh Supplement Indenture dated September 12, 2001. Incorporated herein by reference to Exhibit 4.2.2 to Chesapeakes quarterly report on Form 10-Q for the quarter ended September 30, 2001. Eighth Supplemental Indenture dated October 1, 2001. Incorporated herein by reference to Exhibit 4.2.3 to Chesapeakes registration statement of Form S-3 (No. 333-76545). Tenth Supplemental Indenture dated as of June 28, 2002. Incorporated herein by reference to Exhibit 4.2.2 to Chesapeakes registration statement on Form S-4 (No. 333-99289). Eleventh Supplement Indenture dated as of July 8, 2002. Incorporated herein by reference to Exhibit 4.2.3 to Chesapeakes registration statement on Form S-4 (No. 333-99289). Twelfth Supplemental Indenture dated as of February 14, 2003. Incorporated herein by reference to Exhibit 4.2.1 to Chesapeakes annual report on Form 10-K/A for the year ended December 31, 2002. Thirteenth Supplemental Indenture dated as of August 15, 2003. Incorporated herein by reference to Exhibit 4.2.1 to Chesapeakes quarterly report on Form 10-Q for the quarter ended March 31, 2003. Fourteenth Supplemental Indenture dated as of August 15, 2003. Incorporated herein by reference to Chesapeakes quarterly report on Form 10-Q for the quarter ended September 30, 2003. | |||
4.2.1 | * | Fifteenth Supplemental Indenture dated as of November 26, 2003 among Chesapeake, as issuer, its Subsidiaries signatory thereto, as Subsidiary Guarantors and The Bank of New York (formerly United States Trust Company of New York), as Trustee, with respect to the 8.5% senior notes due 2012. | |
4.3 | Indenture dated as of April 6, 2001 among Chesapeake, as issuer, its subsidiaries signatory thereto, as Subsidiary Guarantors, and
The Bank of New York (formerly United States Trust Company of New York), as Trustee, with respect to 8.125% Senior Notes due 2011. Incorporated herein by reference to Exhibit 4.6 to Chesapeakes quarterly report on Form 10-Q for the quarter
ended March 31, 2001. Supplemental Indenture dated May 14, 2001. Incorporated herein by reference to Exhibit 4.6 to Chesapeakes quarterly report on Form 10-Q for the quarter ended March 31, 2001. Second Supplemental Indenture dated September
12, 2001. Incorporated herein by reference to Exhibit 4.3.1 to Chesapeakes quarterly report on Form 10-Q for the quarter ended September 30, 2001. Third Supplemental Indenture dated October 1, 2001. Incorporated herein by reference to
Exhibit 4.3.2 to Chesapeakes quarterly report on Form 10-Q for the quarter ended September 30, 2001. Fourth Supplemental Indenture dated December 17, 2001. Incorporated herein by reference to Exhibit 4.3.1 to Chesapeakes
registration statement on Form S-3 (No. 333-76546). Fifth Supplemental Indenture dated as of June 28, 2002. Incorporated herein by reference to Exhibit 4.3.2 to Chesapeakes registration statement on Form S-4 (No. 333-99289). Sixth
Supplemental Indenture dated July 8, 2002. Incorporated herein by reference to Exhibit 4.3.3 to Chesapeakes registration statement on Form S-4 (No. 333-99289). Seventh Supplemental Indenture dated as of February 14, 2003. Incorporated herein
by reference to Exhibit 4.3.1 to Chesapeakes annual report on Form 10-K/A for the year ended December 31, 2002. Eighth |
135
Exhibit Number |
Description | ||
Supplemental Indenture dated as of May 1, 2003. Incorporated herein by reference to Exhibit 4.3.1 to Chesapeakes quarterly report on Form 10-Q for the quarter ended March 31, 2003. Ninth Supplemental Indenture dated as of August 15, 2003. Incorporated herein by reference to Exhibit 4.3.1 to Chesapeakes quarterly report on Form 10-Q for the quarter ended September 30, 2003. | |||
4.3.1 | * | Tenth Supplemental Indenture dated as of March 5, 2004 to Indenture dated as of April 6, 2001 among Chesapeake, as issuer, its subsidiaries signatory thereto, as Subsidiary Guarantors and The Bank of New York (formerly United States Trust Company of New York), as Trustee, with respect to the 8.125% senior notes due 2011. | |
4.4 | Indenture dated as of November 5, 2001 among Chesapeake, as issuer, its subsidiaries signatory thereto, as Subsidiary Guarantors, and The Bank of New York, as Trustee, with respect to 8.375% Senior Notes due 2008. Incorporated herein by reference to Exhibit 4.16 to Chesapeakes registration statement on Form S-4 (No. 333-74584). First Supplemental Indenture dated December 17, 2001. Incorporated herein by reference to Exhibit 4.16.1 to Chesapeakes registration statement on Form S-3 (No. 333-76546). Second Supplemental Indenture dated as of June 28, 2002. Incorporated herein by reference to Exhibit 4.4.2 to Chesapeakes registration statement on Form S-4 (No. 333-99289). Third Supplemental Indenture dated as of July 8, 2002. Incorporated herein by reference to Exhibit 4.4.3 to Chesapeakes registration statement on Form S-4 (No. 333-99289). Fourth Supplemental Indenture dated as of February 14, 2003. Incorporated herein by reference to Exhibit 4.4.1 to Chesapeakes annual report on Form 10-K/A for the year ended December 31, 2002. Fifth Supplemental Indenture dated as of May 1, 2003. Incorporated herein by reference to Exhibit 4.4.1 to Chesapeakes quarterly report on Form 10-Q for the quarter ended March 31, 2003. Sixth Supplemental Indenture dated as of August 15, 2003. Incorporated herein by reference to Exhibit 4.4.1 to Chesapeakes quarterly report on Form 10-Q for the quarter ended September 30, 2003. | ||
4.4.1 | * | Seventh Supplemental Indenture dated March 5, 2004 to Indenture dated as of November 5, 2001 among Chesapeake, as issuer, its subsidiaries signatory thereto as Subsidiary Guarantors, and The Bank of New York, as Trustee, with respect to 8.375% Senior Notes due 2008. | |
4.5 | Indenture dated as of August 12, 2002 among Chesapeake, as issuer, its subsidiaries signatory thereto, as Subsidiary Guarantors and The Bank of New York, as Trustee, with respect to its 9.0% Senior Notes due 2012. Incorporated herein by reference to Exhibit 4.14 to Chesapeakes registration statement on Form S-4 (No. 333-99289). First Supplemental Indenture dated as of February 14, 2003. Incorporated herein by reference to Exhibit 4.5.1 to Chesapeakes annual report on Form 10-K/A for the year ended December 31, 2002. Second Supplemental Indenture dated May 1, 2003. Incorporated herein by reference to Exhibit 4.5.1 to Chesapeakes quarterly report on Form 10-Q for the quarter ended March 31, 2003 Third Supplemental Indenture dated August 15, 2003. Incorporated herein by reference to Exhibit 4.5.1 to Chesapeakes quarterly report on Form 10-Q for the quarter ended September 30, 2003. | ||
4.5.1 | * | Fourth Supplemental Indenture dated March 5, 2004 to Indenture dated as of August 12, 2002 among Chesapeake, as issuer, subsidiaries signatory thereto, as Subsidiary Guarantors and The Bank of New York, as Trustee, with respect to 9.0% Senior Notes due 2012. | |
4.6 | Indenture dated as of December 20, 2002 among Chesapeake, as issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors and
The Bank of New York, as Trustee, with respect to our 7.75% Senior Notes due 2015. Incorporated herein by reference to Exhibit 4.5 to Chesapeakes registration statement on Form S-4 (No. 333-102445). First Supplemental Indenture dated as of
February 14, 2003. Incorporated herein by reference to Exhibit 4.6.1 to Chesapeakes annual report on Form 10-K/A for the year ended December 31, 2002. Second Supplemental Indenture |
136
Exhibit Number |
Description | |
dated as of May 1, 2003. Incorporated herein by reference to Exhibit 4.6.1 to Chesapeakes quarterly report on Form 10-Q for the quarter ended March 31, 2003. Third Supplemental Indenture dated as of August 15, 2003. Incorporated herein by reference to Exhibit 4.6.1 to Chesapeakes quarterly report on Form 10-Q for the quarter ended September 30, 2003. | ||
4.6.1* | Fourth Supplemental Indenture dated March 5, 2004 to Indenture dated as of December 20, 2002 among Chesapeake, as issuer, its subsidiaries signatory thereto as Subsidiary Guarantors, and The Bank of New York, as Trustee, with respect to 7.75% Senior Notes due 2015. | |
4.7 | Agreement to furnish copies of unfiled long-term debt Instruments. Incorporated herein by reference to Chesapeakes transition report on Form 10-K for the six months ended December 31, 1997. | |
4.8 | Third Amended and Restated Credit Agreement, dated as of May 30, 2003, among Chesapeake Energy Corporation, Chesapeake Exploration Limited Partnership, as Borrower, Union Bank of California, N.A., as Administrative Agent and Collateral Agent, BNP Paribas and SunTrust Bank, as Co-Syndication Agents, Credit Lyonnais New York Branch and Toronto Dominion (Texas), Inc., as Co-Documentation Agents and the several lenders from time to time parties thereto. Incorporated herein by reference to Exhibit 4.8 to Chesapeakes quarterly report on Form 10-Q for the quarter ended June 30, 2003. | |
4.9 | Indenture dated as of March 5, 2003 among Chesapeake, as issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors and The Bank of New York, as Trustee, with respect to 7.5% Senior Notes due 2013. First Supplemental Indenture dated as of May 1, 2003. Incorporated herein by reference to Exhibit 4.7.1 to Chesapeakes quarterly report on Form 10-Q for the quarter ended March 31, 2003. Second Supplemental Indenture dated as of August 15, 2003. Incorporated herein by reference to Exhibit 4.7.1 to Chesapeakes quarterly report on Form 10-Q for the quarter ended September 30, 2003. | |
4.9.1* | Third Supplemental Indenture dated March 5, 2004 to Indenture dated as of March 5, 2003 among Chesapeake, as issuer, its subsidiaries signatory thereto as Subsidiary Guarantors, and The Bank of New York, as Trustee, with respect to 7.5% Senior Notes due 2013 | |
4.10 | Indenture dated as of November 26, 2003 among Chesapeake, as issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors and The Bank of New York, as Trustee, with respect to 6.875% senior notes due 2016. Incorporated herein by reference to Exhibit 4.2 to Chesapeakes registration statement on Form S-4/A (No. 333-110668). | |
4.10.1* | First Supplemental Indenture dated March 5, 2004 to Indenture dated as of November 26, 2003 among Chesapeake, as issuer, the subsidiaries signatory thereto, as Subsidiary Guarantors and The Bank of New York, as Trustee, with respect to 6.875% senior notes due 2016. | |
4.15 | Warrant Registration Rights Agreement dated as of April 21, 1998 among Gothic Energy Corporation and purchasers of units consisting of its 14 1/8% senior secured discount notes due 2006 and warrants to purchase its common stock. Incorporated herein by reference to Exhibit 4.15 to Chesapeakes annual report on Form 10-K for the year ended December 31, 2000. | |
10.1.1 | Chesapeakes 2003 Stock Incentive Plan. Incorporated herein by reference to Exhibit A to Chesapeakes definitive proxy statement for its 2003 annual meeting of shareholders filed April 17, 2003. | |
10.1.2 | Chesapeakes 1992 Nonstatutory Stock Option Plan, as Amended. Incorporated herein by reference to Exhibit 10.1.2 to Chesapeakes quarterly report on Form 10-Q for the quarter ended December 31, 1996. |
137
Exhibit Number |
Description | |
10.1.3 | Chesapeakes 1994 Stock Option Plan, as amended. Incorporated herein by reference to Exhibit 10.1.3 to Chesapeakes quarterly report on Form 10-Q for the quarter ended December 31, 1996. | |
10.1.4 | Chesapeakes 1996 Stock Option Plan. Incorporated herein by reference to Exhibit B to Chesapeakes definitive proxy statement for its 1996 annual meeting of shareholders. | |
10.1.5 | Chesapeakes 1999 Stock Option Plan. Incorporated herein by reference to Exhibit 10.1.5 to Chesapeakes quarterly report on Form 10-Q for the quarter ended June 30, 1999. | |
10.1.6 | Chesapeakes 2000 Employee Stock Option Plan. Incorporated herein by reference to Exhibit 10.1.6 to Chesapeakes quarterly report on Form 10-Q for the quarter ended March 31, 2000. | |
10.1.7 | Chesapeakes 2000 Executive Officer Stock Option Plan. Incorporated herein by reference to Exhibit 10.1.7 to Chesapeakes quarterly report on Form 10-Q for the quarter ended March 31, 2000 | |
10.1.8 | Chesapeakes 2001 Stock Option Plan. Incorporated herein by reference to Exhibit B to Chesapeakes definitive proxy statement for its 2001 annual meeting of shareholders filed April 30, 2001 | |
10.1.9 | Chesapeakes 2001 Executive Officer Stock Option Plan. Incorporated herein by reference to Exhibit 10.1.9 to Chesapeakes quarterly report on Form 10-Q for the quarter ended June 30, 2001. | |
10.1.10 | Chesapeakes 2001 Nonqualified Stock Option Plan. Incorporated herein by reference to Exhibit 10.1.10 to Chesapeakes quarterly report on Form 10-Q for the quarter ended June 30, 2001. | |
10.1.11 | Chesapeakes 2002 Stock Option Plan. Incorporated herein by reference to Exhibit A to Chesapeakes definitive proxy statement for its 2002 annual meeting of shareholders filed April 29, 2002. | |
10.1.12 | Chesapeakes 2002 Non-Employee Director Stock Option Plan. Incorporated herein by reference to Exhibit B to Chesapeakes definitive proxy statement for its 2002 annual meeting of shareholders filed April 29, 2002 | |
10.1.13 | Chesapeakes 2002 Nonqualified Stock Option Plan. Incorporated herein by reference to Exhibit 10.1.11 to Chesapeakes quarterly report on Form 10-Q for the quarter ended June 30, 2002. | |
10.1.14 | Chesapeakes 2003 Stock Award Plan for Non-Employee Directors. Incorporated herein by reference to Exhibit 10.1.14 to Chesapeakes annual report on Form 10-K/A for the year ended December 31, 2002. | |
10.1.15 | Chesapeake Energy Corporation 401(k) Make-Up Plan. Incorporated herein by reference to Exhibit 10.1.15 to Chesapeakes annual report on Form 10-K/A for the year ended December 31, 2002 | |
10.1.16 | Chesapeake Energy Corporation Deferred Compensation Plan. Incorporated herein by reference to Exhibit 10.1.16 to Chesapeakes annual report on Form 10-K/A for the year ended December 31, 2002. | |
10.1.17* | First Amendment dated as of October 24, 2003 to Chesapeake Energy Corporation 401(K) Make-Up Plan. |
138
Exhibit Number |
Description | |
10.2.1* | Third Amended and Restated Employment Agreement dated as of January 1, 2004, between Aubrey K. McClendon and Chesapeake Energy Corporation. | |
10.2.2* | Third Amended and Restated Employment Agreement dated as of January 1, 2004, between Tom L. Ward and Chesapeake Energy Corporation. | |
10.2.3 | Amended and Restated Employment Agreement dated as of July 1, 2003 between Marcus C. Rowland and Chesapeake Energy Corporation. Incorporated herein by reference to Exhibit 10.2.3 to Chesapeakes quarterly report on Form 10-Q for the quarter ended September 30, 2003. | |
10.2.8 | Employment Agreement dated as of July 1, 2003 between Michael A. Johnson and Chesapeake Energy Corporation. Incorporated herein by reference to Exhibit 10.2.8 to Chesapeakes quarterly report on Form 10-Q for the quarter ended September 30, 2003. | |
10.2.9 | Employment Agreement dated as of July 1, 2003 between Martha A. Burger and Chesapeake Energy Corporation. Incorporated herein by reference to Exhibit 10.2.9 to Chesapeakes quarterly report on Form 10-Q for the quarter ended September 30, 2003. | |
10.3 | Form of Indemnity Agreement for officers and directors of Chesapeake and its subsidiaries. Incorporated herein by reference to Exhibit 10.30 to Chesapeakes registration statement on Form S-1 (No. 33-55600). | |
10.5 | Rights Agreement dated July 15, 1998 between Chesapeake and UMB Bank, N.A., as Rights Agent. Incorporated herein by reference to Exhibit 1 to Chesapeakes registration statement on Form 8-A filed July 16, 1998. Amendment No. 1 dated September 11, 1998. Incorporated herein by reference to Exhibit 10.3 to Chesapeakes quarterly report on Form 10-Q for the quarter ended September 30, 1998. | |
12* | Ratios of Earnings to Fixed Charges and Preferred Dividends. | |
21* | Subsidiaries of Chesapeake. | |
23.1* | Consent of PricewaterhouseCoopers LLP | |
23.2* | Consent of Ryder Scott Company L.P. | |
23.3* | Consent of Lee Keeling and Associates, Inc. | |
23.4* | Consent of Netherland, Sewell & Associates, Inc. | |
31.1* | Aubrey K. McClendon, Chairman and Chief Executive Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
31.2* | Marcus C. Rowland, Executive Vice President and Chief Financial Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
32.1* | Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |
32.2* | Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
* | Filed herewith. |
| Management contract or compensatory plan or arrangement. |
139
EXHIBIT 3.2
BYLAWS
OF
CHESAPEAKE ENERGY CORPORATION
(an Oklahoma corporation)
(as amended through March 5, 2004)
TABLE OF CONTENTS
Page | ||||
Article 1 Shareholders Meetings |
1 | |||
Section 1 Place of Meetings |
1 | |||
Section 2 Annual Meeting |
1 | |||
Section 3 Special Meeting |
1 | |||
Section 4 Notice of Meetings |
1 | |||
Section 5 Quorum |
2 | |||
Section 6 Action Without Meeting |
2 | |||
Section 7 Voting |
3 | |||
Section 8 List of Shareholders |
3 | |||
Section 9 Organization |
4 | |||
Section 10 Order of Business |
4 | |||
Section 11 Nomination of Directors |
4 | |||
Section 12 Notice of Business |
5 | |||
Section 13 Action by Remote Communication |
5 | |||
Section 14 Inspectors of Elections |
6 | |||
Article II Directors |
6 | |||
Section 1 Powers |
6 | |||
Section 2 Number; Election |
6 | |||
Section 3 Vacancies |
7 | |||
Section 4 Place of Meetings |
7 | |||
Section 5 Regular Meetings |
7 | |||
Section 6 Special Meetings |
7 | |||
Section 7 Quorum |
7 | |||
Section 8 Presence at Meeting |
7 | |||
Section 9 Action Without Meeting |
8 | |||
Section 10 Committees of the Board |
8 | |||
Section 11 Compensation |
8 | |||
Section 12 Advisory Directors |
9 | |||
Section 13 Resignation |
9 | |||
Section 14 Removal |
9 | |||
Section 15 Preferred Directors |
9 | |||
Article III Officers and Employees |
9 | |||
Section 1 Election |
9 | |||
Section 2 Term, Removal and Vacancies |
9 | |||
Section 3 Chairman of the Board |
10 | |||
Section 4 Chief Executive Officer |
10 | |||
Section 5 Vice Chairman of the Board |
10 |
i
Section 6 President |
10 | |||
Section 7 Vice Presidents |
11 | |||
Section 8 Secretary |
11 | |||
Section 9 Treasurer |
11 | |||
Section 10 Divisional Officers |
11 | |||
Article IV Stock Certificates and Transfer Books |
11 | |||
Section 1 Certificates |
11 | |||
Section 2 Record Ownership |
12 | |||
Section 3 Transfer Agent and Registrar |
12 | |||
Section 4 Lost Certificates |
12 | |||
Section 5 Transfer of Stock |
12 | |||
Section 6 Fixing Date for Determination of Shareholders of Record |
12 | |||
Article V General Provisions |
13 | |||
Section 1 Offices |
13 | |||
Section 2 Voting of Stock |
13 | |||
Section 3 Notices |
13 | |||
Section 4 Waiver of Notice |
14 | |||
Section 5 Exception to Notice |
14 | |||
Article VI Indemnification of Officers, Directors, Employees and Agents |
14 | |||
Article VII Amendments |
16 |
ii
BYLAWS
OF
CHESAPEAKE ENERGY CORPORATION
(an Oklahoma corporation)
ARTICLE 1
Shareholders Meetings
Section 1. Place of Meetings. Meetings of shareholders for all purposes may be held at such time and place, either within or without the State of Oklahoma, or by means of remote communication in the manner provided by statute as the board of directors in its sole discretion may determine, as shall be stated in the notice of the meeting.
Section 2. Annual Meeting. The annual meeting of shareholders for the election of directors and the transaction of such other business as may properly come before the meeting shall be held within six (6) months following the end of the fiscal year of the corporation at such time, date and place as shall be determined by the board of directors.
Section 3. Special Meeting. Special meetings of shareholders may be called for any purpose or purposes, unless otherwise prescribed by the Oklahoma General Corporation Act (the Act) and may be called only by the chairman of the board, or shall be called by the president or secretary, at the request, in writing, of a majority of the board of directors or by shareholders who are the record owners of ten percent (10%) or more of the outstanding shares of the corporations stock entitled to vote at the election of directors. Such request shall state the purpose or purposes of the proposed meeting.
Section 4. Notice of Meetings. Unless otherwise provided in the Act, written notice of every meeting of shareholders stating the place, if any, date, hour, the means of remote communications, if any, by which shareholders and proxyholders may be deemed to be present in person and vote at such meeting and, in the case of a special meeting, purposes thereof, shall, except when otherwise required by law, be given not less than ten (10) nor more than sixty (60) days before the date of the meeting to each shareholder entitled to vote thereat.
At any meeting at which a quorum of shareholders is present, in person or represented by proxy, the chairman of the meeting or the holders of the majority of the shares of stock present or represented by proxy may adjourn from time to time until its business is completed. When a meeting is adjourned to another time or place, notice need not be given of the adjourned meeting if the time, place, if any, thereof, and the means of remote communications, if any, by which shareholders and proxyholders may be deemed to be present in person and vote at such adjourned meeting are announced at the meeting at which the adjournment is taken. At the
adjourned meeting, the corporation may transact any business which might have been transacted at the original meeting. If the adjournment is for more than thirty (30) days, or if after the adjournment a new record date is fixed for the adjourned meeting, a notice of the adjourned meeting shall be given to each shareholder of record entitled to vote at the meeting. Otherwise, no notice need be given.
Attendance of a person at a meeting shall constitute a waiver of notice of such meeting, except when the person attends the meeting for the express purpose of objecting, at the beginning of the meeting, to the transaction of any business because the meeting is not lawfully called or convened.
Business transacted at any special meeting of shareholders shall be limited to the purposes stated in the notice.
Section 5. Quorum. The holders of a majority of the shares of stock entitled to vote, present in person or by proxy, shall, except as otherwise provided by law, constitute a quorum for the transaction of business at all meetings of the shareholders.
Section 6. Action Without Meeting.
(a) Unless otherwise provided in the Act or the Certificate of Incorporation, any action required or permitted to be taken at a meeting of the shareholders of the corporation may be taken without a meeting, without prior notice and without a vote, if a consent or consents in writing, setting forth the action so taken, shall be signed by the holders of outstanding stock having not less than the minimum number of votes that would be necessary to authorize or take such action at a meeting at which all shares entitled to vote thereon were present and voted. Such consent or consents shall be delivered to the corporation at its registered office in Oklahoma, at its principal place of business, or to an officer or agent of the corporation having custody of the book in which proceedings of meetings of shareholders are recorded. Delivery made to the corporations registered office shall be by hand or by certified or registered mail, return receipt requested.
(b) Every written consent shall bear the date of signature of each shareholder who signs the written consent, and no consent shall be effective to take the corporate action referred to therein unless, within sixty (60) days of the earliest dated consent delivered in the manner required by this Section 6 to the corporation, written consents signed by a sufficient number of shareholders to take action are delivered to the corporation in the manner required by this Section 6.
(c) A telegram, cablegram or other electronic transmission consenting to an action to be taken and transmitted by a shareholder or proxyholder, or by a person or persons authorized to act for a shareholder or proxyholder, shall be deemed to be written, signed and dated for the purposes of this Section 6, provided that any such telegram, cablegram or other electronic transmission sets forth or is delivered with information from which the corporation can determine: (i) that the telegram, cablegram or other electronic transmission was transmitted by the shareholder or proxyholder or by a person or persons authorized to act for the shareholder
2
or proxyholder and (ii) the date on which such shareholder or proxyholder or authorized person or persons transmitted such telegram, cablegram or electronic transmission. The date on which such telegram, cablegram or electronic transmission is transmitted shall be deemed to be the date on which such consent was signed. No consent given by telegram, cablegram or other electronic transmission shall be deemed to have been delivered until such consent is reproduced in paper form and until such paper form shall be delivered to the corporation by delivery to its registered office in Oklahoma, its principal place of business, or an officer or agent of the corporation having custody of the book in which proceedings of meetings of shareholders are recorded. Delivery made to the corporations registered office shall be made by hand or by certified or registered mail, return receipt requested. Notwithstanding the foregoing limitations on delivery, consents given by telegram, cablegram or other electronic transmission may be otherwise delivered to the principal place of business of the corporation or to an officer or agent of the corporation having custody of the book in which proceedings of meetings of shareholders are recorded, if to the extent and in the manner provided by resolution of the board of directors of the corporation.
(d) Prompt notice of the taking of corporate action without a meeting by less than unanimous written consent shall be given by the corporation to those shareholders who have not consented to the action in writing and who are entitled to receive such notice as provided in the Act.
Section 7. Voting. Unless otherwise provided by the corporations Certificate of Incorporation and any amendments thereto or certificates of designation, at every meeting of shareholders or, if action is to be taken by written consent without a meeting, each shareholder shall be entitled to one vote, in person or by proxy, for each share of stock having voting power held by such shareholder. Unless otherwise provided by law, no proxy shall be voted on or after three years from its date unless the proxy provides for a longer period. All elections and questions shall be decided by a plurality of the votes cast, in person or by proxy, except as otherwise required by law, or any stock exchange requirements or as set forth in the corporations Certificate of Incorporation, any amendments thereto, these bylaws or the terms of any series of outstanding preferred stock.
Section 8. List of Shareholders. Unless otherwise provided in the Act, at least ten (10) days before every meeting of shareholders, a complete list of the shareholders entitled to vote at the meeting, arranged in alphabetical order, and showing the address of each shareholder, and the number of shares registered in the name of each shareholder, shall be prepared by the officer in charge of the stock ledger. Such list shall be open to the examination of any shareholder, for any purpose germane to the meeting, for a period of at least ten (10) days prior to the meeting: (i) on a reasonably accessible electronic network, provided that the information required to gain access to such list is provided with the notice of the meeting, or (ii) during ordinary business hours, at the principal place of business of the corporation In the event that the corporation determines to make the list available on an electronic network, the corporation may take reasonable steps to ensure that such information is available only to shareholders of the corporation. If the meeting is to be held at a place, then the list shall be produced and kept at the time and place of the meeting during the whole time of the meeting and may be inspected by any shareholder who is present. If the meeting is to be held solely by means of remote
3
communication, then the list shall also be open to the examination of any shareholder during the whole time of the meeting on a reasonably accessible electronic network, and the information required to access such list shall be provided with the notice of the meeting. The stock ledger shall be the only evidence as to who are shareholders entitled to examine the stock ledger, the list required by this section or the books of the corporation, or to vote in person or by proxy at any meeting of shareholders.
Section 9. Organization. At each meeting of shareholders, the chairman of the board of directors, if one shall have been elected (or in his absence or if one shall not have been elected, the president), shall act as chairman of the meeting. The secretary (or in his absence or inability to act, the person whom the chairman of the meeting shall appoint secretary of the meeting) shall act as secretary of the meeting and keep the minutes thereof.
Section 10. Order of Business. The chairman of the meeting shall determine the order of business and the procedure at the meeting, including regulation of the manner of voting and the conduct of discussion.
Section 11. Nomination of Directors. Nominations of persons for election to the board of directors of the corporation may only be made by or at the direction of the board of directors. Any shareholder may recommend a potential nominee to the board of directors for consideration if the shareholder provides timely notice as provided in this Section 11 and if the shareholder is a shareholder of record at the time of giving such notice. To be timely, a shareholders notice must be delivered to or mailed and received at the principal executive offices of the corporation not less than 120 days prior to the meeting. In order to be effective the shareholders notice shall set forth (a) as to each person whom the shareholder proposes to nominate for election or re-election as a director all information relating to such person that is required to be disclosed in solicitations of proxies for election of directors, or is otherwise required, in each case pursuant to Regulation 14A under the Securities Exchange Act of 1934 (including such persons written consent to being named as a nominee, to be disclosed as a nominee and to serving as a director if elected); (b) a written consent by the shareholder or shareholders giving the notice permitting the disclosure of the identity of the recommending shareholder or shareholders; (c) a statement in support of the nominee stating why the person should be nominated for election to the board of directors; and (d) as to the shareholder giving the notice (i) the name and address, as they appear on the corporations books, of such shareholder, and (ii) the class and number of shares of stock of the corporation which are beneficially owned by such shareholder. At the request of the board of directors, any person nominated by the board of directors for election as a director shall furnish to the secretary of the corporation that information required to be set forth in a shareholders notice of nomination which pertains to the nominee. Notwithstanding anything in these bylaws to the contrary, no person shall be eligible to serve as a director of the corporation unless nominated in accordance with the procedures set forth in this Section 11. If the chairman of the meeting shall determine, based on the facts, that a nomination was not made in accordance with the procedures set forth in this Section 11, the chairman of the board or the chairman of the nomination committee of the board of directors may declare the nomination defective and the nomination will be disregarded. Each person validly nominated in accordance with this Section 11 (regardless of the source of recommendation) will be evaluated consistently in accordance with the board of directors policy regarding the identification, evaluation and nomination of
4
directors. Notwithstanding the foregoing provisions of this Section 11, a shareholder shall also comply with all applicable requirements of the Securities Exchange Act of 1934, and the rules and regulations thereunder, with respect to the matters set forth in this Section 11.
Section 12. Notice of Business. At any meeting of the shareholders, only such business shall be conducted as shall have been brought before the meeting (a) by or at the direction of the board of directors, or (b) by any shareholder of the corporation who is a shareholder of record at the time of giving of the notice provided for in this Section 12, who shall be entitled to vote at such meeting and who complies with the procedures set forth below. For business to be properly brought before a shareholder meeting by a shareholder, the shareholder must have given timely notice thereof in writing to the secretary of the corporation. To be timely, a shareholders notice must be delivered to or mailed and received at the principal executive offices of the corporation not less than sixty (60) days nor more than ninety (90) days prior to the meeting; provided, however, that in the event that less than seventy (70) days notice or prior public disclosure of the date of the meeting is given or made to shareholders, notice by the shareholder to be timely must be received no later than the close of business on the tenth day following the day on which notice of the date of the meeting was mailed or public disclosure thereof was made, whichever occurred first. Such shareholders notice shall set forth as to each matter the shareholder purposes to bring before the meeting (a) a brief description of the business desired to be brought before the meeting and the reasons for conducting such business at the meeting, (b) the name and address, as they appear on the corporations books, of the shareholder proposing such business, (c) the class and number of shares of stock of the corporation which are beneficially owned by the shareholder, and (d) any material interest of the shareholder in such business. Notwithstanding anything in these bylaws to the contrary, no business shall be conducted at a shareholder meeting except in accordance with the procedures set forth in this Section 12. If the chairman of the meeting shall determine, based on the facts, that business was not properly brought before the meeting in accordance with the procedures set forth in this Section 12, he shall so declare to the meeting and any such business not properly brought before the meeting shall not be transacted. Notwithstanding the foregoing provisions of this Section 12, a shareholder shall also comply with all application requirements of the Securities Exchange Act of 1934, and the rules and regulations thereunder with respect to the matters set forth in this Section 12.
Section 13. Action by Remote Communication. If authorized by the board of directors in its sole discretion, and subject to such guidelines and procedures as the board of directors may adopt, shareholders and proxyholders not physically present at a meeting of shareholders may, by means of remote communication: (i) participate in a meeting of shareholders and (ii) be deemed present in person and vote at a meeting of shareholders, whether such meeting is to be held at a designated place or solely by means of remote communication, provided that (A) the corporation shall implement reasonable measures to verify that each person deemed present and permitted to vote at the meeting by means of remote communication is a shareholder or proxyholder, (B) the corporation shall implement reasonable measures to provide such shareholders and proxyholders a reasonable opportunity to participate in the meeting and to vote on matters submitted to the shareholders, including an opportunity to read or hear the proceedings of the meeting substantially concurrently with such proceedings, and (C) if any shareholder or proxyholder votes or takes other action at the meeting by means of remote communication, a record of such vote or other action shall be maintained by the corporation.
5
Section 14. Inspectors of Elections. The corporation shall, in advance of any meeting of shareholders, appoint one or more inspectors to act at the meeting and make a written report thereof. The corporation may designate one or more persons as alternate inspectors to replace any inspector who fails to act. If no inspector or alternate is able to act at a meeting of shareholders, the person presiding at the meeting shall appoint one or more inspectors to act at the meeting. Each inspector, before entering upon the discharge of the duties of inspector, shall take and sign an oath faithfully to execute the duties of inspector with strict impartiality and according to the best of the inspectors ability. The inspectors shall ascertain the number of shares outstanding and the voting power of each, determine the number of shares represented at a meeting and the validity of proxies and ballots, count all votes and ballots, determine and retain for a reasonable period a record of the disposition of any challenges made to any determination by the inspectors, and certify their determination of the number of shares represented at the meeting and their count of all votes and ballots. The inspectors may appoint or retain other persons or entities to assist the inspectors in the performance of the duties of the inspectors.
ARTICLE II
Directors
Section 1. Powers. The business and affairs of the corporation shall be managed by or under the direction of its board of directors.
Section 2. Number; Election. The number of directors which shall constitute the whole board shall not be less than three nor more than nine, and shall be determined by resolution adopted by a vote of two-thirds (2/3) of the entire board, or at an annual or special meeting of shareholders by the affirmative vote of sixty-six and two-thirds percent (66- 2/3%) of the outstanding stock entitled to vote. No reduction in number shall have the effect of removing any director prior to the expiration of his term. In the event the number of directors which constitute the whole board shall be three or more, the board of directors shall be divided into three classes as nearly equal in number as possible with the term of office of one class expiring each year. At the first shareholders meeting following the election or appointment of three or more directors which constitute the whole board, the term of office of those of the first class shall expire at the first annual meeting after their election; the term of office of those of the second class shall expire at the second annual meeting after their election; and the term of office of those of the third class shall expire at the third annual meeting after their election. At each annual meeting held after such classification and election, directors shall be chosen for a full term of three years to succeed those whose terms expire.
No person may stand for election to, or be elected to, the board of directors or be appointed by the directors to fill a vacancy on the board of directors who shall have made, or be making, improper or unlawful use of the corporations confidential information. Directors need not be shareholders at the time of election but must be less than 80 years of age.
6
All elections of directors shall be by written ballot unless otherwise provided in the Certificate of Incorporation. However, if authorized by the board of directors, the ballot may be submitted by electronic transmission, provided that any such electronic transmission must either set forth, or be submitted with, information from which it can be determined that the electronic transmission was authorized by the shareholder or proxyholder.
Section 3. Vacancies. Vacancies and newly created directorships resulting from any increase in the authorized number of directors may be filled by a majority of the directors then in office, though less than a quorum, and the directors so chosen shall hold office until the next annual election of the class for which each such director has been chosen and until his successor is duly elected and qualified, or until his earlier resignation or removal.
Section 4. Place of Meetings. Board meetings may be held at such places, within or without the State of Oklahoma, as stated in these bylaws or as the board may, from time to time, determine or as may be specified in the call of any meetings.
Section 5. Regular Meetings. The annual meeting of the board shall be held without call or notice immediately after and at the same general place as the annual meeting of the shareholders, for the purpose of electing officers and transacting any other business that may properly come before the meeting. Additional regular meetings of the board may be held without call or notice at such place and at such time as shall be fixed by resolution of the board but in the absence of such resolution shall be held upon call by the president or a majority of directors.
Section 6. Special Meetings. Special meetings of the board may be called by the chairman of the board or the president or by a majority of the directors then in office. Notice of special meetings shall be given to each director at least three (3) days before the meeting. Such notice shall set forth the time and place of such meeting, but need not, unless otherwise required by law, state the purposes of the meeting. A majority of the directors present at any meeting may adjourn the meeting from time to time without notice other than announcement at the meeting.
Section 7. Quorum. A majority of the total number of directors, excluding any vacancies, shall constitute a quorum for the transaction of business at any meeting of the board; provided, however, that in no event shall a number which is less than one-third (1/3) of the total number of directors (excluding vacancies) constitute a quorum. If at any meeting a quorum is not present, a majority of the directors present may adjourn the meeting from time to time without notice other than announcement at the meeting until a quorum is present. The act of a majority of directors present in person at a meeting at which a quorum is present shall be the act of the board of directors.
Section 8. Presence at Meeting. Members of the board of directors, or of any committee thereof, may participate in a meeting of such board or committee by means of conference telephone or other communications equipment by means of which all persons participating in the meeting can hear each other, and such participation shall be deemed presence in person at such meeting.
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Section 9. Action Without Meeting. Any action required or permitted to be taken at any meeting of the board of directors, or of any committee thereof, may be taken without a meeting if all members of the board or such committee, as the case may be, consent thereto in writing or by electronic transmission, and such writing or electronic transmission is filed with the minutes of the proceedings of the board or such committee. Such filing shall be in paper form if the minutes are maintained in paper form and shall be in electronic form if the minutes are maintained in electronic form.
Section 10. Committees of the Board. The board of directors may, by resolution passed by a majority of the whole board, designate one or more committees, each such committee to consist of one or more of the directors of the corporation and shall have such name or names as may be determined from time to time by resolution adopted by the board. The board may designate one or more directors as alternate members of any committee who may replace any absent or disqualified member at any meeting of the committee. Any such committee, to the extent provided in the resolution, shall have and may exercise the powers of the board of directors in the management of the business and affairs of the corporation, and generally perform such duties and exercise such powers as may be directed or delegated by the board of directors from time to time and, furthermore, may authorize the seal of the corporation to be affixed to all papers which may require it; but no such committee shall have the power or authority in reference to amending the Certificate of Incorporation (except that a committee may, to the extent authorized in the resolution(s) providing for the issuance of shares of stock adopted by the board of directors as provided in Section 1032(A) of the Act, fix the designations and any of the preferences or rights of such shares relating to dividends, redemption, dissolution, any distribution of assets of the corporation or the conversion into, or the exchange of such shares for shares of any other class or classes or any other series of the same or any other class or classes or stock of the corporation or fix the number of shares of any series of stock or authorize the increase or decrease of the shares of any series), adopting an agreement of merger or consolidation, recommending to the shareholders the sale, lease or exchange of all or substantially all of the corporations property and assets, recommending to the shareholders a dissolution of the corporation or a revocation of a dissolution, or amending the bylaws of the corporation; and unless the resolution of the board of directors, the Certificate of Incorporation or these bylaws expressly so provide, no such committee shall have the power or authority to declare a dividend or to authorize the issuance of stock or to adopt a certificate of ownership and merger pursuant to the Act. In the absence or disqualification of any member of such committee or committees, the member or members thereof present at any meeting and not disqualified from voting, whether or not he or they constitute a quorum, may unanimously appoint another member of the board to act at the meeting in the place of such absent or disqualified member. Each such committee shall keep regular minutes of its proceedings and report the same to the board of directors as and when required.
Section 11. Compensation. Each director shall be reimbursed for reasonable expenses incurred in attending any meeting of the board or of any committee of which such director shall be a member. The board may, by resolution, allow reasonable fees to some or all of the directors for attendance at any board or committee meeting. No such payment shall preclude any directors from serving the corporation in any other capacity and receiving compensation therefor.
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Section 12. Advisory Directors. The board of directors may appoint individuals who may, but need not be, officers or employees of the corporation to serve as members of an advisory board of directors of the corporation and may fix fees or compensation for attendance at meetings of any such advisory board. The members of any such advisory board may adopt and from time to time may amend rules and regulations for the conduct of their meetings and shall keep minutes which shall be submitted to the board of directors of the corporation. The term of office of any member of the advisory board of directors shall be at the pleasure of the board of directors and shall expire the day of the annual meeting of the shareholders of the corporation. The function of any such advisory board of directors shall be to advise with respect to the affairs of the corporation.
Section 13. Resignation. Any director may resign at any time upon notice given in writing or by electronic transmission to the board of directors or to the secretary of the corporation. The resignation of any director shall take effect upon receipt of notice thereof or at such later time as shall be specified in such notice; and unless otherwise specified therein, the acceptance of such resignation shall not be necessary to make it effective.
Section 14. Removal. No director may be removed from office by the shareholders except for cause with the affirmative vote of the holders of not less than a majority of the total voting power of all outstanding securities of the corporation then entitled to vote generally in the election of directors voting together as a single class.
Section 15. Preferred Directors. Notwithstanding anything else contained herein, whenever the holders of one or more classes or series of preferred stock shall have the right, voting separately as a class or series, to elect directors, the nomination, election, term of office, filling of vacancies, removal and other features of such directorships shall be governed by the terms of the certificate of designation for such classes or series, and such directors so elected shall not be subject to the provisions of Sections 2, 3 and 14 of this Article II unless otherwise provided therein.
ARTICLE III
Officers and Employees
Section 1. Election. At the annual meeting of the board, there shall be elected such officers as may be necessary to enable the corporation to sign instruments and stock certificates which comply with the Act. Such officers may include a chairman of the board, chief executive officer, vice chairman of the board, a president, one or more vice presidents (who may be designated by different classes), a secretary, a treasurer and other officers. No officer need be a director. Two or more offices may be held by the same person.
Section 2. Term, Removal and Vacancies. All officers shall serve at the pleasure of the board. Any officer elected or appointed by the board may be removed at any time by the board whenever in its judgment the best interests of the corporation would be served thereby, but such removal shall be without prejudice to the contract rights, if any, of the person so removed. A vacancy in any office shall be filled by the board of directors.
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Section 3. Chairman of the Board. The chairman of the board, if one has been elected, shall preside at all meetings of the board, shareholders and committees of which he is a member. He shall have such powers and perform such duties as may be authorized by the board of directors.
Section 4. Chief Executive Officer. If the board of directors has elected a chairman of the board, it may designate the chairman of the board as the chief executive officer of the corporation. If no chairman of the board has been elected, or in his absence or inability to act, or if no such designation has been made by the board of directors, the president shall be the chief executive officer of the corporation. The chief executive officer shall (i) have the overall supervision of the business of the corporation and shall direct the affairs and policies of the corporation, subject to any directions which may be given by the board of directors, (ii) shall have authority to designate the duties and powers of officers and delegate special powers and duties to specified officers, so long as such designations shall not be inconsistent with the laws of the State of Oklahoma, these bylaws or action of the board of directors, and shall in general have all other powers and shall perform all other duties incident to the chief executive officer of a corporation and such other powers and duties as may be prescribed by the board of directors from time to time.
Section 5. Vice Chairman of the Board. The vice chairman of the board, if one has been elected, shall, in the absence or inability of the chairman of the board to act, preside at all meetings of shareholders, the board of directors and committees of which the chairman of the board is a member. The vice chairman of the board shall be subject to the control of the board of directors and chairman of the board. He shall have such powers and perform such duties as from time to time may be assigned to him by the board of directors or the chairman of the board.
Section 6. President. If the board of directors has elected a chairman of the board and designated such officer as the chief executive officer of the corporation, the president shall serve as chief operating officer and be subject to the control of the board of directors and the chairman of the board. He shall have such powers and perform such duties as from time to time may be assigned to him by the board of directors or the chairman of the board. If the board of directors has not elected a chairman of the board, or if one has been elected and has not been designated the chief executive officer of the corporation, then the president shall be the chief executive officer of the corporation with the powers and duties provided in Article III, Section 4, of these bylaws. In any event, the president shall have the power to execute, and shall execute, bonds, deeds, mortgages, extensions, agreements, modification of mortgage agreements, leases and contracts or other instruments of the corporation except where required or permitted by law to be otherwise signed and executed and except where the signing and execution thereof shall be expressly delegated by the board of directors or by the president to some other officer or agent of the corporation. The chairman of the board, if there is one, or the president, may give a proxy to any other person to vote all shares of the stock of any other corporation standing in the name of the corporation. The president, in general, shall have all other powers and shall perform all other duties as may be prescribed by the board of directors from time to time.
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Section 7. Vice Presidents. A vice president shall perform such duties as may from time to time be assigned to him by the board or by the chairman, the vice chairman or the president. In the absence or inability to act of the president, the vice president (or if there is more than one vice president, in the order designated by the board and, absent such designation, in the order of their first election to that office) shall perform the duties and discharge the responsibilities of the president.
Section 8. Secretary. The secretary shall be the keeper of the corporate seal and records, and shall give notice of, attend and record minutes of meetings of shareholders and directors. He shall see that the seal is affixed to all documents on which the seal is required by law to be affixed, the execution of which on behalf of the corporation under its seal is duly authorized in accordance with the provisions of these bylaws. He shall, in general, perform all duties incident to the office of secretary and such other duties as may be assigned to him by the board or by the president. The assistant secretaries, if any, shall have such duties as shall be delegated to them by the secretary and, in the absence of the secretary, the senior of them present shall discharge the duties of the secretary.
Section 9. Treasurer. The treasurer shall be responsible for (i) the custody and safekeeping of all of the funds and securities of the corporation, (ii) the receipt and deposit of all monies paid to the corporation, (iii) where necessary or appropriate, the endorsement for collection on behalf of the corporation of all checks, drafts, notes and other obligations payable to the corporation, (iv) the disbursement of funds of the corporation under such rules as the board may from time to time adopt, (v) maintaining the general books of account of the corporation, and (vi) the performance of such further duties as are incident to the office of treasurer or as may be assigned to him by the board or by the president. The assistant treasurers, if any, shall have such duties as shall be delegated to them by the treasurer, and in the absence of the treasurer, the senior one of them present shall discharge the duties of the treasurer.
Section 10. Divisional Officers. The board may from time to time appoint officers of various divisions of the corporation. Divisional officers shall not by virtue of such appointment become officers of the corporation. Subject to the direction of the president of the corporation, the president of a division shall have general charge, control and supervision of all the business operations of his division, and the other divisional officers shall have such duties and authority as may be prescribed by the president of the division.
ARTICLE IV
Stock Certificates and Transfer Books
Section 1. Certificates. Every shareholder shall be entitled to have a certificate in such form as the board shall from time to time approve, signed by, or in the name of, the corporation by (i) the chairman of the board, if any, the president or any vice president and (ii) the treasurer, or assistant treasurer, or the secretary or an assistant secretary, certifying the number of shares owned by him in the corporation. During the time in which the corporation is authorized to issue more than one class of stock or more than one series of any class, there shall be set forth on the face or back of each certificate issued a statement that the corporation will
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furnish without charge to each shareholder who so requests, the designations, preferences and relative, participating, option or other special rights of each class of stock or series thereof of the corporation and the qualifications, limitations or restrictions of such preferences and/or rights.
The signatures of any of the officers on a certificate may be facsimiles. In case any officer who has signed or whose facsimile signature has been placed upon a certificate shall have ceased to be such officer before such certificate is issued, it may be issued by the corporation with the same effect as if he were such officer at the date of issue.
Section 2. Record Ownership. A record of the name and address of the holder of each certificate, the number of shares represented thereby, and the date of issue thereof shall be made on the corporations books. The corporation shall be entitled to treat the holder of record of any share or shares of stock as the holder in fact thereof, and, accordingly, shall not be bound to recognize any equitable or other claim to or interest in any share on the part of any other person, whether or not it shall have express or other notice thereof, except as required by the laws of Oklahoma.
Section 3. Transfer Agent and Registrar. The corporation may maintain one or more transfer offices or agencies, each in the charge of a transfer agent designated by the board, where the shares of stock of the corporation shall be transferable. The corporation may also maintain one or more registry offices, each in the charge of a registrar designated by the board, wherein such shares of stock shall be registered. To the extent authorized by the board, the same entity may serve both as a transfer agent and registrar.
Section 4. Lost Certificates. Any person claiming a stock certificate in lieu of one lost, stolen, mutilated or destroyed shall give the corporation an affidavit as to his ownership of the certificate and of the facts which go to prove its loss, theft, mutilation or destruction. He shall also, if required by the board, give the corporation a bond, in such form as may be approved by the board, sufficient to indemnify the corporation against any claim that may be made against it on account of the alleged loss or theft of the certificate or the issuance of a new certificate.
Section 5. Transfer of Stock. Transfer of shares shall, except as provided in Section 4 of this Article IV, be made on the books of the corporation only by direction of the person named in the certificate or his attorney, lawfully constituted in writing, and only upon surrender for cancellation of the certificate therefor, duly endorsed or accompanied by a written assignment of the shares evidenced thereby.
Section 6. Fixing Date for Determination of Shareholders of Record.
(a) In order that the corporation may determine the shareholders entitled to notice of or to vote at any meeting of shareholders or any adjournment thereof, or to express consent to any corporate action in writing without a meeting, or entitled to receive payment of any dividend or other distribution or allotment of any rights, or entitled to exercise any rights in respect of any change, conversion or exchange of stock or for the purpose of any other lawful action, the board may fix, in advance, a record date, which shall not be more than sixty (60) nor less than ten (10) days before the date of such meetings, nor more than sixty (60) prior to any other action.
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(b) A determination of shareholders of record entitled to notice of and to vote at a meeting of shareholders shall apply to any adjournment of the meeting; provided, however, that the board may fix a new record date for the adjourned meeting.
ARTICLE V
General Provisions
Section 1. Offices. The principal office of the corporation shall be maintained in Oklahoma City, Oklahoma, or at such other place as the board may determine. The corporation may have such other offices as the board may from time to time determine.
Section 2. Voting of Stock. Unless otherwise ordered by the board, the chairman of the board, if any, the president or any vice president shall have full power and authority, in the name and on behalf of the corporation, to attend, act and vote at any meeting of shareholders of any company in which the corporation may hold shares of stock, and at any such meeting shall possess and may exercise any and all rights and powers incident to the ownership of such shares and which, as the holder thereof, the corporation might possess and exercise if personally present, and may exercise such power and authority through the execution of proxies or may delegate such power and authority to any other officer, agent or employee of the corporation.
Section 3. Notices.
(a) Unless otherwise provided herein, whenever notice is required to be given, it shall not be construed to require personal notice, but such notice may be given in writing by depositing the same in the United States mail, addressed to the individual to whom notice is being given at such address as appears on the records of the corporation, with postage thereon prepaid. Such notice shall be deemed to be given at the time when the same shall be thus deposited.
(b) Without limiting the manner by which notice otherwise may be given effectively to shareholders, any notice to shareholders given by the corporation under any provision of the Act, the Certificate of Incorporation, or these bylaws shall be effective if given by a form of electronic transmission consented to by the shareholder to whom the notice is given. Any such consent shall be revocable by the shareholder by written notice to the corporation. Any such consent shall be deemed revoked if: (i) the corporation is unable to deliver by electronic transmission two (2) consecutive notices given by the corporation in accordance with such consent and (ii) such inability becomes known to the secretary or an assistant secretary of the corporation or to the transfer agent, or other person responsible for the giving of notice; provided, however, the inadvertent failure to treat such inability as a revocation shall not invalidate any meeting or other action.
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(c) Notice given pursuant to Section 3(b) shall be deemed given if by: (i) facsimile telecommunication, when directed to a number at which the shareholder has consented to receive notice; (ii) electronic mail, when directed to an electronic mail address at which the shareholder has consented to receive notice; (iii) a posting on an electronic network together with separate notice to the shareholder of such specific posting, upon the later of (A) such posting and (B) the giving of such separate notice; and (iv) any other form of electronic transmission, when directed to the shareholder, in accordance with the shareholders consent.
(d) An affidavit of the secretary or an assistant secretary or of the transfer agent or other agent of the corporation that the notice has been given by a form of electronic transmission shall, in the absence of fraud, be prima facie evidence of the facts stated therein.
Section 4. Waiver of Notice. Whenever any notice is required to be given, a waiver thereof in writing, signed by the person or persons entitled to the notice, or a waiver by electronic transmission by the person or persons entitled to such notice, whether before or after the time stated therein, shall be deemed equivalent thereto.
Section 5. Exception to Notice. The giving of any notice required under any provision of the Act, the Certificate of Incorporation or these bylaws shall not be required to be given to any shareholder to whom: (i) notice of two consecutive annual meetings and all notices of meetings or of the taking of action by written consent without a meeting to such shareholder during the period between such two consecutive annual meetings, or (ii) all, and at least two, payments (if sent by first-class mail) of dividends or interest on securities during a twelve-month period, have been mailed addressed to such person at such persons address as shown on the records of the corporation and have been returned undeliverable. If any such shareholder shall deliver to the corporation a written notice setting forth such shareholders then current address, the requirement that such notice be given to such shareholder shall be reinstated. The exception provided for in this Section 5 to the requirement that notice be given shall not be applicable to any notice returned as undeliverable if the notice was given by electronic transmission.
ARTICLE VI
Indemnification of Officers, Directors, Employees and Agents
(a) The corporation shall indemnify any person who was or is a party or is threatened to be made a party to any threatened, pending or completed action, suit or proceeding whether civil, criminal, administrative or investigative (other than an action by or in the right of the corporation) by reason of the fact that he is or was a director, officer, employee or agent of the corporation or is or was serving at the request of the corporation as a director, officer, employee or agent of another corporation, partnership, joint venture or other enterprise against expenses (including attorneys fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by him in connection with such action, suit or proceeding, if he acted in good faith and in a manner he reasonably believed to be in or not opposed to the best interest of the corporation and, with respect to any criminal action or proceeding, had no reasonable cause to believe that his conduct was unlawful. The termination of any action, suit or proceeding by judgment, order, settlement, conviction or upon a plea of nolo contendre or its
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equivalent shall not of itself create a presumption that the person did not act in good faith and in a manner which he reasonably believed to be in or not opposed to the best interest of the corporation and with respect to any criminal action or proceeding had reasonable cause to believe that his conduct was unlawful.
(b) The corporation shall indemnify any person who was or is a party or is threatened to be made a party to any threatened, pending or completed action or suit by or in the right of the corporation to procure a judgment in its favor by reason of the fact that he is or was a director, officer, employee or agent of the corporation or is or was serving at the request of the corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise against expenses (including attorneys fees) actually and reasonably incurred by him in connection with the defense or settlement of such action or suit, if he acted in good faith and in a manner he reasonably believed to be in or not opposed to the best interest of the corporation; except that no indemnification shall be made in respect of any claim, issue or matter as to which such person shall have been adjudged to be liable to the corporation unless and only to the extent that the court in which such action or suit was brought shall determine, upon application, that despite the adjudication of liability, but in the view of all the circumstances of the case, such person is fairly and reasonably entitled to indemnity for such expenses which the court shall deem proper.
(c) Expenses incurred in defending a civil or criminal action, suit or proceeding may be paid by the corporation in advance of the final disposition of such action, suit or proceeding upon receipt of an undertaking by or on behalf of the director, officer, employee or agent to repay such amount if it shall ultimately be determined that he is not entitled to be indemnified by the corporation as authorized herein.
(d) The corporation may purchase (upon resolution duly adopted by the board of directors) and maintain insurance on behalf of any person who is or was a director, officer, employee or agent of the corporation, or is or was serving at the request of the corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise against any liability asserted against him and incurred by him in any such capacity, or arising out of his status as such, whether or not the corporation would have the power to indemnify him against such liability.
(e) To the extent that a director, officer, employee or agent of the corporation has been successful on the merits or otherwise in defense of any action, suit or proceeding referred to herein or in defense of any claim, issue or matter therein, he shall be indemnified against expenses (including attorneys fees) actually and reasonably incurred by him in connection therewith.
(f) Every such person shall be entitled, without demand by him upon the corporation or any action by the corporation, to enforce his right to such indemnity in an action at law against the corporation. The right of indemnification and advancement of expenses hereinabove provided shall not be deemed exclusive of any rights to which any such person may now or hereafter be otherwise entitled and specifically, without limiting the generality of the foregoing, shall not be deemed exclusive of any rights pursuant to statute or otherwise, of any
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such person in any such action, suit or proceeding to have assessed or allowed in his favor against the corporation or otherwise, his costs and expenses incurred therein or in connection therewith or any part thereof.
ARTICLE VII
Amendments
These bylaws may be altered, amended or repealed or new bylaws may be adopted in accordance with the corporations Certificate of Incorporation, as the same may be amended or supplemented, and the Act.
I hereby certify that the foregoing is a full, true and correct copy of the bylaws of Chesapeake Energy Corporation, an Oklahoma corporation, as in effect on the date hereof.
Dated this 5th day of March, 2004.
|
Jennifer M. Grigsby, Secretary |
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Exhibit 4.2.1
FIFTEENTH SUPPLEMENTAL INDENTURE
FIFTEENTH SUPPLEMENTAL INDENTURE (this Supplemental Indenture), dated as of November 26, 2003 is by and among Chesapeake Energy Corporation, an Oklahoma corporation (the Company), the Subsidiary Guarantors (as defined in the Indenture referred to herein), The Bank of New York, as successor to United States Trust Company of New York, as trustee under the Indenture referred to below (the Trustee). All capitalized terms not defined herein shall have the meaning ascribed to them in the Indenture.
WHEREAS, the Company has heretofore executed and delivered to the Trustee an indenture (the Indenture), dated as of March 15, 1997, and such Indenture was supplemented and amended by (i) the First Supplemental Indenture dated December 17, 1997, (ii) the Second Supplemental Indenture dated February 16, 1998, (iii) the Second [Third] Supplemental Indenture dated April 22, 1998, (iv) the Fourth Supplemental Indenture dated July 1, 1998, (v) the Fifth Supplemental Indenture dated November 19, 1999, (vi) the Sixth Supplemental Indenture dated December 31, 1999, (vii) the Seventh Supplemental Indenture dated September 12, 2001, (viii) the Eighth Supplemental Indenture dated October 1, 2001 (ix) the Ninth Supplemental Indenture dated December 17, 2001, (x) the Tenth Supplemental Indenture dated as of June 28, 2002, (xi) the Eleventh Supplement Indenture dated as of July 8, 2002, (xii) the Twelfth Supplemental Indenture dated as of February 14, 2003, (xiii) the Thirteenth Supplemental Indenture dated as of May 1, 2003 and (xiv) the Fourteenth Supplemental Indenture dated as of August 15, 2003.
WHEREAS, on March 15, 1997, the Company issued $120,000,000 aggregate principal amount of its 8.5% Senior Notes due 2012;
WHEREAS, Section 9.02 of the Indenture provides that, with the consent of the Holders of a majority in aggregate principal amount of the Notes then outstanding (including consents obtained in connection with a tender offer for the Notes), the Company, when authorized by a resolution of its Board of Directors, and the Trustee may enter into a supplemental to the Indenture for the purpose of amending or supplementing any provisions of the Indenture (with certain exceptions not relevant to this Supplemental Indenture);
WHEREAS, the Company and the Subsidiary Guarantors desire and have requested the Trustee to join with them in entering into this Supplemental Indenture for the purpose of amending the Indenture to remove certain covenants and events of default as permitted by Section 9.02 of the Indenture;
WHEREAS, the Company has solicited consents to this Supplemental Indenture upon the terms and subject to the conditions set forth in its Offer to Purchase and Consent Solicitation Statement dated November 12, 2003 and the related Letter of Transmittal and Consent (which together constitute the Tender Offer);
WHEREAS, the Company (1) has received the consent of the Holders of more than 50% in aggregate principal amount of the outstanding Notes, (2) has delivered to the Trustee an Opinion of Counsel relating to this Supplemental Indenture as contemplated by Section 9.06 of the Indenture and (3) has satisfied all other conditions required under Article 9 of the Indenture to enable the Company and the Trustee to enter into this Supplemental Indenture.
NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Company, the Subsidiary Guarantors and the Trustee mutually covenant and agree for the equal and ratable benefit of the Holders as follows:
ARTICLE I
DEFINITIONS
1.1 Deletion of Definitions and Related References. Section 1.1 of Article 1 of the Indenture is hereby amended to delete in their entirety all terms and their respective definitions for which all references are eliminated in the Indenture as a result of the amendments set forth in Article II of this Supplemental Indenture.
G-1
ARTICLE II
AMENDMENTS TO INDENTURE
2.1 Amendments to Articles 4, 5 and 6. The Indenture is hereby amended by deleting the following sections of the Indenture and all references thereto in their entirety: Section 4.2 (SEC Reports); Section 4.3 (Compliance Certificates); Section 4.4 (Maintenance of an Office or Agency); Section 4.5 (Corporate Existence) Section 4.6 (Waiver of Stay, Extension or Usury Laws); Section 4.7 (Payment of Taxes and Other Claims); Section 4.8 (Maintenance of Properties and Insurance); Section 4.9 (Limitation on Liens); Section 4.10 (Limitation on Sale/Leaseback Transactions); Section 5.1 (When Company May Merge, etc.) and each of subsections (4), (5), (6), (8) and (9) of Section 6.1 (Events of Default).
ARTICLE III
MISCELLANEOUS
3.1 Definitions. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture. For all purposes of this Supplemental Indenture, except as otherwise herein expressly provided or unless the context otherwise requires, the words herein, hereof and hereby and other words of similar import used in this Supplemental Indenture refer to this Supplemental Indenture as a whole and not to any particular section hereof.
4.2 Ratification of Indenture; Supplemental Indenture Part of Indenture. Except as expressly amended hereby, the Indenture is in all respects ratified and confirmed and all the terms, conditions and provisions thereof shall remain in full force and effect. This Supplemental Indenture shall form a part of the Indenture for all purposes, and every Holder of Notes heretofore or hereafter authenticated and delivered under the Indenture shall be bound hereby and all terms and conditions of both shall be read together as though they constitute a single instrument, except that in the case of conflict the provisions of this Supplemental Indenture shall control.
4.3 Endorsement and Change of Form of Notes. Any Notes authenticated and delivered after the close of business on the date that this Supplemental Indenture becomes operative in substitution for Notes then outstanding and all Notes presented or delivered to the Trustee on and after that date for such purpose shall be stamped, imprinted or otherwise legended by the Trustee, with a notation as follows:
Effective as of November 26, 2003 certain restrictive covenants of the Company and certain Events of Default have been eliminated or limited, as provided in the Fifteenth Supplemental Indenture, dated as of November 26, 2003. Reference is hereby made to said Fifteenth Supplemental Indenture, copies of which are on file with the Trustee, for a description of the amendments made therein.
4.4 Governing Law. This Supplemental Indenture shall be governed by and construed in accordance with the laws of the State of New York.
4.5 Trustee Makes No Representation. The Trustee makes no representation as to the validity or sufficiency of this Supplemental Indenture or for or in respect of the recitals contained herein, all of which are made solely by the Company and the Guarantors.
4.6 Counterparts. The parties may sign any number of copies or counterparts of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.
4.7 Effect of Headings. The Section headings herein are for convenience only and shall not affect the construction thereof.
[remainder of page intentionally left blank]
IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed as of the date first above written.
COMPANY:
CHESAPEAKE ENERGY CORPORATION
By: | /s/ MARTHA A. BURGER | |
Name: | Martha A. Burger | |
Title: | Treasurer and Sr. Vice President Human Resources |
SUBSIDIARY GUARANTORS:
CHESAPEAKE BETA CORP.
CHESAPEAKE DELTA CORP.
CHESAPEAKE ENERGY LOUISIANA CORPORATION
CHESAPEAKE OPERATING, INC.
NOMAC DRILLING CORPORATION
CARMEN ACQUISITION, L.L.C.
CHESAPEAKE ACQUISITION, L.L.C.
CHESAPEAKE ENO ACQUISITION, L.L.C.
CHESAPEAKE FOCUS, L.L.C.
CHESAPEAKE KNAN ACQUISITION, L.L.C.
CHESAPEAKE MOUNTAIN FRONT, L.L.C.
CHESAPEAKE ORC, L.L.C.
CHESAPEAKE ROYALTY, L.L.C.
GOTHIC ENERGY, L.L.C.
GOTHIC PRODUCTION, L.L.C.
SAP ACQUISITION, L.L.C.
THE AMES COMPANY, L.L.C.
By: | /s/ MARTHA A. BURGER | |
Name: | Martha A. Burger | |
Title: | Treasurer and Sr. Vice President Human Resources |
CHESAPEAKE EXPLORATION LIMITED PARTNERSHIP
CHESAPEAKE LOUISIANA, L.P.
CHESAPEAKE PANHANDLE LIMITED PARTNERSHIP
CHESAPEAKE-STAGHORN ACQUISITION L.P.
CHESAPEAKE SIGMA, L.P.
By: Chesapeake Operating, Inc., as general partner of each representative entity
By: | /s/ MARTHA A. BURGER | |
Name: | Martha A. Burger | |
Title: | Treasurer and Sr. Vice President Human Resources |
TRUSTEE:
THE BANK OF NEW YORK, as successor to United States Trust Company of New York, as Trustee
By: | /s/ LOUIS P. YOUNG | |
Name: | Louis P. Young | |
Title: | Vice-President |
Ex. 4.3.1
CHESAPEAKE ENERGY CORPORATION
and
the Subsidiary Guarantors named herein
8 1/8% SENIOR NOTES DUE 2011
TENTH SUPPLEMENTAL INDENTURE
DATED AS OF March 5, 2004
THE BANK OF NEW YORK
as successor Trustee to
United States Trust Company of New York
THIS TENTH SUPPLEMENTAL INDENTURE, dated as of March 5, 2004, is among Chesapeake Energy Corporation, an Oklahoma corporation (the Company), each of the parties identified under the caption Subsidiary Guarantors on the signature page hereto (the Subsidiary Guarantors) and The Bank of New York, as successor to United States Trust Company of New York, as Trustee.
RECITALS
WHEREAS, the Company, the Subsidiary Guarantors a party thereto and the Trustee entered into an Indenture, dated as of April 6, 2001, as supplemented prior to the date hereof (the Indenture), pursuant to which the Company has originally issued $800,000,000 in principal amount of 8 1/8% Senior Notes due 2011 (the Notes); and
WHEREAS, Section 9.01(3) of the Indenture provides that the Company, the Subsidiary Guarantors and the Trustee may amend or supplement the Indenture without notice to or consent of any Holder to reflect the addition of any Subsidiary Guarantor, as provided for in the Indenture; and
WHEREAS, the Board of Directors of the Company has designated Chesapeake PRH Corp., Chesapeake Permian Acquisition, L.L.C., Chesapeake Permian, L.P. and Chesapeake Zapata, L.P. as Restricted Subsidiaries of the Company and desires to add such entities as Subsidiary Guarantors under the Indenture; and
WHEREAS, all acts and things prescribed by the Indenture, by law and by the charter and the bylaws (or comparable constituent documents) of the Company, of the Subsidiary Guarantors and of the Trustee necessary to make this Tenth Supplemental Indenture a valid instrument legally binding on the Company, the Subsidiary Guarantors and the Trustee, in accordance with its terms, have been duly done and performed;
NOW, THEREFORE, to comply with the provisions of the Indenture and in consideration of the above premises, the Company, the Subsidiary Guarantors and the Trustee covenant and agree for the equal and proportionate benefit of the respective Holders of the Notes as follows:
ARTICLE 1
Section 1.01. This Tenth Supplemental Indenture is supplemental to the Indenture and does and shall be deemed to form a part of, and shall be construed in connection with and as part of, the Indenture for any and all purposes.
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Section 1.02. This Tenth Supplemental Indenture shall become effective immediately upon its execution and delivery by each of the Company, the Subsidiary Guarantors and the Trustee.
ARTICLE 2
Section 2.01. From this date, in accordance with Section 10.03 of the Indenture and by executing this Tenth Supplemental Indenture, Chesapeake PRH Corp., an Oklahoma corporation, Chesapeake Permian Acquisition, L.L.C., an Oklahoma limited liability company, Chesapeake Permian, L.P., an Oklahoma limited partnership, and Chesapeake Zapata, L.P., an Oklahoma limited partnership, are subject to the provisions of the Indenture as Subsidiary Guarantors to the extent provided for in Article Ten thereunder.
ARTICLE 3
Section 3.01. Except as specifically modified herein, the Indenture and the Notes are in all respects ratified and confirmed (mutatis mutandis) and shall remain in full force and effect in accordance with their terms with all capitalized terms used herein without definition having the same respective meanings ascribed to them as in the Indenture.
Section 3.02. Except as otherwise expressly provided herein, no duties, responsibilities or liabilities are assumed, or shall be construed to be assumed, by the Trustee by reason of this Tenth Supplemental Indenture. This Tenth Supplemental Indenture is executed and accepted by the Trustee subject to all the terms and conditions set forth in the Indenture with the same force and effect as if those terms and conditions were repeated at length herein and made applicable to the Trustee with respect hereto.
Section 3.03. The Company hereby notifies the Trustee that Chesapeake PRH Corp., Chesapeake Permian Acquisition, L.L.C., Chesapeake Permian, L.P. and Chesapeake Zapata, L.P. have each been designated by the Board of Directors of the Company as a Restricted Subsidiary (as that term is defined in the Indenture).
Section 3.04. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE AND ENFORCE THIS TENTH SUPPLEMENTAL INDENTURE.
Section 3.05. The parties may sign any number of copies of this Tenth Supplemental Indenture. Each signed copy shall be an
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original, but all of such executed copies together shall represent the same agreement.
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IN WITNESS WHEREOF, the parties hereto have caused this Tenth Supplemental Indenture to be duly executed, all as of the date first written above.
COMPANY: | ||
CHESAPEAKE ENERGY CORPORATION | ||
By | /s/ AUBREY K. MCCLENDON | |
Name: |
Aubrey K. McClendon | |
Title: |
Chief Executive Officer |
SUBSIDIARY GUARANTORS: | ||
CHESAPEAKE SOUTH TEXAS CORP. | ||
CHESAPEAKE ENERGY LOUISIANA CORPORATION | ||
CHESAPEAKE EP CORPORATION | ||
CHESAPEAKE OPERATING, INC. | ||
NOMAC DRILLING CORPORATION | ||
CARMEN ACQUISITION, L.L.C. | ||
CHESAPEAKE ACQUISITION, L.L.C. | ||
CHESAPEAKE ENO ACQUISITION, L.L.C. | ||
CHESAPEAKE FOCUS, L.L.C. | ||
CHESAPEAKE KNAN ACQUISITION, L.L.C. | ||
CHESAPEAKE MOUNTAIN FRONT, L.L.C. | ||
CHESAPEAKE ORC, L.L.C. | ||
CHESAPEAKE ROYALTY, L.L.C. | ||
GOTHIC ENERGY, L.L.C. | ||
GOTHIC PRODUCTION, L.L.C. | ||
SAP ACQUISITION, L.L.C. | ||
THE AMES COMPANY, L.L.C. | ||
MC MINERAL COMPANY, L.L.C. | ||
JOHN C. OXLEY, L.L.C. | ||
OXLEY PETROLEUM CO. CHESAPEAKE PRH CORP. | ||
CHESAPEAKE PERMIAN ACQUISITION, L.L.C. | ||
By | /s/ AUBREY K. MCCLENDON | |
Name: |
Aubrey K. McClendon | |
Title: |
Chief Executive Officer |
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CHESAPEAKE EXPLORATION LIMITED PARTNERSHIP | ||
CHESAPEAKE LOUISIANA, L.P. | ||
CHESAPEAKE PANHANDLE LIMITED PARTNERSHIP | ||
CHESAPEAKE-STAGHORN ACQUISITION L.P. | ||
CHESAPEAKE SIGMA, L.P. | ||
CHESAPEAKE PERMIAN, L.P. | ||
CHESAPEAKE ZAPATA, L.P. | ||
By: | Chesapeake Operating, Inc. as general partner of each representative entity | |
By |
/s/ AUBREY K. MCCLENDON | |
Name: |
Aubrey K. McClendon | |
Title: |
Chief Executive Officer |
TRUSTEE: | ||
THE BANK OF NEW YORK, as successor to United States Trust Company of New York, as Trustee | ||
By | /s/ LOUIS P. YOUNG | |
Name: |
Louis P. Young | |
Title: |
Vice President |
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Ex. 4.4.1
CHESAPEAKE ENERGY CORPORATION
and
the Subsidiary Guarantors named herein
8.375% SENIOR NOTES DUE 2008
SEVENTH SUPPLEMENTAL INDENTURE
DATED AS OF March 5, 2004
THE BANK OF NEW YORK
as Trustee
THIS SEVENTH SUPPLEMENTAL INDENTURE, dated as of March 5, 2004, is among Chesapeake Energy Corporation, an Oklahoma corporation (the Company), each of the parties identified under the caption Subsidiary Guarantors on the signature page hereto (the Subsidiary Guarantors) and The Bank of New York, as Trustee.
RECITALS
WHEREAS, the Company, the Subsidiary Guarantors a party thereto and the Trustee entered into an Indenture, dated as of November 5, 2001, as supplemented prior to the date hereof (the Indenture), pursuant to which the Company has originally issued $250,000,000 in principal amount of 8.375% Senior Notes due 2008 (the Notes); and
WHEREAS, Section 9.01(3) of the Indenture provides that the Company, the Subsidiary Guarantors and the Trustee may amend or supplement the Indenture without notice to or consent of any Holder to reflect the addition of any Subsidiary Guarantor, as provided for in the Indenture; and
WHEREAS, the Board of Directors of the Company has designated Chesapeake PRH Corp., Chesapeake Permian Acquisition, L.L.C., Chesapeake Permian, L.P. and Chesapeake Zapata, L.P. as Restricted Subsidiaries of the Company and desires to add such entities as Subsidiary Guarantors under the Indenture; and
WHEREAS, all acts and things prescribed by the Indenture, by law and by the charter and the bylaws (or comparable constituent documents) of the Company, of the Subsidiary Guarantors and of the Trustee necessary to make this Seventh Supplemental Indenture a valid instrument legally binding on the Company, the Subsidiary Guarantors and the Trustee, in accordance with its terms, have been duly done and performed;
NOW, THEREFORE, to comply with the provisions of the Indenture and in consideration of the above premises, the Company, the Subsidiary Guarantors and the Trustee covenant and agree for the equal and proportionate benefit of the respective Holders of the Notes as follows:
ARTICLE 1
Section 1.01. This Seventh Supplemental Indenture is supplemental to the Indenture and does and shall be deemed to form a part of, and shall be construed in connection with and as part of, the Indenture for any and all purposes.
Section 1.02. This Seventh Supplemental Indenture shall become effective immediately upon its execution and delivery by each of the Company, the Subsidiary Guarantors and the Trustee.
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ARTICLE 2
Section 2.01. From this date, in accordance with Section 10.03 of the Indenture and by executing this Seventh Supplemental Indenture, Chesapeake PRH Corp., an Oklahoma corporation, Chesapeake Permian Acquisition, L.L.C., an Oklahoma limited liability company, Chesapeake Permian, L.P., an Oklahoma limited partnership, and Chesapeake Zapata, L.P., an Oklahoma limited partnership, are subject to the provisions of the Indenture as Subsidiary Guarantors to the extent provided for in Article Ten thereunder.
ARTICLE 3
Section 3.01. Except as specifically modified herein, the Indenture and the Notes are in all respects ratified and confirmed (mutatis mutandis) and shall remain in full force and effect in accordance with their terms with all capitalized terms used herein without definition having the same respective meanings ascribed to them as in the Indenture.
Section 3.02. Except as otherwise expressly provided herein, no duties, responsibilities or liabilities are assumed, or shall be construed to be assumed, by the Trustee by reason of this Seventh Supplemental Indenture. This Seventh Supplemental Indenture is executed and accepted by the Trustee subject to all the terms and conditions set forth in the Indenture with the same force and effect as if those terms and conditions were repeated at length herein and made applicable to the Trustee with respect hereto.
Section 3.03. The Company hereby notifies the Trustee that Chesapeake PRH Corp., Chesapeake Permian Acquisition, L.L.C., Chesapeake Permian, L.P. and Chesapeake Zapata, L.P. have each been designated by the Board of Directors of the Company as a Restricted Subsidiary (as that term is defined in the Indenture).
Section 3.04. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE AND ENFORCE THIS SEVENTH SUPPLEMENTAL INDENTURE.
Section 3.05. The parties may sign any number of copies of this Seventh Supplemental Indenture. Each signed copy shall be an original, but all of such executed copies together shall represent the same agreement.
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IN WITNESS WHEREOF, the parties hereto have caused this Seventh Supplemental Indenture to be duly executed, all as of the date first written above.
COMPANY: | ||
CHESAPEAKE ENERGY CORPORATION | ||
By | /s/ AUBREY K. MCCLENDON | |
Name: |
Aubrey K. McClendon | |
Title: |
Chief Executive Officer |
SUBSIDIARY GUARANTORS: | ||
CHESAPEAKE SOUTH TEXAS CORP. | ||
CHESAPEAKE ENERGY LOUISIANA CORPORATION | ||
CHESAPEAKE EP CORPORATION | ||
CHESAPEAKE OPERATING, INC. | ||
NOMAC DRILLING CORPORATION | ||
CARMEN ACQUISITION, L.L.C. | ||
CHESAPEAKE ACQUISITION, L.L.C. | ||
CHESAPEAKE ENO ACQUISITION, L.L.C. | ||
CHESAPEAKE FOCUS, L.L.C. | ||
CHESAPEAKE KNAN ACQUISITION, L.L.C. | ||
CHESAPEAKE MOUNTAIN FRONT, L.L.C. | ||
CHESAPEAKE ORC, L.L.C. | ||
CHESAPEAKE ROYALTY, L.L.C. | ||
GOTHIC ENERGY, L.L.C. | ||
GOTHIC PRODUCTION, L.L.C. | ||
SAP ACQUISITION, L.L.C. | ||
THE AMES COMPANY, L.L.C. | ||
MC MINERAL COMPANY, L.L.C. | ||
JOHN C. OXLEY, L.L.C. | ||
OXLEY PETROLEUM CO. | ||
CHESAPEAKE PRH CORP. | ||
CHESAPEAKE PERMIAN ACQUISITION, L.L.C. | ||
By | /s/ AUBREY K. MCCLENDON | |
Name: |
Aubrey K. McClendon | |
Title: |
Chief Executive Officer |
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CHESAPEAKE EXPLORATION LIMITED PARTNERSHIP | ||
CHESAPEAKE LOUISIANA, L.P. | ||
CHESAPEAKE PANHANDLE LIMITED PARTNERSHIP | ||
CHESAPEAKE-STAGHORN ACQUISITION L.P. | ||
CHESAPEAKE SIGMA, L.P. | ||
CHESAPEAKE PERMIAN, L.P. | ||
CHESAPEAKE ZAPATA, L.P. | ||
By: Chesapeake Operating, Inc. as general partner of each representative entity | ||
By | /s/ AUBREY K. MCCLENDON | |
Name: |
Aubrey K. McClendon | |
Title: |
Chief Executive Officer |
TRUSTEE: | ||
THE BANK OF NEW YORK, as Trustee | ||
By | /s/ LOUIS P. YOUNG | |
Name: |
Louis P. Young | |
Title: |
Vice President |
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Ex. 4.5.1
CHESAPEAKE ENERGY CORPORATION
and
the Subsidiary Guarantors named herein
9% SENIOR NOTES DUE 2012
FOURTH SUPPLEMENTAL INDENTURE
DATED AS OF March 5, 2004
THE BANK OF NEW YORK
as Trustee
THIS FOURTH SUPPLEMENTAL INDENTURE, dated as of March 5, 2004, is among Chesapeake Energy Corporation, an Oklahoma corporation (the Company), each of the parties identified under the caption Subsidiary Guarantors on the signature page hereto (the Subsidiary Guarantors) and The Bank of New York, as Trustee.
RECITALS
WHEREAS, the Company, the Subsidiary Guarantors a party thereto and the Trustee entered into an Indenture, dated as of August 12, 2002, as supplemented prior to the date hereof (the Indenture), pursuant to which the Company has originally issued $250,000,000 in principal amount of 9% Senior Notes due 2012 (the Notes); and
WHEREAS, Section 9.01(3) of the Indenture provides that the Company, the Subsidiary Guarantors and the Trustee may amend or supplement the Indenture without notice to or consent of any Holder to reflect the addition of any Subsidiary Guarantor, as provided for in the Indenture; and
WHEREAS, the Board of Directors of the Company has designated Chesapeake PRH Corp., Chesapeake Permian Acquisition, L.L.C., Chesapeake Permian, L.P. and Chesapeake Zapata, L.P. as Restricted Subsidiaries of the Company and desires to add such entities as Subsidiary Guarantors under the Indenture; and
WHEREAS, all acts and things prescribed by the Indenture, by law and by the charter and the bylaws (or comparable constituent documents) of the Company, of the Subsidiary Guarantors and of the Trustee necessary to make this Fourth Supplemental Indenture a valid instrument legally binding on the Company, the Subsidiary Guarantors and the Trustee, in accordance with its terms, have been duly done and performed;
NOW, THEREFORE, to comply with the provisions of the Indenture and in consideration of the above premises, the Company, the Subsidiary Guarantors and the Trustee covenant and agree for the equal and proportionate benefit of the respective Holders of the Notes as follows:
ARTICLE 1
Section 1.01. This Fourth Supplemental Indenture is supplemental to the Indenture and does and shall be deemed to form a part of, and shall be construed in connection with and as part of, the Indenture for any and all purposes.
Section 1.02. This Fourth Supplemental Indenture shall become effective immediately upon its execution and delivery by each of the Company, the Subsidiary Guarantors and the Trustee.
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ARTICLE 2
Section 2.01. From this date, in accordance with Section 10.03 of the Indenture and by executing this Fourth Supplemental Indenture, Chesapeake PRH Corp., an Oklahoma corporation, Chesapeake Permian Acquisition, an Oklahoma limited liability company, Chesapeake Permian, L.P., an Oklahoma limited partnership, and Chesapeake Zapata, L.P., an Oklahoma limited partnership, are subject to the provisions of the Indenture as Subsidiary Guarantors to the extent provided for in Article Ten thereunder.
ARTICLE 3
Section 3.01. Except as specifically modified herein, the Indenture and the Notes are in all respects ratified and confirmed (mutatis mutandis) and shall remain in full force and effect in accordance with their terms with all capitalized terms used herein without definition having the same respective meanings ascribed to them as in the Indenture.
Section 3.02. Except as otherwise expressly provided herein, no duties, responsibilities or liabilities are assumed, or shall be construed to be assumed, by the Trustee by reason of this Fourth Supplemental Indenture. This Fourth Supplemental Indenture is executed and accepted by the Trustee subject to all the terms and conditions set forth in the Indenture with the same force and effect as if those terms and conditions were repeated at length herein and made applicable to the Trustee with respect hereto.
Section 3.03. The Company hereby notifies the Trustee that Chesapeake PRH Corp., Chesapeake Permian Acquisition, L.L.C., Chesapeake Permian, L.P. and Chesapeake Zapata, L.P. have each been designated by the Board of Directors of the Company as a Restricted Subsidiary (as that term is defined in the Indenture).
Section 3.04. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE AND ENFORCE THIS FOURTH SUPPLEMENTAL INDENTURE.
Section 3.05. The parties may sign any number of copies of this Fourth Supplemental Indenture. Each signed copy shall be an original, but all of such executed copies together shall represent the same agreement.
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IN WITNESS WHEREOF, the parties hereto have caused this Fourth Supplemental Indenture to be duly executed, all as of the date first written above.
COMPANY:
CHESAPEAKE ENERGY CORPORATION | ||
By | /s/ AUBREY K. MCCLENDON | |
Name: |
Aubrey K. McClendon | |
Title: |
Chief Executive Officer | |
SUBSIDIARY GUARANTORS:
CHESAPEAKE SOUTH TEXAS CORP. CHESAPEAKE ENERGY LOUISIANA CORPORATION CHESAPEAKE EP CORPORATION CHESAPEAKE OPERATING, INC. NOMAC DRILLING CORPORATION CARMEN ACQUISITION, L.L.C. CHESAPEAKE ACQUISITION, L.L.C. CHESAPEAKE ENO ACQUISITION, L.L.C. CHESAPEAKE FOCUS, L.L.C. CHESAPEAKE KNAN ACQUISITION, L.L.C. CHESAPEAKE MOUNTAIN FRONT, L.L.C. CHESAPEAKE ORC, L.L.C. CHESAPEAKE ROYALTY, L.L.C. GOTHIC ENERGY, L.L.C. GOTHIC PRODUCTION, L.L.C. SAP ACQUISITION, L.L.C. THE AMES COMPANY, L.L.C. MC MINERAL COMPANY, L.L.C. JOHN C. OXLEY, L.L.C. OXLEY PETROLEUM CO. CHESAPEAKE PRH CORP. CHESAPEAKE PERMIAN ACQUISITION, L.L.C.
| ||
By | /s/ AUBREY K. MCCLENDON | |
Name: |
Aubrey K. McClendon | |
Title: |
Chief Executive Officer |
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CHESAPEAKE EXPLORATION LIMITED PARTNERSHIP CHESAPEAKE LOUISIANA, L.P. CHESAPEAKE PANHANDLE LIMITED PARTNERSHIP CHESAPEAKE-STAGHORN ACQUISITION L.P. CHESAPEAKE SIGMA, L.P. CHESAPEAKE PERMIAN, L.P. CHESAPEAKE ZAPATA, L.P. | ||
By: Chesapeake Operating, Inc. as general partner of each representative entity | ||
By | /s/ AUBREY K. MCCLENDON | |
Name: |
Aubrey K. McClendon | |
Title: |
Chief Executive Officer |
TRUSTEE:
THE BANK OF NEW YORK, as Trustee | ||
By | /s/ LOUIS P. YOUNG | |
Name: |
Louis P. Young | |
Title: |
Vice President |
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Ex. 4.6.1
CHESAPEAKE ENERGY CORPORATION
and
the Subsidiary Guarantors named herein
7.75% SENIOR NOTES DUE 2015
FOURTH SUPPLEMENTAL INDENTURE
DATED AS OF March 5, 2004
THE BANK OF NEW YORK
as Trustee
THIS FOURTH SUPPLEMENTAL INDENTURE, dated as of March 5, 2004, is among Chesapeake Energy Corporation, an Oklahoma corporation (the Company), each of the parties identified under the caption Subsidiary Guarantors on the signature page hereto (the Subsidiary Guarantors) and The Bank of New York, as Trustee.
RECITALS
WHEREAS, the Company, the Subsidiary Guarantors a party thereto and the Trustee entered into an Indenture, dated as of December 20, 2002, as supplemented prior to the date hereof (the Indenture), pursuant to which the Company has originally issued $150,000,000 in principal amount of 7.75% Senior Notes due 2015 (the Notes); and
WHEREAS, Section 9.01(3) of the Indenture provides that the Company, the Subsidiary Guarantors and the Trustee may amend or supplement the Indenture without notice to or consent of any Holder to reflect the addition of any Subsidiary Guarantor, as provided for in the Indenture; and
WHEREAS, the Board of Directors of the Company has designated Chesapeake PRH Corp., Chesapeake Permian Acquisition, L.L.C., Chesapeake Permian, L.P. and Chesapeake Zapata, L.P. as Restricted Subsidiaries of the Company and desires to add such entities as Subsidiary Guarantors under the Indenture; and
WHEREAS, all acts and things prescribed by the Indenture, by law and by the charter and the bylaws (or comparable constituent documents) of the Company, of the Subsidiary Guarantors and of the Trustee necessary to make this Fourth Supplemental Indenture a valid instrument legally binding on the Company, the Subsidiary Guarantors and the Trustee, in accordance with its terms, have been duly done and performed;
NOW, THEREFORE, to comply with the provisions of the Indenture and in consideration of the above premises, the Company, the Subsidiary Guarantors and the Trustee covenant and agree for the equal and proportionate benefit of the respective Holders of the Notes as follows:
ARTICLE 1
Section 1.01. This Fourth Supplemental Indenture is supplemental to the Indenture and does and shall be deemed to form a part of, and shall be construed in connection with and as part of, the Indenture for any and all purposes.
Section 1.02. This Fourth Supplemental Indenture shall become effective immediately upon its execution and delivery by each of the Company, the Subsidiary Guarantors and the Trustee.
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ARTICLE 2
Section 2.01. From this date, in accordance with Section 10.03 of the Indenture and by executing this Fourth Supplemental Indenture, Chesapeake PRH Corp., an Oklahoma corporation, Chesapeake Permian Acquisition, L.L.C., an Oklahoma limited liability company, Chesapeake Permian, L.P., an Oklahoma limited partnership, and Chesapeake Zapata, L.P., an Oklahoma limited partnership, are subject to the provisions of the Indenture as Subsidiary Guarantors to the extent provided for in Article Ten thereunder.
ARTICLE 3
Section 3.01. Except as specifically modified herein, the Indenture and the Notes are in all respects ratified and confirmed (mutatis mutandis) and shall remain in full force and effect in accordance with their terms with all capitalized terms used herein without definition having the same respective meanings ascribed to them as in the Indenture.
Section 3.02. Except as otherwise expressly provided herein, no duties, responsibilities or liabilities are assumed, or shall be construed to be assumed, by the Trustee by reason of this Fourth Supplemental Indenture. This Fourth Supplemental Indenture is executed and accepted by the Trustee subject to all the terms and conditions set forth in the Indenture with the same force and effect as if those terms and conditions were repeated at length herein and made applicable to the Trustee with respect hereto.
Section 3.03. The Company hereby notifies the Trustee that Chesapeake PRH Corp., Chesapeake Permian Acquisition, L.L.C., Chesapeake Permian, L.P. and Chesapeake Zapata, L.P. have each been designated by the Board of Directors of the Company as a Restricted Subsidiary (as that term is defined in the Indenture).
Section 3.04. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE AND ENFORCE THIS FOURTH SUPPLEMENTAL INDENTURE.
Section 3.05. The parties may sign any number of copies of this Fourth Supplemental Indenture. Each signed copy shall be an original, but all of such executed copies together shall represent the same agreement.
[NEXT PAGE IS SIGNATURE PAGE]
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IN WITNESS WHEREOF, the parties hereto have caused this Fourth Supplemental Indenture to be duly executed, all as of the date first written above.
COMPANY:
CHESAPEAKE ENERGY CORPORATION | ||
By | /s/ AUBREY K. MCCLENDON | |
Name: |
Aubrey K. McClendon | |
Title: |
Chief Executive Officer | |
SUBSIDIARY GUARANTORS:
CHESAPEAKE SOUTH TEXAS CORP. CHESAPEAKE ENERGY LOUISIANA CORPORATION CHESAPEAKE EP CORPORATION CHESAPEAKE OPERATING, INC. NOMAC DRILLING CORPORATION CARMEN ACQUISITION, L.L.C. CHESAPEAKE ACQUISITION, L.L.C. CHESAPEAKE ENO ACQUISITION, L.L.C. CHESAPEAKE FOCUS, L.L.C. CHESAPEAKE KNAN ACQUISITION, L.L.C. CHESAPEAKE MOUNTAIN FRONT, L.L.C. CHESAPEAKE ORC, L.L.C. CHESAPEAKE ROYALTY, L.L.C. GOTHIC ENERGY, L.L.C. GOTHIC PRODUCTION, L.L.C. SAP ACQUISITION, L.L.C. THE AMES COMPANY, L.L.C. MC MINERAL COMPANY, L.L.C. JOHN C. OXLEY, L.L.C. OXLEY PETROLEUM CO. CHESAPEAKE PRH CORP. CHESAPEAKE PERMIAN ACQUISITION, L.L.C.
| ||
By | /s/ AUBREY K. MCCLENDON | |
Name: |
Aubrey K. McClendon | |
Title: |
Chief Executive Officer |
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CHESAPEAKE EXPLORATION LIMITED PARTNERSHIP CHESAPEAKE LOUISIANA, L.P. CHESAPEAKE PANHANDLE LIMITED PARTNERSHIP CHESAPEAKE-STAGHORN ACQUISITION L.P. CHESAPEAKE SIGMA, L.P. CHESAPEAKE PERMIAN, L.P. CHESAPEAKE ZAPATA, L.P. |
By: Chesapeake Operating, Inc. as general partner of each representative entity | ||
By | /s/ AUBREY K. MCCLENDON | |
Name: |
Aubrey K. McClendon | |
Title: |
Chief Executive Officer |
TRUSTEE:
THE BANK OF NEW YORK, as Trustee | ||
By | /s/ LOUIS P. YOUNG | |
Name: |
Louis P. Young | |
Title: |
Vice President |
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Ex. 4.9.1
CHESAPEAKE ENERGY CORPORATION
and
the Subsidiary Guarantors named herein
7.5% SENIOR NOTES DUE 2013
THIRD SUPPLEMENTAL INDENTURE
DATED AS OF March 5, 2004
THE BANK OF NEW YORK
as Trustee
THIS THIRD SUPPLEMENTAL INDENTURE, dated as of March 5, 2004, is among Chesapeake Energy Corporation, an Oklahoma corporation (the Company), each of the parties identified under the caption Subsidiary Guarantors on the signature page hereto (the Subsidiary Guarantors) and The Bank of New York, as Trustee.
RECITALS
WHEREAS, the Company, the Subsidiary Guarantors a party thereto and the Trustee entered into an Indenture, dated as of March 5, 2003, as supplemented prior to the date hereof (the Indenture), pursuant to which the Company has originally issued $300,000,000 in principal amount of 7.5% Senior Notes due 2013 (the Notes); and
WHEREAS, Section 9.01(3) of the Indenture provides that the Company, the Subsidiary Guarantors and the Trustee may amend or supplement the Indenture without notice to or consent of any Holder to reflect the addition of any Subsidiary Guarantor, as provided for in the Indenture; and
WHEREAS, the Board of Directors of the Company has designated Chesapeake PRH Corp., Chesapeake Permian Acquisition, L.L.C., Chesapeake Permian, L.P. and Chesapeake Zapata, L.P. as Restricted Subsidiaries of the Company and desires to add such entities as Subsidiary Guarantors under the Indenture; and
WHEREAS, all acts and things prescribed by the Indenture, by law and by the charter and the bylaws (or comparable constituent documents) of the Company, of the Subsidiary Guarantors and of the Trustee necessary to make this Third Supplemental Indenture a valid instrument legally binding on the Company, the Subsidiary Guarantors and the Trustee, in accordance with its terms, have been duly done and performed;
NOW, THEREFORE, to comply with the provisions of the Indenture and in consideration of the above premises, the Company, the Subsidiary Guarantors and the Trustee covenant and agree for the equal and proportionate benefit of the respective Holders of the Notes as follows:
ARTICLE 1
Section 1.01. This Third Supplemental Indenture is supplemental to the Indenture and does and shall be deemed to form a part of, and shall be construed in connection with and as part of, the Indenture for any and all purposes.
Section 1.02. This Third Supplemental Indenture shall become effective immediately upon its execution and delivery by each of the Company, the Subsidiary Guarantors and the Trustee.
ARTICLE 2
Section 2.01. From this date, in accordance with Section 10.03 of the Indenture and by executing this Third Supplemental Indenture, Chesapeake PRH Corp., an Oklahoma corporation, Chesapeake Permian Acquisition, L.L.C., an Oklahoma limited liability company, Chesapeake Permian, L.P., an Oklahoma limited partnership, and Chesapeake Zapata, L.P., an Oklahoma limited partnership, are subject to the provisions of the Indenture as Subsidiary Guarantors to the extent provided for in Article Ten thereunder.
ARTICLE 3
Section 3.01. Except as specifically modified herein, the Indenture and the Notes are in all respects ratified and confirmed (mutatis mutandis) and shall remain in full force and effect in accordance with their terms with all capitalized terms used herein without definition having the same respective meanings ascribed to them as in the Indenture.
Section 3.02. Except as otherwise expressly provided herein, no duties, responsibilities or liabilities are assumed, or shall be construed to be assumed, by the Trustee by reason of this Third Supplemental Indenture. This Third Supplemental Indenture is executed and accepted by the Trustee subject to all the terms and conditions set forth in the Indenture with the same force and effect as if those terms and conditions were repeated at length herein and made applicable to the Trustee with respect hereto.
Section 3.03. The Company hereby notifies the Trustee that Chesapeake PRH Corp., Chesapeake Permian Acquisition, L.L.C., Chesapeake Permian, L.P. and Chesapeake Zapata, L.P. have each been designated by the Board of Directors of the Company as a Restricted Subsidiary (as that term is defined in the Indenture).
Section 3.04. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE AND ENFORCE THIS THIRD SUPPLEMENTAL INDENTURE.
Section 3.05. The parties may sign any number of copies of this Third Supplemental Indenture. Each signed copy shall be an original, but all of such executed copies together shall represent the same agreement.
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IN WITNESS WHEREOF, the parties hereto have caused this Third Supplemental Indenture to be duly executed, all as of the date first written above.
COMPANY: | ||
CHESAPEAKE ENERGY CORPORATION | ||
By |
/s/ AUBREY K. MCCLENDON | |
Name: |
Aubrey K. McClendon | |
Title: |
Chief Executive Officer |
SUBSIDIARY GUARANTORS: | ||
CHESAPEAKE SOUTH TEXAS CORP. | ||
CHESAPEAKE ENERGY LOUISIANA | ||
CORPORATION | ||
CHESAPEAKE EP CORPORATION | ||
CHESAPEAKE OPERATING, INC. | ||
NOMAC DRILLING CORPORATION | ||
CARMEN ACQUISITION, L.L.C. | ||
CHESAPEAKE ACQUISITION, L.L.C. | ||
CHESAPEAKE ENO ACQUISITION, L.L.C. | ||
CHESAPEAKE FOCUS, L.L.C. | ||
CHESAPEAKE KNAN ACQUISITION, L.L.C. | ||
CHESAPEAKE MOUNTAIN FRONT, L.L.C. | ||
CHESAPEAKE ORC, L.L.C. | ||
CHESAPEAKE ROYALTY, L.L.C. | ||
GOTHIC ENERGY, L.L.C. | ||
GOTHIC PRODUCTION, L.L.C. | ||
SAP ACQUISITION, L.L.C. | ||
THE AMES COMPANY, L.L.C. | ||
MC MINERAL COMPANY, L.L.C. | ||
JOHN C. OXLEY, L.L.C. | ||
OXLEY PETROLEUM CO. | ||
CHESAPEAKE PRH CORP. | ||
CHESAPEAKE PERMIAN ACQUISITION, L.L.C. | ||
By |
/s/ AUBREY K. MCCLENDON | |
Name: |
Aubrey K. McClendon | |
Title: |
Chief Executive Officer |
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CHESAPEAKE EXPLORATION LIMITED | ||
PARTNERSHIP | ||
CHESAPEAKE LOUISIANA, L.P. | ||
CHESAPEAKE PANHANDLE LIMITED | ||
PARTNERSHIP | ||
CHESAPEAKE-STAGHORN ACQUISITION L.P. | ||
CHESAPEAKE SIGMA, L.P. | ||
CHESAPEAKE PERMIAN, L.P. | ||
CHESAPEAKE ZAPATA, L.P. | ||
By: |
Chesapeake Operating, Inc. as general partner of each representative entity | |
By |
/s/ AUBREY K. MCCLENDON | |
Name: |
Aubrey K. McClendon | |
Title: |
Chief Executive Officer |
TRUSTEE: | ||
THE BANK OF NEW YORK, as Trustee | ||
By |
/s/ LOUIS P. YOUNG | |
Name: |
Louis P. Young | |
Title: |
Vice President |
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Ex. 4.10.1
CHESAPEAKE ENERGY CORPORATION
and
the Subsidiary Guarantors named herein
6.875% SENIOR NOTES DUE 2016
FIRST SUPPLEMENTAL INDENTURE
DATED AS OF March 5, 2004
THE BANK OF NEW YORK
as Trustee
THIS FIRST SUPPLEMENTAL INDENTURE, dated as of March 5, 2004, is among Chesapeake Energy Corporation, an Oklahoma corporation (the Company), each of the parties identified under the caption Subsidiary Guarantors on the signature page hereto (the Subsidiary Guarantors) and The Bank of New York, as Trustee.
RECITALS
WHEREAS, the Company, the Subsidiary Guarantors a party thereto and the Trustee entered into an Indenture, dated as of November 26, 2003 (the Indenture), pursuant to which the Company has originally issued $200,000,000 in principal amount of 6.875% Senior Notes due 2016 (the Notes); and
WHEREAS, Section 9.01(3) of the Indenture provides that the Company, the Subsidiary Guarantors and the Trustee may amend or supplement the Indenture without notice to or consent of any Holder to reflect the addition of any Subsidiary Guarantor, as provided for in the Indenture; and
WHEREAS, the Board of Directors of the Company has designated Chesapeake PRH Corp., Chesapeake Permian Acquisition, L.L.C., Chesapeake Permian, L.P. and Chesapeake Zapata, L.P. as Restricted Subsidiaries of the Company and desires to add such entities as Subsidiary Guarantors under the Indenture; and
WHEREAS, all acts and things prescribed by the Indenture, by law and by the charter and the bylaws (or comparable constituent documents) of the Company, of the Subsidiary Guarantors and of the Trustee necessary to make this First Supplemental Indenture a valid instrument legally binding on the Company, the Subsidiary Guarantors and the Trustee, in accordance with its terms, have been duly done and performed;
NOW, THEREFORE, to comply with the provisions of the Indenture and in consideration of the above premises, the Company, the Subsidiary Guarantors and the Trustee covenant and agree for the equal and proportionate benefit of the respective Holders of the Notes as follows:
ARTICLE 1
Section 1.01. This First Supplemental Indenture is supplemental to the Indenture and does and shall be deemed to form a part of, and shall be construed in connection with and as part of, the Indenture for any and all purposes.
Section 1.02. This First Supplemental Indenture shall become effective immediately upon its execution and delivery by each of the Company, the Subsidiary Guarantors and the Trustee.
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ARTICLE 2
Section 2.01. From this date, in accordance with Section 10.03 of the Indenture and by executing this First Supplemental Indenture, Chesapeake PRH Corp., an Oklahoma corporation, Chesapeake Permian Acquisition, L.L.C., an Oklahoma limited liability company, Chesapeake Permian, L.P., an Oklahoma limited partnership, and Chesapeake Zapata, L.P., an Oklahoma limited partnership, are subject to the provisions of the Indenture as Subsidiary Guarantors to the extent provided for in Article Ten thereunder.
ARTICLE 3
Section 3.01. Except as specifically modified herein, the Indenture and the Notes are in all respects ratified and confirmed (mutatis mutandis) and shall remain in full force and effect in accordance with their terms with all capitalized terms used herein without definition having the same respective meanings ascribed to them as in the Indenture.
Section 3.02. Except as otherwise expressly provided herein, no duties, responsibilities or liabilities are assumed, or shall be construed to be assumed, by the Trustee by reason of this First Supplemental Indenture. This First Supplemental Indenture is executed and accepted by the Trustee subject to all the terms and conditions set forth in the Indenture with the same force and effect as if those terms and conditions were repeated at length herein and made applicable to the Trustee with respect hereto.
Section 3.03. The Company hereby notifies the Trustee that Chesapeake PRH Corp., Chesapeake Permian Acquisition, L.L.C., Chesapeake Permian, L.P. and Chesapeake Zapata, L.P. have each been designated by the Board of Directors of the Company as a Restricted Subsidiary (as that term is defined in the Indenture).
Section 3.04. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE AND ENFORCE THIS FIRST SUPPLEMENTAL INDENTURE.
Section 3.05. The parties may sign any number of copies of this First Supplemental Indenture. Each signed copy shall be an original, but all of such executed copies together shall represent the same agreement.
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IN WITNESS WHEREOF, the parties hereto have caused this First Supplemental Indenture to be duly executed, all as of the date first written above.
COMPANY: | ||
CHESAPEAKE ENERGY CORPORATION | ||
By |
/s/ AUBREY K. MCCLENDON | |
Name: |
Aubrey K. McClendon | |
Title: |
Chief Executive Officer |
SUBSIDIARY GUARANTORS: | ||
CHESAPEAKE SOUTH TEXAS CORP. | ||
CHESAPEAKE ENERGY LOUISIANA | ||
CORPORATION | ||
CHESAPEAKE EP CORPORATION | ||
CHESAPEAKE OPERATING, INC. | ||
NOMAC DRILLING CORPORATION | ||
CARMEN ACQUISITION, L.L.C. | ||
CHESAPEAKE ACQUISITION, L.L.C. | ||
CHESAPEAKE ENO ACQUISITION, L.L.C. | ||
CHESAPEAKE FOCUS, L.L.C. | ||
CHESAPEAKE KNAN ACQUISITION, L.L.C. | ||
CHESAPEAKE MOUNTAIN FRONT, L.L.C. | ||
CHESAPEAKE ORC, L.L.C. | ||
CHESAPEAKE ROYALTY, L.L.C. | ||
GOTHIC ENERGY, L.L.C. | ||
GOTHIC PRODUCTION, L.L.C. | ||
SAP ACQUISITION, L.L.C. | ||
THE AMES COMPANY, L.L.C. | ||
MC MINERAL COMPANY, L.L.C. | ||
JOHN C. OXLEY, L.L.C. | ||
OXLEY PETROLEUM CO. | ||
CHESAPEAKE PRH CORP. | ||
CHESAPEAKE PERMIAN ACQUISITION, L.L.C. | ||
By |
/s/ AUBREY K. MCCLENDON | |
Name: |
Aubrey K. McClendon | |
Title: |
Chief Executive Officer |
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CHESAPEAKE EXPLORATION LIMITED | ||
PARTNERSHIP | ||
CHESAPEAKE LOUISIANA, L.P. | ||
CHESAPEAKE PANHANDLE LIMITED | ||
PARTNERSHIP | ||
CHESAPEAKE-STAGHORN ACQUISITION L.P. | ||
CHESAPEAKE SIGMA, L.P. | ||
CHESAPEAKE PERMIAN, L.P. | ||
CHESAPEAKE ZAPATA, L.P. | ||
By: |
Chesapeake Operating, Inc. as general partner of each representative entity | |
By |
/s/ AUBREY K. MCCLENDON | |
Name: |
Aubrey K. McClendon | |
Title: |
Chief Executive Officer |
TRUSTEE: | ||
THE BANK OF NEW YORK, as Trustee | ||
By |
/s/ LOUIS P. YOUNG | |
Name: |
Louis P. Young | |
Title: |
Vice President |
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EXHIBIT 10.1.17
FIRST AMENDMENT TO THE
CHESAPEAKE ENERGY CORPORATION 401(k) MAKE-UP PLAN
This First Amendment to the Chesapeake Energy Corporation 401(k) Make-Up Plan (the Plan), is made this 24th day of October, 2003 by the Compensation Committee (Committee) on behalf of Chesapeake Energy Corporation (Company).
1. Effective January 1, 2004, Article II, Section 2.1(o)(i)(B) of the Plan document shall be deleted and replaced with the following:
(B) receives combined Base Salary and Bonus Compensation of $90,000 or more during the twelve months immediately preceding the applicable Plan Year;
2. Effective January 1, 2004, Article VII, Section 7.5(b) of the Plan shall be deleted and replaced with the following:
(b) Company Contributions. Supplemental Matching Contributions and any income, earnings or losses thereon shall vest at the rate of 25% per year for each Year of Service with the Company from the date of the contribution. A Participant shall fully vest in all existing and future Company contributions made on their behalf upon attainment of 60 years of age. Discretionary Contributions shall vest as determined by the Committee upon the grant of a Discretionary Contribution. If a Participant terminates employment prior to vesting, the unvested Company Contributions and any income, earnings or losses thereon shall be forfeited. Forfeited amounts shall be used to offset future contributions by the Company. In the event termination is due to death, Disability or retirement, the Committee may, in its sole and absolute discretion, accelerate vesting. Upon the occurrence of a Change of Control, all Participants shall be deemed to be 100% vested in all Company Contributions credited to their Account.
IN WITNESS WHEREOF, the Company has caused this Amendment to be executed this 24th day of October, 2003.
CHESAPEAKE ENERGY CORPORATION, an Oklahoma corporation
| ||
By: | /s/ MARTHA A. BURGER | |
Martha A. Burger Treasurer and Senior Vice President Human Resources |
Exhibit 10.2.1
THIRD AMENDED AND RESTATED
EMPLOYMENT AGREEMENT
THIS AGREEMENT is made effective January 1, 2004, between CHESAPEAKE ENERGY CORPORATION, an Oklahoma corporation (the Company), and AUBREY K. McCLENDON, an individual (the Executive).
W I T N E S S E T H:
WHEREAS, the Company and the Executive entered into that certain Amended and Restated Employment Agreement dated effective July 1, 1998 as amended by the First Amendment to Amended and Restated Employment Agreement dated December 31, 1998 and as further amended by the Second Amended and Restated Employment Agreement dated January 1, 2001 (together the Prior Agreements);
WHEREAS, the Company and the Executive desire to amend and restate the Prior Agreements in their entirety.
NOW, THEREFORE, in consideration of the mutual promises herein contained, the Company and the Executive agree as follows:
1. Employment. The Company hereby employs the Executive and the Executive hereby accepts such employment subject to the terms and conditions contained in this Agreement. The Executive is engaged as an employee of the Company and the Executive and the Company do not intend to create a joint venture, partnership or other relationship that might impose a fiduciary obligation on the Executive or the Company in the performance of this Agreement.
2. Executives Duties. The Executive is employed on a full-time basis. Throughout the term of this Agreement, the Executive will use the Executives best efforts and due diligence to assist the Company in achieving the most profitable operation of the Company and the Companys affiliated entities consistent with developing and maintaining a quality business operation.
2.1 | Specific Duties. The Executive will serve as Chairman of the Board and Chief Executive Officer for the Company. From time to time, the Executive may be appointed as an officer of one (1) or more of the Companys subsidiaries. During the term of this Agreement, the Executive will be nominated for election or appointed to serve as a director of the Company and one (1) or more of the Companys subsidiaries. The Executive will use the Executives best efforts to perform all of the services required to fully and faithfully execute the offices and positions to which the Executive is appointed and such other services as may be reasonably directed by the Board of Directors of the Company in accordance with this Agreement. |
2.2 | Modifications. The precise duties to be performed by the Executive may be extended or curtailed in the discretion of the Board of Directors of the Company. However, except for termination for Cause (as hereinafter defined) under paragraph 6.1.2 of this Agreement, the failure of the Executive to be elected, be reelected or serve as a director of the Company during the term of this Agreement, the removal of the Executive as a member of the board of directors of the Company, the withdrawal of the designation of the Executive as Chairman of the Board and Chief Executive Officer of the Company, or the assignment of the performance of duties incumbent on the foregoing offices to other persons without the prior written consent of the Executive will constitute termination without Cause by the Company. |
2.3 | Rules and Regulations. From time to time, the Company may issue policies applicable to employees and the Executive including an Employment Policies Manual that addresses frequently asked questions regarding the Company. The Executive agrees to comply with such policies, except to the extent such policies are inconsistent with this Agreement. The policies and the Employment Policies Manual are subject to change without notice in the sole discretion of the Company at any time. In the event of a conflict between such policies and this Agreement, this Agreement will control over the terms of the Employment Policies Manual. |
2.4 | Stock Investment. During the term of this Agreement, the Executive agrees to hold shares of the Companys common stock having an aggregate Investment Value (as hereafter defined) greater than five hundred percent (500%) of the compensation paid to the Executive under paragraphs 4.1 and 4.2 of this Agreement during such calendar year. Any shares of common stock acquired by the Executive prior to the date of this Agreement and still owned by the Executive during the term of this Agreement may be used to satisfy the requirement to own common stock. For purposes of this paragraph, the Investment Value of each share of stock will be as follows: (a) for shares purchased in the open market the price paid by the Executive for such shares; (b) for shares acquired after the Companys initial public offering (IPO) in February 1993 through the exercise of stock options or other than through open market purchases, the fair market value of the common stock on the date the option was exercised or the stock was acquired; and (c) for shares acquired prior to the Companys IPO, the price obtained for stock in the IPO adjusted for subsequent stock splits. This paragraph will become null and void if the Companys common stock ceases to be listed on the New York Stock Exchange, the National Association of Securities Dealers Automated Quotation System or other national exchange. The Company has no obligation to sell or to purchase from the Executive any of the Companys stock in connection with this paragraph 2.4 and has made no representations or warranties regarding the Companys stock, operations or financial condition. |
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3. Other Activities. Except for the activities (the Permitted Activities) expressly permitted by paragraphs 3.1 and 3.2 of this Agreement or approved by the board of directors of the Company, the Executive will not: (a) engage in business independent of the Executives employment by the Company which requires any substantial portion of the Executives time; (b) serve as an officer or director of any public corporation, partnership, company, or firm; (c) except for passive investments that do not violate this Agreement and require only a minimal portion of the Executives time, serve as a general partner or member of any corporation, partnership, company or firm; or (d) directly or indirectly invest in, participate in or acquire an interest in any oil and gas business, including, without limitation, (i) producing oil and gas, (ii) drilling, owning or operating oil and gas leases or wells, (iii) providing services or materials to the oil and gas industry, (iv) marketing or refining oil or gas, or (v) owning any interest in any corporation, partnership, company or entity which conducts any of the foregoing activities. The limitations in this paragraph 3 will not prohibit an investment by the Executive in publicly traded securities. Notwithstanding the foregoing, the Executive will be permitted to participate in the following activities that will be deemed to be approved by the Company, if such activities are undertaken in strict compliance with this Agreement. The foregoing will not prohibit the ownership of royalty interests where the Executive owns or previously owned the surface of the land covered by the royalty interest and the ownership of the royalty interest is incidental to the ownership of the surface estate or the ownership of royalty, overriding royalty or working interests that are received by gift, inheritance or were acquired prior to the Executives date of first employment with the Company.
3.1 | Existing Interests. The Executive has in the past conducted oil and gas activities individually and through Chesapeake Investments, an Oklahoma Limited Partnership, and other entities owned or controlled by the Executive (collectively, the Executive Affiliates). The Executive will be permitted to continue to conduct oil and gas activities (including participation in new wells) directly or through the Executive Affiliates, but only to the extent such activities are conducted on oil and gas leases or interests which the Executive or Executive Affiliates owned or had the right to acquire as of July 1, 2001, or which the Executive or the Executive Affiliates acquired from the Company under this Agreement or prior agreements with the Company (collectively, the Prior Interests). To the extent that the oil and gas interests or activities covered by this paragraph 3.1 are operated by the Company, the ownership and participation will be subject to the payment provisions set forth in this paragraph 3. |
3.2 | Companys Activities. The Executive or the designated Executive Affiliate will be permitted to acquire on the terms and conditions set forth herein an interest in the governmental, spacing or production unit for each of the wells (the Program Wells) spudded by any of the Company Entities (as hereafter defined) in any Calendar Quarter (as hereafter defined) during the Participation Term (as hereafter defined). The Program Wells include any well spudded during such Calendar Quarter in which the Company Entities |
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participate as a non-operator. Program Wells will include grass-roots wells only and will exclude re-entries of existing wells. |
3.2.1 | Election. On or before the date which is thirty (30) days before the first (1st) day of each Calendar Quarter, the Executive will provide notice to the Compensation Committee of the Companys Board of Directors of the Executives intent to participate in Program Wells during the succeeding Calendar Quarter and the minimum percentage working interest which the Executive proposes to participate with during such Calendar Quarter (the Acquisition Percentage). The Executives elected Acquisition Percentage for any Calendar Quarter will not exceed two and one-half percent (2.5%) on an eight-eighths (8/8ths) basis. If prior to the date specified herein, the Executive fails to provide notice of the Executives intent to participate or of the Acquisition Percentage for a Calendar Quarter, the amount of the Acquisition Percentage for the Calendar Quarter will be deemed to be equal to the Acquisition Percentage for the immediately preceding Calendar Quarter. |
3.2.2 | Amount of Participation. On election to participate and the designation of the Acquisition Percentage for a Calendar Quarter, the Executive will be deemed to have elected to participate in each Program Well spudded during such Calendar Quarter with a working interest equal to the greater of the following determined on a well-by-well basis (the Minimum Participation): (a) the Acquisition Percentage for such Program Well (as adjusted for any well under paragraph 3.2.3); or (b) the Prior Interest of the Executive or the Executive Affiliates in the drilling unit for such Program Well. If the foregoing clause (a) is applicable to a Program Well, then the Company will assign or allocate to the Executive or the designated Executive Affiliate a unit working interest in the Program Well sufficient to cause the Executive and the Executive Affiliates combined interest in such Program Well to equal the Acquisition Percentage (including in such computation any Prior Interests). The interest to be assigned or allocated under this paragraph to cause the Executives participation to be equal to the Acquisition Percentage will be derived proportionately from all the interests owned by the Company in the Program Wells (including non-consenting interests, back-in interests, leased royalty interests, overriding royalty interests or other similar interests) so that the interests assigned or allocated to the Executive are substantially similar to the interests retained by the Company. If the Executive elects not to participate in Program Wells during a Calendar Quarter, then the Executive can elect to participate or not participate with any Prior Interests under the existing agreements related to such Prior Interests. |
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3.2.3 | Minimum Company Working Interest Ownership Level. If the combined interests in a specific Program Well to be assigned or allocated by the Company to the Executive and Mr. Tom L. Ward under their respective employment agreements causes the Companys working interest (determined after consideration of any carried or reversionary interests) on the spud date for such Program Well to be less than twelve and one-half percent (12.5%) on an eight-eighths (8/8ths) basis, then the Acquisition Percentage for that Program Well will be equal to zero for purposes of paragraph 3.2.2 of this Agreement. If this paragraph 3.2.3 prohibits the Executives participation in a Program Well, then Mr. Ward will also not be entitled to participate in such Program Well under his employment agreement. |
3.3 | Conditions of Participation. The Participation by the Executive in each Program Well will be on no better terms than the terms agreed to by unaffiliated third party participants in connection with the participation in such Program Well or similar wells operated by the Company Entities. The Acquisition Percentage cannot be changed during any Calendar Quarter without the prior approval of the members of the Compensation Committee of the Companys board of directors. Any participation by the Executive under paragraph 3.2 is also conditioned on the Executives participation in each Program Well spudded during such Calendar Quarter in an amount equal to the Minimum Participation. The Executive hereby agrees to execute and deliver any documents reasonably requested by the Company and hereby appoints the Company as the Executives agent and attorney-in-fact to execute and deliver such documents if the Executive fails or refuses to execute such documents. The Executive further agrees to pay all joint interest billings promptly after receipt of the Companys invoice in accordance with the applicable joint operating agreement or, in the absence of an applicable joint operating agreement, the standard joint operating agreement used by the Company in the ordinary conduct of its business. |
3.4 | Definitions. For purposes of this Agreement, the term: (a) Calendar Quarter means the three (3) month periods commencing on the first (1st) day of January, April, July and October; (b) the term Company Entities means the Company, any affiliate or successor to the Company, any entity which controls, subsequently owns or is under common control with the Company and any subsidiary corporation, partnership, limited liability company or other entity owned by, controlled by or under common control with any of the foregoing (whether direct or indirect); and (c) Participation Term means the term of this Agreement plus five (5) years after a termination under paragraphs 6.1.1 or 6.3 of this Agreement. |
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4. Executives Compensation. The Company agrees to compensate the Executive as follows:
4.1 | Base Salary. A base salary (the Base Salary), in an annual rate of not less than Eight Hundred Thousand Dollars ($800,000.00), will be paid to the Executive in equal semi-monthly installments, beginning January 15, 2004, during the term of this Agreement. |
4.2 | Bonus. In addition to the Base Salary described at paragraph 4.1 of this Agreement, the Company may periodically pay bonus compensation to the Executive. Any bonus compensation will be at the absolute discretion of the Company in such amounts and at such times as the Compensation Committee of the Board of Directors of the Company may determine. |
4.3 | Equity Compensation. In addition to the compensation set forth in paragraphs 4.1 and 4.2 of this Agreement, the Executive may periodically receive grants of stock options, restricted stock or other equity related awards from the Companys various stock compensation plans, subject to the terms and conditions thereof. |
4.4 | Benefits. The Company will provide the Executive such retirement benefits, reimbursement of reasonable expenditures for dues, travel and entertainment and other benefits on terms customarily provided by the Company from time to time. The Company will also provide the Executive the opportunity to apply for coverage under the Companys medical, life and disability plans, if any. If the Executive is accepted for coverage under such plans, the Company will provide such coverage on the same terms as is customarily provided by the Company to the plan participants as modified from time to time. The following specific benefits will also be provided to the Executive at the expense of the Company: |
4.4.1 | Vacation. The Executive will be entitled to take up to five (5) weeks of paid vacation each calendar year during the term of this Agreement. No additional compensation will be paid for failure to take vacation and no vacation may be carried forward from one calendar year to another. |
4.4.2 | Membership Dues. The Company will reimburse the Executive for: (a) the monthly dues necessary to maintain a full membership in (1) golf and/or country club in the Oklahoma City area selected by the Executive; and (b) the reasonable cost of any qualified business entertainment at such country club. All other costs, including, without implied limitation, any initiation costs, initial membership costs, personal use and business entertainment unrelated to the Company |
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will be the sole obligation of the Executive and the Company will have no liability with respect to such amounts. |
4.4.3 | Travel. The Executive will receive a monthly cash allowance in the amount of Two Thousand Dollars ($2,000.00) to defer a portion of the Executives cost of acquiring, operating and maintaining an automobile for use in the Executives employment. Additionally, for safety and security reasons, the Executive will be required to utilize aircraft owned or leased by the Company for business and personal use in the Western Hemisphere (including North America, South America and the surrounding oceans) and will not be required to reimburse the Company for any cost related to such use. In addition, the Executives immediate family members may use such company aircraft for their personal use to the same extent. When a family member travels without the Executive, then the Executive agrees to reimburse the company for the variable costs of such use. For purposes of this Agreement, the variable cost of using the Companys aircraft means the variable costs directly identifiable with each use (including fuel, pilot charges, landing fees, hourly charges under co-ownership arrangements and other such costs), but specifically excluding any fixed costs of the aircraft (including acquisition costs and depreciation). The Executive will pay all personal income taxes accruing as a result of the personal use of the Companys aircraft by the Executive under this paragraph. |
4.4.4 | Accounting Support. The Executive will be permitted to utilize the Companys office space, computer facilities and personnel to provide accounting services, records maintenance and tax advice and tax return preparation for the Executives (and his familys) personal business investments and activities. The Executive will not be required to pay any amount to the Company in connection with such accounting support. |
4.5 | Gross-Up Payment. In the event it is determined that any payment or distribution by the Company or the Company Entities to or for the benefit of the Executive (whether paid or payable or distributed or distributable pursuant to the terms of this Agreement or otherwise, but determined without regard to any additional payments required under this paragraph 4.5) (a Payment) is subject to the excise tax imposed by Section 4999 of the Internal Revenue Code (the Code) or any interest or penalties related to such excise tax (collectively, the Excise Tax), the Executive will be entitled to receive an additional payment (a Gross-Up Payment) from the Company. The Gross-Up Payment will be equal to the amount such that after payment by the Executive of all taxes (including the Excise Tax, income taxes, interest and penalties imposed with respect to such taxes) on the Gross-Up |
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Payment, the Executive will retain an amount of the Gross-Up Payment equal to the Excise Tax imposed on the Payment. |
4.5.1 | Determination. Subject to the provisions of paragraph 4.5.2 all determinations required to be made under this paragraph 4.5 (including whether and when a Gross-Up Payment is required, the amount of such Gross-Up Payment and the assumptions to be utilized) will be made by a nationally recognized certified public accounting firm designated by the Executive (the Accounting Firm). The Accounting Firm will provide detailed supporting calculations both to the Company and the Executive within fifteen (15) business days of the receipt of notice from the Executive that there has been a Payment, or such earlier time as is reasonably requested by the Company. In the event that the Accounting Firm is serving as accountant or auditor for the individual, entity or group effecting a Change of Control (as hereinafter defined), the Executive will be entitled to appoint another nationally recognized accounting firm to make the determinations required under this paragraph (which accounting firm will then be referred to as the Accounting Firm hereunder). All fees and expenses of the Accounting Firm will be paid by the Company. Any Gross-Up Payment required to be paid under this paragraph 4.5 will be paid by the Company to the Executive within five (5) days of the receipt of the Accounting Firms determination. Any determination by the Accounting Firm will be binding on the Company and the Executive. As a result of the uncertainty in the application of Section 4999 of the Code at the time of the initial determination by the Accounting Firm, the Gross-Up Payment made by the Company may be less than actually required (an Underpayment) consistent with the calculations required to be made hereunder. In the event that the Company exhausts its remedies pursuant to paragraph 4.5.2 below and the Executive thereafter is required to make a payment of any Excise Tax, the Accounting Firm will determine the amount of the Underpayment that has occurred and any such Underpayment will be promptly paid by the Company to or for the benefit of the Executive. |
4.5.2 | Contest of Claims. The Executive will notify the Company in writing of any claim by the Internal Revenue Service that, if successful, would require the payment by the Company of a Gross-Up Payment. Such notification will be given as soon as practicable but no later than ten (10) business days after the Executive is informed in writing of such claim and will apprise the Company of the nature of such claim and the date on which such claim is requested to be paid. The Executive will not pay such claim prior to the expiration of the thirty (30) day period following the date on which the Executive notifies the Company |
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(or such shorter period ending on the date that any payment of taxes with respect to such claim is due). If the Company notifies the Executive in writing prior to the expiration of such thirty (30) day period that the Company desires to contest such claim, the Executive will: (a) provide to the Company any information reasonably requested by the Company relating to such claim; (b) take such action in connection with contesting such claim as the Company reasonably requests in writing including, without limitation, accepting legal representation with respect to such claim by an attorney reasonably selected by the Company; (c) cooperate with the Company in good faith as necessary to effectively contest such claim; and (d) permit the Company to participate in any proceedings relating to such claim. The Company will bear and pay directly all costs and expenses (including additional interest and penalties) incurred in connection with the contest of the claim and agrees to indemnify and hold the Executive harmless, on an after-tax basis, for any Excise Tax or income tax (including interest and penalties with respect thereto) imposed as a result of such protest (including payment of costs and expenses as provided hereunder). Without limitation on the foregoing provisions, the Company will control all proceedings related to such contested claim, may at its sole option pursue or forgo any and all administrative appeals, proceedings, hearings and conferences with the taxing authority in respect of such claim and may at its sole option either direct the Executive to pay the tax claimed and sue for a refund or contest the claim in any permissible manner. The Executive agrees to prosecute such contest to a determination before any administrative tribunal, in a court of initial jurisdiction and in one or more appellate courts, as the Company reasonably determines. If the Company directs the Executive to pay a claim and sue for a refund, the Company will be required to advance the amount of such payment to the Executive on an interest-free basis and agrees to indemnify and hold the Executive harmless, on an after-tax basis, from any Excise Tax or income tax (including interest or penalties with respect thereto) imposed with respect to such advance or with respect to any imputed income with respect to such advance, provided that any extension of the statute of limitations relating to payment of taxes for the taxable year of the Executive with respect to which such contested amount is claimed to be due is limited solely to such contested amount. Furthermore, the Companys control of the contested claim will be limited to issues with respect to which a Gross-Up Payment would be payable hereunder and the Executive will be entitled to settle or contest, as the case may be, any other issue raised by the Internal Revenue Service or any other taxing authority. |
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4.5.3 | Refunds. If, after the receipt by the Executive of an amount advanced by the Company pursuant to paragraph 4.5.2, the Executive becomes entitled to receive any refund with respect to such claim the Executive will (subject to the Companys complying with the requirements of paragraph 4.5.2) promptly pay to the Company the amount of such refund (together with any interest paid or credited thereon after taxes applicable thereto). If, after the receipt by the Executive of an amount advanced by the Company pursuant to paragraph 4.5.2, a determination is made that the Executive will not be entitled to any refund with respect to such claim and the Company does not notify the Executive in writing of its intent to contest such denial of refund prior to the expiration of (30) days after such determination, then the advance will be forgiven and will not be required to be repaid and the amount of such advance will offset, to the extent thereof, the amount of Gross-Up Payment required to be paid. |
4.6 | Compensation Review. The compensation of the Executive will be reviewed not less frequently than semi-annually by the Compensation Committee of the Board of Directors of the Company. The compensation of the Executive prescribed in paragraph 4 of this Agreement (including benefits) may be increased at the discretion of the Compensation Committee of the Board of Directors of the Company, but may not be reduced without the prior written consent of the Executive. |
5. Term. In the absence of termination as set forth in paragraph 6 below, this Agreement will extend for a term of five (5) years commencing on January 1, 2004, and ending on December 31, 2008 (the Expiration Date) as extended from time to time. Unless the Company provides thirty (30) days prior written notice of non-extension to the Executive, on each January 31 during the term of this Agreement, the term and the Expiration Date will be automatically extended for one (1) additional year so that the remaining term on this Agreement will be not less than four (4) and not more than five (5) years.
6. Termination. This Agreement will continue in effect until the expiration of the term set forth in paragraph 5 of this Agreement unless earlier terminated pursuant to this paragraph 6.
6.1 | Termination by Company. The Company will have the following rights to terminate this Agreement: |
6.1.1 | Termination without Cause. The Company may terminate this Agreement without Cause at any time by the service of written notice of termination to the Executive specifying an effective date of such termination not sooner than ninety (90) business days after the date of such notice (the Termination Date). In the event the Executive is terminated without Cause (other than a CC Termination under |
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paragraph 6.3 of this Agreement), the Executive will receive as termination compensation: (a) Base Compensation (as hereafter defined) during the remaining term of this Agreement, but in any event through the Expiration Date; (b) any benefits provided by operation of paragraph 4.4 of this Agreement during the remaining term of this Agreement, but in any event through the Expiration Date (including, without implied limitation, suitable office space, secretarial and accounting support at the levels presently provided by the Company to the Executive); and (c) any vacation pay accrued through the Termination Date. For purposes of this Agreement the term Base Compensation means the Executives current Base Salary under paragraph 4.1 on the Termination Date plus the bonus compensation received by the Executive during the twelve (12) month period preceding the Termination Date. |
6.1.2 | Termination for Cause. The Company may terminate this Agreement for Cause. For purposes of this Agreement, Cause means: (a) the willful and continued failure of the Executive to perform substantially the Executives duties with the Company or one of the Company Entities (other than a failure resulting from incapacity due to physical or mental illness), after a written demand for substantial performance is delivered to the Executive by the Board of Directors which specifically identifies the manner in which the Board of Directors believes that the Executive has not substantially performed the Executives duties; or (b) the willful engaging by the Executive in illegal conduct, gross misconduct or a clearly established violation of the Companys code of conduct, in each case which is materially and demonstrably injurious to the Company. For purposes of this provision, an act or failure to act, on the part of the Executive, will not be considered willful unless it is done, or omitted to be done, by the Executive in bad faith or without reasonable belief that the Executives action or omission was in the best interests of the Company. Any act, or failure to act, based on authority given pursuant to a resolution duly adopted by the Board of Directors or based on the advice of counsel for the Company will be conclusively presumed to be done, or omitted to be done, by the Executive in good faith and in the best interests of the Company. In the event this Agreement is terminated for Cause, the Company will not have any obligation to provide any further payments or benefits to the Executive after the effective date of such termination. This Agreement will not be deemed to have terminated for Cause unless a written determination specifying the reasons for such termination is made, approved by a majority of the independent and disinterested members of the Board of Directors of the Company and delivered to the Executive. Thereafter, the Executive will have the right for a period of thirty (30) days to request a Board of Directors |
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meeting to be held at a mutually agreeable time and location within the following thirty (30) days, at which meeting the Executive will have an opportunity to be heard. Failing such determination and opportunity for hearing, any termination of this Agreement will be deemed to have occurred without Cause. |
6.2 | Termination by Executive. The Executive may voluntarily terminate this Agreement with or without Cause by the service of written notice of such termination to the Company specifying an effective date of such termination ninety (90) days after the date of such notice, during which time the Executive may use remaining accrued vacation days, or at the Companys option, be paid for such days. In the event this Agreement is terminated by the Executive, neither the Company nor the Executive will have any further obligations hereunder including, without limitation, any obligation of the Company to provide any further payments or benefits to the Executive after the effective date of such termination. |
6.3 | Termination After Change in Control. If during the term of this Agreement there is a Change of Control and within three (3) years thereafter there is a CC Termination (as hereafter defined), then the Executive will be entitled to a severance payment (in addition to any other rights and other amounts payable to the Executive under this Agreement or otherwise) in an amount equal to the sum of the following: (a) five (5) times the Executives Base Compensation; plus (b) five (5) times the value of any benefits provided by operation of paragraph 4.4 of this Agreement during the preceding twelve (12) months; plus (c) any applicable Gross-Up Payment. If the foregoing amount is not paid within ten (10) days after the CC Termination, the unpaid amount will bear interest at the per annum rate of 12%. In addition, for a period of twelve (12) months after a CC Termination, the Company will provide at no cost to the Executive suitable office space and secretarial and accounting support at the levels presently provided by the Company. |
6.3.1 | Change of Control. For the purpose of this Agreement, a Change of Control means the occurrence of any of the following: |
(a) The acquisition by any individual, entity or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Securities Exchange Act of 1934, as amended (the Exchange Act)) (a Person) of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of 20% or more of either (i) the then outstanding shares of common stock of the Company (the Outstanding Company Common Stock) or (ii) the combined voting power of the then outstanding voting securities of the Company entitled to vote generally in the election of directors (the Outstanding Company Voting Securities). For purposes of this paragraph (a) the following acquisitions by a Person will not constitute a Change of
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Control: (i) any acquisition directly from the Company; (ii) any acquisition by the Company; (iii) any acquisition by any employee benefit plan (or related trust) sponsored or maintained by the Company or any corporation controlled by the Company; or (iv) any acquisition by any corporation pursuant to a transaction which complies with clauses (i), (ii) and (iii) of paragraph (c) of this paragraph 6.3.1.
(b) The individuals who, as of the date hereof, constitute the Board of Directors (the Incumbent Board) cease for any reason to constitute at least a majority of the Board of Directors. Any individual becoming a director subsequent to the date hereof whose election, or nomination for election by the Companys shareholders, is approved by a vote of at least a majority of the directors then comprising the Incumbent Board will be considered a member of the Incumbent Board as of the date hereof, but any such individual whose initial assumption of office occurs as a result of an actual or threatened election contest with respect to the election or removal of directors or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Incumbent Board will not be deemed a member of the Incumbent Board as of the date hereof.
(c) The consummation of a reorganization, merger, consolidation or sale or other disposition of all or substantially all of the assets of the Company (a Business Combination), unless following such Business Combination: (i) all or substantially all of the individuals and entities who were the beneficial owners, respectively, of the Outstanding Company Common Stock and Outstanding Company Voting Securities immediately prior to such Business Combination beneficially own, directly or indirectly, more than 60% of, respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the corporation resulting from such Business Combination (including, without limitation, a corporation which as a result of such transaction owns the Company or all or substantially all of the Companys assets either directly or through one or more subsidiaries) in substantially the same proportions as their ownership, immediately prior to such Business Combination of the Outstanding Company Common Stock and Outstanding Company Voting Securities, as the case may be, (ii) no Person (excluding any corporation resulting from such Business Combination or any employee benefit plan (or related trust) of the Company or such corporation resulting from such Business Combination) beneficially owns, directly or indirectly, 20% or more of, respectively, the then outstanding shares of common stock of the corporation resulting from such Business Combination or the combined voting power of the then outstanding voting securities of
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such corporation except to the extent that such ownership existed prior to the Business Combination and (iii) at least a majority of the members of the board of directors of the corporation resulting from such Business Combination were members of the Incumbent Board at the time of the execution of the initial agreement, or of the action of the Board, providing for such Business Combination.
(d) The approval by the shareholders of the Company of a complete liquidation or dissolution of the Company.
6.3.2 | CC Termination. The term CC Termination means any of the following: (a) this Agreement expires in accordance with its terms; (b) this Agreement is not extended under paragraph 5 of this Agreement and the Executive resigns within one (1) year after such non-extension; (c) the Executive is terminated by the Company other than under paragraphs 6.1.2, 6.4 or 6.5 based on adequate grounds; (d) the Executive resigns as a result of a change in the Executives duties or title, a reduction in the Executives then current compensation, a required relocation more than 25 miles from the Executives then current place of employment or a default by the Company under this Agreement; (e) the failure by the Company after a Change of Control to obtain the assumption of this Agreement, without limitation or reduction, by any successor to the Company or any parent corporation of the Company; or (f) after a Change of Control has occurred, the Executive agrees to remain employed by the Company for a period of three (3) months to assist in the transition and thereafter resigns. |
6.4 | Incapacity of Executive. If the Executive suffers from a physical or mental condition, which in the reasonable judgment of the Companys Board of Directors, prevents the Executive in whole or in part from performing the duties specified herein for a period of four (4) consecutive months, the Executive may be terminated. Although the termination will be deemed as a termination with Cause, any compensation payable under paragraph 4 of this Agreement will be continued through the remaining term of this Agreement, but in any event through the Expiration Date. Notwithstanding the foregoing, the Executives Base Salary specified in paragraph 4.1 of this Agreement will be reduced by any benefits payable under any disability plans provided by the Company under paragraph 4.4 of this Agreement. |
6.5 | Death of Executive. If the Executive dies during the term of this Agreement, the Company may thereafter terminate this Agreement without compensation to the Executives estate except: (a) the obligation to continue the Base Salary payments under paragraph 4.1 of this Agreement for twelve (12) months after the effective date of such termination, and (b) the benefits |
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described in paragraph 4.4 of this Agreement accrued through the effective date of such termination. |
6.6 | Effect of Termination. The termination of this Agreement will terminate all obligations of the Executive to render services on behalf of the Company, provided that the Executive will maintain the confidentiality of all information acquired by the Executive during the term of his employment in accordance with paragraph 7 of this Agreement. In the event of a termination under paragraphs 6.1.1 or 6.3 of this Agreement, the Executives right to participate in Program Wells will continue in accordance with paragraph 3 of this Agreement through the Expiration Date as extended under this Agreement. Except as otherwise provided in this paragraph 6, no accrued bonus, severance pay or other form of compensation will be payable by the Company to the Executive by reason of the termination of this Agreement. In the event that payments are required to be made by the Company under this paragraph 6, the Executive will not be required to seek other employment as a means of mitigating the Companys obligations hereunder resulting from termination of the Executives employment and the Companys obligations hereunder (including payment of severance benefits) will not be terminated, reduced or modified as a result of the Executives earnings from other employment or self-employment. All keys, entry cards, credit cards, files, records, financial information, furniture, furnishings, equipment, supplies and other items relating to the Company will remain the property of the Company. The Executive will have the right to retain and remove all personal property and effects that are owned by the Executive and located in the offices of the Company. All such personal items will be removed from such offices no later than ten (10) days after the effective date of termination, and the Company is hereby authorized to discard any items remaining and to reassign the Executives office space after such date. Prior to the effective date of termination, the Executive will cooperate with the Company to provide for the orderly termination of the Executives employment. |
7. Confidentiality. The Executive recognizes that the nature of the Executives services are such that the Executive will have access to information which constitutes trade secrets, is of a confidential nature, is of great value to the Company or is the foundation on which the business of the Company is predicated. The Executive agrees not to disclose to any person other than the Companys employees or the Companys legal counsel nor use for any purpose, other than the performance of this Agreement, any confidential information (Confidential Information). Confidential Information includes data or material (regardless of form) which is: (a) a trade secret; (b) provided, disclosed or delivered to Executive by the Company, any officer, director, employee, agent, attorney, accountant, consultant, or other person or entity employed by the Company in any capacity, any customer, borrower or business associate of the Company or any public authority having jurisdiction over the Company of any business activity conducted by the Company; or (c) produced, developed, obtained or prepared by or on behalf of Executive or the Company (whether or not such
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information was developed in the performance of this Agreement) with respect to the Company or any assets oil and gas prospects, business activities, officers, directors, employees, borrowers or customers of the foregoing. However, Confidential Information will not include any information, data or material which at the time of disclosure or use was generally available to the public other than by a breach of this Agreement, was available to the party to whom disclosed on a non-confidential basis by disclosure or access provided by the Company or a third party, or was otherwise developed or obtained independently by the person to whom disclosed without a breach of this Agreement. On request by the Company, the Company will be entitled to a copy of any Confidential Information in the possession of the Executive. The Executive also agrees that the provisions of this paragraph 7 will survive the termination, expiration or cancellation of this Agreement for a period of one (1) year. The Executive will deliver to the Company all originals and copies of the documents or materials containing Confidential Information. For purposes of paragraphs 7, 8, and 9 of this Agreement, the Company expressly includes any of the Company Entities.
8. Non-competition. For a period ending six months after the later of the Executives termination or the termination of the Executives participation rights as described in paragraph 3 of this Agreement, the Executive will not acquire, attempt to acquire or aid another in the acquisition or attempted acquisition of an interest in oil and gas assets, oil and gas production, oil and gas leases, minerals interests, oil and gas wells or other such oil and gas exploration, development or production activities within any spacing unit in which the Company owns an oil an gas interest on the date of the resignation or termination of the Executive. In addition, the Executive will not solicit, induce, entice or attempt to entice any employee, contractor, customer, vendor or subcontractor to terminate or breach any relationship with the Company or the Companys affiliates for the Executives own account or for the benefit of another party. The Executive further agrees that the Executive will not circumvent or attempt to circumvent the foregoing agreements by any future arrangement or through the actions of a third party. The foregoing will not prohibit the activities which are expressly permitted by paragraph 3 of this Agreement.
9. Proprietary Matters. The Executive expressly understands and agrees that any and all improvements, inventions, discoveries, processes or know-how that are generated or conceived by the Executive during the term of this Agreement, whether generated or conceived during the Executives regular working hours or otherwise, will be the sole and exclusive property of the Company. Whenever requested by the Company (either during the term of this Agreement or thereafter), the Executive will assign or execute any and all applications, assignments and or other instruments and do all things which the Company deems necessary or appropriate in order to permit the Company to: (a) assign and convey or otherwise make available to the Company the sole and exclusive right, title, and interest in and to said improvements, inventions, discoveries, processes, know-how, applications, patents, copyrights, trade names or trademarks; or (b) apply for, obtain, maintain, enforce and defend patents, copyrights, trade names, or trademarks of the United States or of foreign countries for said improvements, inventions, discoveries, processes or know-how. However, the improvements, inventions, discoveries, processes or know-how generated or
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conceived by the Executive and referred to above (except as they may be included in the patents, copyrights or registered trade names or trademarks of the Company, or corporations, partnerships or other entities which may be affiliated with the Company) will not be exclusive property of the Company at any time after having been disclosed or revealed or have otherwise become available to the public or to a third party on a non-confidential basis other than by a breach of this Agreement, or after they have been independently developed or discussed without a breach of this Agreement by a third party who has no obligation to the Company or the Company Entities.
10. Arbitration. The parties will attempt to promptly resolve any dispute or controversy arising out of or relating to this Agreement or termination of the Executive by the Company. Any negotiations pursuant to this paragraph 10 are confidential and will be treated as compromise and settlement negotiations for all purposes. If the parties are unable to reach a settlement amicably, the dispute will be submitted to binding arbitration before a single arbitrator in accordance with the Employment Dispute Resolution Rules of the American Arbitration Association. The arbitrator will be instructed and empowered to take reasonable steps to expedite the arbitration and the arbitrators judgment will be final and binding upon the parties subject solely to challenge on the grounds of fraud or gross misconduct. Except for damages arising out of a breach of paragraphs 6, 7, 8 or 9 of this Agreement, the arbitrator is not empowered to award total damages (including compensatory damages) that exceed 300% of compensatory damages and each party hereby irrevocably waives any damages in excess of that amount. The arbitration will be held in Oklahoma County, Oklahoma. Judgment upon any verdict in arbitration may be entered in any court of competent jurisdiction and the parties hereby consent to the jurisdiction of, and proper venue in, the federal and state courts located in Oklahoma County, Oklahoma. The Company will pay the costs and expenses of the arbitration including, without implied limitation, the fees for the arbitrators. Unless otherwise expressly set forth in this Agreement, the procedures specified in this paragraph 10 will be the sole and exclusive procedures for the resolution of disputes and controversies between the parties arising out of or relating to this Agreement. Notwithstanding the foregoing, a party may seek a preliminary injunction or other provisional judicial relief if in such partys judgment such action is necessary to avoid irreparable damage or to preserve the status quo.
11. Miscellaneous. The parties further agree as follows:
11.1 | Time. Time is of the essence of each provision of this Agreement. |
11.2 | Notices. Any notice, payment, demand or communication required or permitted to be given by any provision of this Agreement will be in writing and will be deemed to have been given when delivered personally or by telefacsimile to the party designated to receive such notice, or on the date following the day sent by overnight courier, or on the third (3rd) business day after the same is sent by certified mail, postage and charges prepaid, |
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directed to the following address or to such other or additional addresses as any party might designate by written notice to the other party: |
To the Company: |
Chesapeake Energy Corporation Post Office Box 18496 Oklahoma City, OK 73154-0496 Attn: Marcus C. Rowland | |
To the Executive: |
Mr. Aubrey K. McClendon 6902 Avondale Drive Oklahoma City, Oklahoma 73116 |
11.3 | Assignment. Neither this Agreement nor any of the parties rights or obligations hereunder can be transferred or assigned without the prior written consent of the other parties to this Agreement. |
11.4 | Construction. If any provision of this Agreement or the application thereof to any person or circumstances is determined, to any extent, to be invalid or unenforceable, the remainder of this Agreement, or the application of such provision to persons or circumstances other than those as to which the same is held invalid or unenforceable, will not be affected thereby, and each term and provision of this Agreement will be valid and enforceable to the fullest extent permitted by law. This Agreement is intended to be interpreted, construed and enforced in accordance with the laws of the State of Oklahoma. |
11.5 | Entire Agreement. Except as provided in paragraph 2.3 of this Agreement, this Agreement constitutes the entire agreement between the parties hereto with respect to the subject matter herein contained, and no modification hereof will be effective unless made by a supplemental written agreement executed by all of the parties hereto. |
11.6 | Binding Effect. This Agreement will be binding on the parties and their respective successors, legal representatives and permitted assigns. In the event of a merger, consolidation, combination, dissolution or liquidation of the Company, the performance of this Agreement will be assumed by any entity which succeeds to or is transferred the business of the Company as a result thereof. |
11.7 | Attorneys Fees. If any party institutes an action, proceeding or arbitration against any other party relating to the provisions of this Agreement or any default hereunder, the Company will be responsible for paying the Companys legal fees and expenses and the Company will be required to reimburse the Executive for reasonable expenses and legal fees incurred by |
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the Executive in connection with the resolution of such action or proceeding, including any costs of appeal. |
11.8 | Supercession. This Agreement is the final, complete and exclusive expression of the agreement between the Company and the Executive and supersedes and replaces in all respects any prior employment agreements (including the Prior Agreement). On execution of this Agreement by the Company and the Executive, the relationship between the Company and the Executive after the effective date of this Agreement will be governed by the terms of this Agreement and not by any other agreements, oral or otherwise. |
IN WITNESS WHEREOF, the undersigned have executed this Agreement effective the date first above written.
CHESAPEAKE ENERGY CORPORATION, an Oklahoma corporation | ||
By: | ||
Marcus C. Rowland, Executive Vice President and Chief Financial Officer | ||
(the Company) |
By: | ||
Aubrey K. McClendon, individually | ||
(the Executive) |
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Exhibit 10.2.2
THIRD AMENDED AND RESTATED
EMPLOYMENT AGREEMENT
THIS AGREEMENT is made effective January 1, 2004, between CHESAPEAKE ENERGY CORPORATION, an Oklahoma corporation (the Company), and TOM L. WARD, an individual (the Executive).
W I T N E S S E T H:
WHEREAS, the Company and the Executive entered into that certain Amended and Restated Employment Agreement dated effective July 1, 1998 as amended by the First Amendment to Amended and Restated Employment Agreement dated December 31, 1998 and as further amended by the Second Amended and Restated Employment Agreement dated January 1, 2001 (together the Prior Agreements);
WHEREAS, the Company and the Executive desire to amend and restate the Prior Agreements in their entirety.
NOW, THEREFORE, in consideration of the mutual promises herein contained, the Company and the Executive agree as follows:
1. Employment. The Company hereby employs the Executive and the Executive hereby accepts such employment subject to the terms and conditions contained in this Agreement. The Executive is engaged as an employee of the Company and the Executive and the Company do not intend to create a joint venture, partnership or other relationship that might impose a fiduciary obligation on the Executive or the Company in the performance of this Agreement.
2. Executives Duties. The Executive is employed on a full-time basis. Throughout the term of this Agreement, the Executive will use the Executives best efforts and due diligence to assist the Company in achieving the most profitable operation of the Company and the Companys affiliated entities consistent with developing and maintaining a quality business operation.
2.1 | Specific Duties. The Executive will serve as President and Chief Operating Officer for the Company. From time to time, the Executive may be appointed as an officer of one (1) or more of the Companys subsidiaries. During the term of this Agreement, the Executive will be nominated for election or appointed to serve as a director of the Company and one (1) or more of the Companys subsidiaries. The Executive will use the Executives best efforts to perform all of the services required to fully and faithfully execute the offices and positions to which the Executive is appointed and such other services as may be reasonably directed by the Board of Directors of the Company in accordance with this Agreement. |
2.2 | Modifications. The precise duties to be performed by the Executive may be extended or curtailed in the discretion of the Board of Directors of the Company. However, except for termination for Cause (as hereinafter defined) under paragraph 6.1.2 of this Agreement, the failure of the Executive to be elected, be reelected or serve as a director of the Company during the term of this Agreement, the removal of the Executive as a member of the board of directors of the Company, the withdrawal of the designation of the Executive as President and Chief Operating Officer of the Company, or the assignment of the performance of duties incumbent on the foregoing offices to other persons without the prior written consent of the Executive will constitute termination without Cause by the Company. |
2.3 | Rules and Regulations. From time to time, the Company may issue policies applicable to employees and the Executive including an Employment Policies Manual that addresses frequently asked questions regarding the Company. The Executive agrees to comply with such policies, except to the extent such policies are inconsistent with this Agreement. The policies and the Employment Policies Manual are subject to change without notice in the sole discretion of the Company at any time. In the event of a conflict between such policies and this Agreement, this Agreement will control over the terms of the Employment Policies Manual. |
2.4 | Stock Investment. During the term of this Agreement, the Executive agrees to hold shares of the Companys common stock having an aggregate Investment Value (as hereafter defined) greater than five hundred percent (500%) of the compensation paid to the Executive under paragraphs 4.1 and 4.2 of this Agreement during such calendar year. Any shares of common stock acquired by the Executive prior to the date of this Agreement and still owned by the Executive during the term of this Agreement may be used to satisfy the requirement to own common stock. For purposes of this paragraph, the Investment Value of each share of stock will be as follows: (a) for shares purchased in the open market the price paid by the Executive for such shares; (b) for shares acquired after the Companys initial public offering (IPO) in February 1993 through the exercise of stock options or other than through open market purchases, the fair market value of the common stock on the date the option was exercised or the stock was acquired; and (c) for shares acquired prior to the Companys IPO, the price obtained for stock in the IPO adjusted for subsequent stock splits. This paragraph will become null and void if the Companys common stock ceases to be listed on the New York Stock Exchange, the National Association of Securities Dealers Automated Quotation System or other national exchange. The Company has no obligation to sell or to purchase from the Executive any of the Companys stock in connection with this paragraph 2.4 and has made no representations or warranties regarding the Companys stock, operations or financial condition. |
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3. Other Activities. Except for the activities (the Permitted Activities) expressly permitted by paragraphs 3.1 and 3.2 of this Agreement or approved by the board of directors of the Company, the Executive will not: (a) engage in business independent of the Executives employment by the Company which requires any substantial portion of the Executives time; (b) serve as an officer or director of any public corporation, partnership, company, or firm; (c) except for passive investments that do not violate this Agreement and require only a minimal portion of the Executives time, serve as a general partner or member of any corporation, partnership, company or firm; or (d) directly or indirectly invest in, participate in or acquire an interest in any oil and gas business, including, without limitation, (i) producing oil and gas, (ii) drilling, owning or operating oil and gas leases or wells, (iii) providing services or materials to the oil and gas industry, (iv) marketing or refining oil or gas, or (v) owning any interest in any corporation, partnership, company or entity which conducts any of the foregoing activities. The limitations in this paragraph 3 will not prohibit an investment by the Executive in publicly traded securities. Notwithstanding the foregoing, the Executive will be permitted to participate in the following activities that will be deemed to be approved by the Company, if such activities are undertaken in strict compliance with this Agreement. The foregoing will not prohibit the ownership of royalty interests where the Executive owns or previously owned the surface of the land covered by the royalty interest and the ownership of the royalty interest is incidental to the ownership of the surface estate or the ownership of royalty, overriding royalty or working interests that are received by gift, inheritance or were acquired prior to the Executives date of first employment with the Company.
3.1 | Existing Interests. The Executive has in the past conducted oil and gas activities individually and through TLW Investments, Inc., TLW Production Company and other entities owned or controlled by the Executive (collectively, the Executive Affiliates). The Executive will be permitted to continue to conduct oil and gas activities (including participation in new wells) directly or through the Executive Affiliates, but only to the extent such activities are conducted on oil and gas leases or interests which the Executive or Executive Affiliates owned or had the right to acquire as of July 1, 2001, or which the Executive or the Executive Affiliates acquired from the Company under this Agreement or prior agreements with the Company (collectively, the Prior Interests). To the extent that the oil and gas interests or activities covered by this paragraph 3.1 are operated by the Company, the ownership and participation will be subject to the payment provisions set forth in this paragraph 3. |
3.2 | Companys Activities. The Executive or the designated Executive Affiliate will be permitted to acquire on the terms and conditions set forth herein an interest in the governmental, spacing or production unit for each of the wells (the Program Wells) spudded by any of the Company Entities (as hereafter defined) in any Calendar Quarter (as hereafter defined) during the Participation Term (as hereafter defined). The Program Wells include any well spudded during such Calendar Quarter in which the Company Entities |
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participate as a non-operator. Program Wells will include grass-roots wells only and will exclude re-entries of existing wells. |
3.2.1 | Election. On or before the date which is thirty (30) days before the first (1st) day of each Calendar Quarter, the Executive will provide notice to the Compensation Committee of the Companys Board of Directors of the Executives intent to participate in Program Wells during the succeeding Calendar Quarter and the minimum percentage working interest which the Executive proposes to participate with during such Calendar Quarter (the Acquisition Percentage). The Executives elected Acquisition Percentage for any Calendar Quarter will not exceed two and one-half percent (2.5%) on an eight-eighths (8/8ths) basis. If prior to the date specified herein, the Executive fails to provide notice of the Executives intent to participate or of the Acquisition Percentage for a Calendar Quarter, the amount of the Acquisition Percentage for the Calendar Quarter will be deemed to be equal to the Acquisition Percentage for the immediately preceding Calendar Quarter. |
3.2.2 | Amount of Participation. On election to participate and the designation of the Acquisition Percentage for a Calendar Quarter, the Executive will be deemed to have elected to participate in each Program Well spudded during such Calendar Quarter with a working interest equal to the greater of the following determined on a well-by-well basis (the Minimum Participation): (a) the Acquisition Percentage for such Program Well (as adjusted for any well under paragraph 3.2.3); or (b) the Prior Interest of the Executive or the Executive Affiliates in the drilling unit for such Program Well. If the foregoing clause (a) is applicable to a Program Well, then the Company will assign or allocate to the Executive or the designated Executive Affiliate a unit working interest in the Program Well sufficient to cause the Executive and the Executive Affiliates combined interest in such Program Well to equal the Acquisition Percentage (including in such computation any Prior Interests). The interest to be assigned or allocated under this paragraph to cause the Executives participation to be equal to the Acquisition Percentage will be derived proportionately from all the interests owned by the Company in the Program Wells (including non-consenting interests, back-in interests, leased royalty interests, overriding royalty interests or other similar interests) so that the interests assigned or allocated to the Executive are substantially similar to the interests retained by the Company. If the Executive elects not to participate in Program Wells during a Calendar Quarter, then the Executive can elect to participate or not participate with any Prior Interests under the existing agreements related to such Prior Interests. |
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3.2.3 | Minimum Company Working Interest Ownership Level. If the combined interests in a specific Program Well to be assigned or allocated by the Company to the Executive and Mr. Aubrey K. McClendon under their respective employment agreements causes the Companys working interest (determined after consideration of any carried or reversionary interests) on the spud date for such Program Well to be less than twelve and one-half percent (12.5%) on an eight-eighths (8/8ths) basis, then the Acquisition Percentage for that Program Well will be equal to zero for purposes of paragraph 3.2.2 of this Agreement. If this paragraph 3.2.3 prohibits the Executives participation in a Program Well, then Mr. McClendon will also not be entitled to participate in such Program Well under his employment agreement. |
3.3 | Conditions of Participation. The Participation by the Executive in each Program Well will be on no better terms than the terms agreed to by unaffiliated third party participants in connection with the participation in such Program Well or similar wells operated by the Company Entities. The Acquisition Percentage cannot be changed during any Calendar Quarter without the prior approval of the members of the Compensation Committee of the Companys board of directors. Any participation by the Executive under paragraph 3.2 is also conditioned on the Executives participation in each Program Well spudded during such Calendar Quarter in an amount equal to the Minimum Participation. The Executive hereby agrees to execute and deliver any documents reasonably requested by the Company and hereby appoints the Company as the Executives agent and attorney-in-fact to execute and deliver such documents if the Executive fails or refuses to execute such documents. The Executive further agrees to pay all joint interest billings promptly after receipt of the Companys invoice in accordance with the applicable joint operating agreement or, in the absence of an applicable joint operating agreement, the standard joint operating agreement used by the Company in the ordinary conduct of its business. |
3.4 | Definitions. For purposes of this Agreement, the term: (a) Calendar Quarter means the three (3) month periods commencing on the first (1st) day of January, April, July and October; (b) the term Company Entities means the Company, any affiliate or successor to the Company, any entity which controls, subsequently owns or is under common control with the Company and any subsidiary corporation, partnership, limited liability company or other entity owned by, controlled by or under common control with any of the foregoing (whether direct or indirect); and (c) Participation Term means the term of this Agreement plus five (5) years after a termination under paragraphs 6.1.1 or 6.3 of this Agreement. |
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4. Executives Compensation. The Company agrees to compensate the Executive as follows:
4.1 | Base Salary. A base salary (the Base Salary), in an annual rate of not less than Eight Hundred Thousand Dollars ($800,000.00), will be paid to the Executive in equal semi-monthly installments, beginning January 15, 2004, during the term of this Agreement. |
4.2 | Bonus. In addition to the Base Salary described at paragraph 4.1 of this Agreement, the Company may periodically pay bonus compensation to the Executive. Any bonus compensation will be at the absolute discretion of the Company in such amounts and at such times as the Compensation Committee of the Board of Directors of the Company may determine. |
4.3 | Equity Compensation. In addition to the compensation set forth in paragraphs 4.1 and 4.2 of this Agreement, the Executive may periodically receive grants of stock options, restricted stock or other equity related awards from the Companys various stock compensation plans, subject to the terms and conditions thereof. |
4.4 | Benefits. The Company will provide the Executive such retirement benefits, reimbursement of reasonable expenditures for dues, travel and entertainment and other benefits on terms customarily provided by the Company from time to time. The Company will also provide the Executive the opportunity to apply for coverage under the Companys medical, life and disability plans, if any. If the Executive is accepted for coverage under such plans, the Company will provide such coverage on the same terms as is customarily provided by the Company to the plan participants as modified from time to time. The following specific benefits will also be provided to the Executive at the expense of the Company: |
4.4.1 | Vacation. The Executive will be entitled to take up to five (5) weeks of paid vacation each calendar year during the term of this Agreement. No additional compensation will be paid for failure to take vacation and no vacation may be carried forward from one calendar year to another. |
4.4.2 | Membership Dues. The Company will reimburse the Executive for: (a) the monthly dues necessary to maintain a full membership in (1) golf and/or country club in the Oklahoma City area selected by the Executive; and (b) the reasonable cost of any qualified business entertainment at such country club. All other costs, including, without implied limitation, any initiation costs, initial membership costs, personal use and business entertainment unrelated to the Company |
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will be the sole obligation of the Executive and the Company will have no liability with respect to such amounts. |
4.4.3 | Travel. The Executive will receive a monthly cash allowance in the amount of Two Thousand Dollars ($2,000.00) to defer a portion of the Executives cost of acquiring, operating and maintaining an automobile for use in the Executives employment. Additionally, for safety and security reasons, the Executive will be required to utilize aircraft owned or leased by the Company for business and personal use in the Western Hemisphere (including North America, South America and the surrounding oceans) and will not be required to reimburse the Company for any cost related to such use. In addition, the Executives immediate family members may use such company aircraft for their personal use to the same extent. When a family member travels without the Executive, then the Executive agrees to reimburse the company for the variable costs of such use. For purposes of this Agreement, the variable cost of using the Companys aircraft means the variable costs directly identifiable with each use (including fuel, pilot charges, landing fees, hourly charges under co-ownership arrangements and other such costs), but specifically excluding any fixed costs of the aircraft (including acquisition costs and depreciation). The Executive will pay all personal income taxes accruing as a result of the personal use of the Companys aircraft by the Executive under this paragraph. |
4.4.4 | Accounting Support. The Executive will be permitted to utilize the Companys office space, computer facilities and personnel to provide accounting services, records maintenance and tax advice and tax return preparation for the Executives (and his familys) personal business investments and activities. The Executive will not be required to pay any amount to the Company in connection with such accounting support. |
4.5 | Gross-Up Payment. In the event it is determined that any payment or distribution by the Company or the Company Entities to or for the benefit of the Executive (whether paid or payable or distributed or distributable pursuant to the terms of this Agreement or otherwise, but determined without regard to any additional payments required under this paragraph 4.5) (a Payment) is subject to the excise tax imposed by Section 4999 of the Internal Revenue Code (the Code) or any interest or penalties related to such excise tax (collectively, the Excise Tax), the Executive will be entitled to receive an additional payment (a Gross-Up Payment) from the Company. The Gross-Up Payment will be equal to the amount such that after payment by the Executive of all taxes (including the Excise Tax, income taxes, interest and penalties imposed with respect to such taxes) on the Gross-Up |
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Payment, the Executive will retain an amount of the Gross-Up Payment equal to the Excise Tax imposed on the Payment. |
4.5.1 | Determination. Subject to the provisions of paragraph 4.5.2 all determinations required to be made under this paragraph 4.5 (including whether and when a Gross-Up Payment is required, the amount of such Gross-Up Payment and the assumptions to be utilized) will be made by a nationally recognized certified public accounting firm designated by the Executive (the Accounting Firm). The Accounting Firm will provide detailed supporting calculations both to the Company and the Executive within fifteen (15) business days of the receipt of notice from the Executive that there has been a Payment, or such earlier time as is reasonably requested by the Company. In the event that the Accounting Firm is serving as accountant or auditor for the individual, entity or group effecting a Change of Control (as hereinafter defined), the Executive will be entitled to appoint another nationally recognized accounting firm to make the determinations required under this paragraph (which accounting firm will then be referred to as the Accounting Firm hereunder). All fees and expenses of the Accounting Firm will be paid by the Company. Any Gross-Up Payment required to be paid under this paragraph 4.5 will be paid by the Company to the Executive within five (5) days of the receipt of the Accounting Firms determination. Any determination by the Accounting Firm will be binding on the Company and the Executive. As a result of the uncertainty in the application of Section 4999 of the Code at the time of the initial determination by the Accounting Firm, the Gross-Up Payment made by the Company may be less than actually required (an Underpayment) consistent with the calculations required to be made hereunder. In the event that the Company exhausts its remedies pursuant to paragraph 4.5.2 below and the Executive thereafter is required to make a payment of any Excise Tax, the Accounting Firm will determine the amount of the Underpayment that has occurred and any such Underpayment will be promptly paid by the Company to or for the benefit of the Executive. |
4.5.2 | Contest of Claims. The Executive will notify the Company in writing of any claim by the Internal Revenue Service that, if successful, would require the payment by the Company of a Gross-Up Payment. Such notification will be given as soon as practicable but no later than ten (10) business days after the Executive is informed in writing of such claim and will apprise the Company of the nature of such claim and the date on which such claim is requested to be paid. The Executive will not pay such claim prior to the expiration of the thirty (30) day period following the date on which the Executive notifies the Company |
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(or such shorter period ending on the date that any payment of taxes with respect to such claim is due). If the Company notifies the Executive in writing prior to the expiration of such thirty (30) day period that the Company desires to contest such claim, the Executive will: (a) provide to the Company any information reasonably requested by the Company relating to such claim; (b) take such action in connection with contesting such claim as the Company reasonably requests in writing including, without limitation, accepting legal representation with respect to such claim by an attorney reasonably selected by the Company; (c) cooperate with the Company in good faith as necessary to effectively contest such claim; and (d) permit the Company to participate in any proceedings relating to such claim. The Company will bear and pay directly all costs and expenses (including additional interest and penalties) incurred in connection with the contest of the claim and agrees to indemnify and hold the Executive harmless, on an after-tax basis, for any Excise Tax or income tax (including interest and penalties with respect thereto) imposed as a result of such protest (including payment of costs and expenses as provided hereunder). Without limitation on the foregoing provisions, the Company will control all proceedings related to such contested claim, may at its sole option pursue or forgo any and all administrative appeals, proceedings, hearings and conferences with the taxing authority in respect of such claim and may at its sole option either direct the Executive to pay the tax claimed and sue for a refund or contest the claim in any permissible manner. The Executive agrees to prosecute such contest to a determination before any administrative tribunal, in a court of initial jurisdiction and in one or more appellate courts, as the Company reasonably determines. If the Company directs the Executive to pay a claim and sue for a refund, the Company will be required to advance the amount of such payment to the Executive on an interest-free basis and agrees to indemnify and hold the Executive harmless, on an after-tax basis, from any Excise Tax or income tax (including interest or penalties with respect thereto) imposed with respect to such advance or with respect to any imputed income with respect to such advance, provided that any extension of the statute of limitations relating to payment of taxes for the taxable year of the Executive with respect to which such contested amount is claimed to be due is limited solely to such contested amount. Furthermore, the Companys control of the contested claim will be limited to issues with respect to which a Gross-Up Payment would be payable hereunder and the Executive will be entitled to settle or contest, as the case may be, any other issue raised by the Internal Revenue Service or any other taxing authority. |
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4.5.3 | Refunds. If, after the receipt by the Executive of an amount advanced by the Company pursuant to paragraph 4.5.2, the Executive becomes entitled to receive any refund with respect to such claim the Executive will (subject to the Companys complying with the requirements of paragraph 4.5.2) promptly pay to the Company the amount of such refund (together with any interest paid or credited thereon after taxes applicable thereto). If, after the receipt by the Executive of an amount advanced by the Company pursuant to paragraph 4.5.2, a determination is made that the Executive will not be entitled to any refund with respect to such claim and the Company does not notify the Executive in writing of its intent to contest such denial of refund prior to the expiration of (30) days after such determination, then the advance will be forgiven and will not be required to be repaid and the amount of such advance will offset, to the extent thereof, the amount of Gross-Up Payment required to be paid. |
4.6 | Compensation Review. The compensation of the Executive will be reviewed not less frequently than semi-annually by the Compensation Committee of the Board of Directors of the Company. The compensation of the Executive prescribed in paragraph 4 of this Agreement (including benefits) may be increased at the discretion of the Compensation Committee of the Board of Directors of the Company, but may not be reduced without the prior written consent of the Executive. |
5. Term. In the absence of termination as set forth in paragraph 6 below, this Agreement will extend for a term of five (5) years commencing on January 1, 2004, and ending on December 31, 2008 (the Expiration Date) as extended from time to time. Unless the Company provides thirty (30) days prior written notice of non-extension to the Executive, on each January 31 during the term of this Agreement, the term and the Expiration Date will be automatically extended for one (1) additional year so that the remaining term on this Agreement will be not less than four (4) and not more than five (5) years.
6. Termination. This Agreement will continue in effect until the expiration of the term set forth in paragraph 5 of this Agreement unless earlier terminated pursuant to this paragraph 6.
6.1 | Termination by Company. The Company will have the following rights to terminate this Agreement: |
6.1.1 | Termination without Cause. The Company may terminate this Agreement without Cause at any time by the service of written notice of termination to the Executive specifying an effective date of such termination not sooner than ninety (90) business days after the date of such notice (the Termination Date). In the event the Executive is terminated without Cause (other than a CC Termination under |
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paragraph 6.3 of this Agreement), the Executive will receive as termination compensation: (a) Base Compensation (as hereafter defined) during the remaining term of this Agreement, but in any event through the Expiration Date; (b) any benefits provided by operation of paragraph 4.4 of this Agreement during the remaining term of this Agreement, but in any event through the Expiration Date (including, without implied limitation, suitable office space, secretarial and accounting support at the levels presently provided by the Company to the Executive); and (c) any vacation pay accrued through the Termination Date. For purposes of this Agreement the term Base Compensation means the Executives current Base Salary under paragraph 4.1 on the Termination Date plus the bonus compensation received by the Executive during the twelve (12) month period preceding the Termination Date. |
6.1.2 | Termination for Cause. The Company may terminate this Agreement for Cause. For purposes of this Agreement, Cause means: (a) the willful and continued failure of the Executive to perform substantially the Executives duties with the Company or one of the Company Entities (other than a failure resulting from incapacity due to physical or mental illness), after a written demand for substantial performance is delivered to the Executive by the Board of Directors which specifically identifies the manner in which the Board of Directors believes that the Executive has not substantially performed the Executives duties; or (b) the willful engaging by the Executive in illegal conduct, gross misconduct or a clearly established violation of the Companys code of conduct, in each case which is materially and demonstrably injurious to the Company. For purposes of this provision, an act or failure to act, on the part of the Executive, will not be considered willful unless it is done, or omitted to be done, by the Executive in bad faith or without reasonable belief that the Executives action or omission was in the best interests of the Company. Any act, or failure to act, based on authority given pursuant to a resolution duly adopted by the Board of Directors or based on the advice of counsel for the Company will be conclusively presumed to be done, or omitted to be done, by the Executive in good faith and in the best interests of the Company. In the event this Agreement is terminated for Cause, the Company will not have any obligation to provide any further payments or benefits to the Executive after the effective date of such termination. This Agreement will not be deemed to have terminated for Cause unless a written determination specifying the reasons for such termination is made, approved by a majority of the independent and disinterested members of the Board of Directors of the Company and delivered to the Executive. Thereafter, the Executive will have the right for a period of thirty (30) days to request a Board of Directors |
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meeting to be held at a mutually agreeable time and location within the following thirty (30) days, at which meeting the Executive will have an opportunity to be heard. Failing such determination and opportunity for hearing, any termination of this Agreement will be deemed to have occurred without Cause. |
6.2 | Termination by Executive. The Executive may voluntarily terminate this Agreement with or without Cause by the service of written notice of such termination to the Company specifying an effective date of such termination ninety (90) days after the date of such notice, during which time the Executive may use remaining accrued vacation days, or at the Companys option, be paid for such days. In the event this Agreement is terminated by the Executive, neither the Company nor the Executive will have any further obligations hereunder including, without limitation, any obligation of the Company to provide any further payments or benefits to the Executive after the effective date of such termination. |
6.3 | Termination After Change in Control. If during the term of this Agreement there is a Change of Control and within three (3) years thereafter there is a CC Termination (as hereafter defined), then the Executive will be entitled to a severance payment (in addition to any other rights and other amounts payable to the Executive under this Agreement or otherwise) in an amount equal to the sum of the following: (a) five (5) times the Executives Base Compensation; plus (b) five (5) times the value of any benefits provided by operation of paragraph 4.4 of this Agreement during the preceding twelve (12) months; plus (c) any applicable Gross-Up Payment. If the foregoing amount is not paid within ten (10) days after the CC Termination, the unpaid amount will bear interest at the per annum rate of 12%. In addition, for a period of twelve (12) months after a CC Termination, the Company will provide at no cost to the Executive suitable office space and secretarial and accounting support at the levels presently provided by the Company. |
6.3.1 | Change of Control. For the purpose of this Agreement, a Change of Control means the occurrence of any of the following: |
(a) The acquisition by any individual, entity or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Securities Exchange Act of 1934, as amended (the Exchange Act)) (a Person) of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of 20% or more of either (i) the then outstanding shares of common stock of the Company (the Outstanding Company Common Stock) or (ii) the combined voting power of the then outstanding voting securities of the Company entitled to vote generally in the election of directors (the Outstanding Company Voting Securities). For purposes of this paragraph (a) the following acquisitions by a Person will not constitute a Change of
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Control: (i) any acquisition directly from the Company; (ii) any acquisition by the Company; (iii) any acquisition by any employee benefit plan (or related trust) sponsored or maintained by the Company or any corporation controlled by the Company; or (iv) any acquisition by any corporation pursuant to a transaction which complies with clauses (i), (ii) and (iii) of paragraph (c) of this paragraph 6.3.1.
(b) The individuals who, as of the date hereof, constitute the Board of Directors (the Incumbent Board) cease for any reason to constitute at least a majority of the Board of Directors. Any individual becoming a director subsequent to the date hereof whose election, or nomination for election by the Companys shareholders, is approved by a vote of at least a majority of the directors then comprising the Incumbent Board will be considered a member of the Incumbent Board as of the date hereof, but any such individual whose initial assumption of office occurs as a result of an actual or threatened election contest with respect to the election or removal of directors or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Incumbent Board will not be deemed a member of the Incumbent Board as of the date hereof.
(c) The consummation of a reorganization, merger, consolidation or sale or other disposition of all or substantially all of the assets of the Company (a Business Combination), unless following such Business Combination: (i) all or substantially all of the individuals and entities who were the beneficial owners, respectively, of the Outstanding Company Common Stock and Outstanding Company Voting Securities immediately prior to such Business Combination beneficially own, directly or indirectly, more than 60% of, respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the corporation resulting from such Business Combination (including, without limitation, a corporation which as a result of such transaction owns the Company or all or substantially all of the Companys assets either directly or through one or more subsidiaries) in substantially the same proportions as their ownership, immediately prior to such Business Combination of the Outstanding Company Common Stock and Outstanding Company Voting Securities, as the case may be, (ii) no Person (excluding any corporation resulting from such Business Combination or any employee benefit plan (or related trust) of the Company or such corporation resulting from such Business Combination) beneficially owns, directly or indirectly, 20% or more of, respectively, the then outstanding shares of common stock of the corporation resulting from such Business Combination or the combined voting power of the then outstanding voting securities of
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such corporation except to the extent that such ownership existed prior to the Business Combination and (iii) at least a majority of the members of the board of directors of the corporation resulting from such Business Combination were members of the Incumbent Board at the time of the execution of the initial agreement, or of the action of the Board, providing for such Business Combination.
(d) The approval by the shareholders of the Company of a complete liquidation or dissolution of the Company.
6.3.2 | CC Termination. The term CC Termination means any of the following: (a) this Agreement expires in accordance with its terms; (b) this Agreement is not extended under paragraph 5 of this Agreement and the Executive resigns within one (1) year after such non-extension; (c) the Executive is terminated by the Company other than under paragraphs 6.1.2, 6.4 or 6.5 based on adequate grounds; (d) the Executive resigns as a result of a change in the Executives duties or title, a reduction in the Executives then current compensation, a required relocation more than 25 miles from the Executives then current place of employment or a default by the Company under this Agreement; (e) the failure by the Company after a Change of Control to obtain the assumption of this Agreement, without limitation or reduction, by any successor to the Company or any parent corporation of the Company; or (f) after a Change of Control has occurred, the Executive agrees to remain employed by the Company for a period of three (3) months to assist in the transition and thereafter resigns. |
6.4 | Incapacity of Executive. If the Executive suffers from a physical or mental condition, which in the reasonable judgment of the Companys Board of Directors, prevents the Executive in whole or in part from performing the duties specified herein for a period of four (4) consecutive months, the Executive may be terminated. Although the termination will be deemed as a termination with Cause, any compensation payable under paragraph 4 of this Agreement will be continued through the remaining term of this Agreement, but in any event through the Expiration Date. Notwithstanding the foregoing, the Executives Base Salary specified in paragraph 4.1 of this Agreement will be reduced by any benefits payable under any disability plans provided by the Company under paragraph 4.4 of this Agreement. |
6.5 | Death of Executive. If the Executive dies during the term of this Agreement, the Company may thereafter terminate this Agreement without compensation to the Executives estate except: (a) the obligation to continue the Base Salary payments under paragraph 4.1 of this Agreement for twelve (12) months after the effective date of such termination, and (b) the benefits |
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described in paragraph 4.4 of this Agreement accrued through the effective date of such termination. |
6.6 | Effect of Termination. The termination of this Agreement will terminate all obligations of the Executive to render services on behalf of the Company, provided that the Executive will maintain the confidentiality of all information acquired by the Executive during the term of his employment in accordance with paragraph 7 of this Agreement. In the event of a termination under paragraphs 6.1.1 or 6.3 of this Agreement, the Executives right to participate in Program Wells will continue in accordance with paragraph 3 of this Agreement through the Expiration Date as extended under this Agreement. Except as otherwise provided in this paragraph 6, no accrued bonus, severance pay or other form of compensation will be payable by the Company to the Executive by reason of the termination of this Agreement. In the event that payments are required to be made by the Company under this paragraph 6, the Executive will not be required to seek other employment as a means of mitigating the Companys obligations hereunder resulting from termination of the Executives employment and the Companys obligations hereunder (including payment of severance benefits) will not be terminated, reduced or modified as a result of the Executives earnings from other employment or self-employment. All keys, entry cards, credit cards, files, records, financial information, furniture, furnishings, equipment, supplies and other items relating to the Company will remain the property of the Company. The Executive will have the right to retain and remove all personal property and effects that are owned by the Executive and located in the offices of the Company. All such personal items will be removed from such offices no later than ten (10) days after the effective date of termination, and the Company is hereby authorized to discard any items remaining and to reassign the Executives office space after such date. Prior to the effective date of termination, the Executive will cooperate with the Company to provide for the orderly termination of the Executives employment. |
7. Confidentiality. The Executive recognizes that the nature of the Executives services are such that the Executive will have access to information which constitutes trade secrets, is of a confidential nature, is of great value to the Company or is the foundation on which the business of the Company is predicated. The Executive agrees not to disclose to any person other than the Companys employees or the Companys legal counsel nor use for any purpose, other than the performance of this Agreement, any confidential information (Confidential Information). Confidential Information includes data or material (regardless of form) which is: (a) a trade secret; (b) provided, disclosed or delivered to Executive by the Company, any officer, director, employee, agent, attorney, accountant, consultant, or other person or entity employed by the Company in any capacity, any customer, borrower or business associate of the Company or any public authority having jurisdiction over the Company of any business activity conducted by the Company; or (c) produced, developed, obtained or prepared by or on behalf of Executive or the Company (whether or not such
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information was developed in the performance of this Agreement) with respect to the Company or any assets oil and gas prospects, business activities, officers, directors, employees, borrowers or customers of the foregoing. However, Confidential Information will not include any information, data or material which at the time of disclosure or use was generally available to the public other than by a breach of this Agreement, was available to the party to whom disclosed on a non-confidential basis by disclosure or access provided by the Company or a third party, or was otherwise developed or obtained independently by the person to whom disclosed without a breach of this Agreement. On request by the Company, the Company will be entitled to a copy of any Confidential Information in the possession of the Executive. The Executive also agrees that the provisions of this paragraph 7 will survive the termination, expiration or cancellation of this Agreement for a period of one (1) year. The Executive will deliver to the Company all originals and copies of the documents or materials containing Confidential Information. For purposes of paragraphs 7, 8, and 9 of this Agreement, the Company expressly includes any of the Company Entities.
8. Non-competition. For a period ending six months after the later of the Executives termination or the termination of the Executives participation rights as described in paragraph 3 of this Agreement, the Executive will not acquire, attempt to acquire or aid another in the acquisition or attempted acquisition of an interest in oil and gas assets, oil and gas production, oil and gas leases, minerals interests, oil and gas wells or other such oil and gas exploration, development or production activities within any spacing unit in which the Company owns an oil an gas interest on the date of the resignation or termination of the Executive. In addition, the Executive will not solicit, induce, entice or attempt to entice any employee, contractor, customer, vendor or subcontractor to terminate or breach any relationship with the Company or the Companys affiliates for the Executives own account or for the benefit of another party. The Executive further agrees that the Executive will not circumvent or attempt to circumvent the foregoing agreements by any future arrangement or through the actions of a third party. The foregoing will not prohibit the activities which are expressly permitted by paragraph 3 of this Agreement.
9. Proprietary Matters. The Executive expressly understands and agrees that any and all improvements, inventions, discoveries, processes or know-how that are generated or conceived by the Executive during the term of this Agreement, whether generated or conceived during the Executives regular working hours or otherwise, will be the sole and exclusive property of the Company. Whenever requested by the Company (either during the term of this Agreement or thereafter), the Executive will assign or execute any and all applications, assignments and or other instruments and do all things which the Company deems necessary or appropriate in order to permit the Company to: (a) assign and convey or otherwise make available to the Company the sole and exclusive right, title, and interest in and to said improvements, inventions, discoveries, processes, know-how, applications, patents, copyrights, trade names or trademarks; or (b) apply for, obtain, maintain, enforce and defend patents, copyrights, trade names, or trademarks of the United States or of foreign countries for said improvements, inventions, discoveries, processes or know-how. However, the improvements, inventions, discoveries, processes or know-how generated or
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conceived by the Executive and referred to above (except as they may be included in the patents, copyrights or registered trade names or trademarks of the Company, or corporations, partnerships or other entities which may be affiliated with the Company) will not be exclusive property of the Company at any time after having been disclosed or revealed or have otherwise become available to the public or to a third party on a non-confidential basis other than by a breach of this Agreement, or after they have been independently developed or discussed without a breach of this Agreement by a third party who has no obligation to the Company or the Company Entities.
10. Arbitration. The parties will attempt to promptly resolve any dispute or controversy arising out of or relating to this Agreement or termination of the Executive by the Company. Any negotiations pursuant to this paragraph 10 are confidential and will be treated as compromise and settlement negotiations for all purposes. If the parties are unable to reach a settlement amicably, the dispute will be submitted to binding arbitration before a single arbitrator in accordance with the Employment Dispute Resolution Rules of the American Arbitration Association. The arbitrator will be instructed and empowered to take reasonable steps to expedite the arbitration and the arbitrators judgment will be final and binding upon the parties subject solely to challenge on the grounds of fraud or gross misconduct. Except for damages arising out of a breach of paragraphs 6, 7, 8 or 9 of this Agreement, the arbitrator is not empowered to award total damages (including compensatory damages) that exceed 300% of compensatory damages and each party hereby irrevocably waives any damages in excess of that amount. The arbitration will be held in Oklahoma County, Oklahoma. Judgment upon any verdict in arbitration may be entered in any court of competent jurisdiction and the parties hereby consent to the jurisdiction of, and proper venue in, the federal and state courts located in Oklahoma County, Oklahoma. The Company will pay the costs and expenses of the arbitration including, without implied limitation, the fees for the arbitrators. Unless otherwise expressly set forth in this Agreement, the procedures specified in this paragraph 10 will be the sole and exclusive procedures for the resolution of disputes and controversies between the parties arising out of or relating to this Agreement. Notwithstanding the foregoing, a party may seek a preliminary injunction or other provisional judicial relief if in such partys judgment such action is necessary to avoid irreparable damage or to preserve the status quo.
11. Miscellaneous. The parties further agree as follows:
11.1 | Time. Time is of the essence of each provision of this Agreement. |
11.2 | Notices. Any notice, payment, demand or communication required or permitted to be given by any provision of this Agreement will be in writing and will be deemed to have been given when delivered personally or by telefacsimile to the party designated to receive such notice, or on the date following the day sent by overnight courier, or on the third (3rd) business day after the same is sent by certified mail, postage and charges prepaid, |
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directed to the following address or to such other or additional addresses as any party might designate by written notice to the other party: |
To the Company: |
Chesapeake Energy Corporation Post Office Box 18496 Oklahoma City, OK 73154-0496 Attn: Marcus C. Rowland | |
To the Executive: |
Mr. Tom L. Ward 19200 North Rockwell Avenue Oklahoma City, Oklahoma 73003-9200 |
11.3 | Assignment. Neither this Agreement nor any of the parties rights or obligations hereunder can be transferred or assigned without the prior written consent of the other parties to this Agreement. |
11.4 | Construction. If any provision of this Agreement or the application thereof to any person or circumstances is determined, to any extent, to be invalid or unenforceable, the remainder of this Agreement, or the application of such provision to persons or circumstances other than those as to which the same is held invalid or unenforceable, will not be affected thereby, and each term and provision of this Agreement will be valid and enforceable to the fullest extent permitted by law. This Agreement is intended to be interpreted, construed and enforced in accordance with the laws of the State of Oklahoma. |
11.5 | Entire Agreement. Except as provided in paragraph 2.3 of this Agreement, this Agreement constitutes the entire agreement between the parties hereto with respect to the subject matter herein contained, and no modification hereof will be effective unless made by a supplemental written agreement executed by all of the parties hereto. |
11.6 | Binding Effect. This Agreement will be binding on the parties and their respective successors, legal representatives and permitted assigns. In the event of a merger, consolidation, combination, dissolution or liquidation of the Company, the performance of this Agreement will be assumed by any entity which succeeds to or is transferred the business of the Company as a result thereof. |
11.7 | Attorneys Fees. If any party institutes an action, proceeding or arbitration against any other party relating to the provisions of this Agreement or any default hereunder, the Company will be responsible for paying the Companys legal fees and expenses and the Company will be required to reimburse the Executive for reasonable expenses and legal fees incurred by |
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the Executive in connection with the resolution of such action or proceeding, including any costs of appeal. |
11.8 | Supercession. This Agreement is the final, complete and exclusive expression of the agreement between the Company and the Executive and supersedes and replaces in all respects any prior employment agreements (including the Prior Agreement). On execution of this Agreement by the Company and the Executive, the relationship between the Company and the Executive after the effective date of this Agreement will be governed by the terms of this Agreement and not by any other agreements, oral or otherwise. |
IN WITNESS WHEREOF, the undersigned have executed this Agreement effective the date first above written.
CHESAPEAKE ENERGY CORPORATION, an Oklahoma corporation | ||
By: | ||
Marcus C. Rowland, Executive Vice President and Chief Financial Officer | ||
(the Company) |
By: | ||
Tom L. Ward, individually | ||
(the Executive) |
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Exhibit 12
CHEAPEAKE ENERGY CORPORATION
RATIOS OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED DIVIDENDS
(dollars in 000s)
Year Ended December 31, 1999 |
Year Ended December 31, 2000 |
Year Ended December 31, 2001 |
Year Ended December 31, 2002 |
Year Ended December 31, 2003 | |||||||||||
EARNINGS: |
|||||||||||||||
Income before income taxes and cumulative |
$ | 35,030 | $ | 196,162 | $ | 361,698 | $ | 67,140 | $ | 500,952 | |||||
Interest expense (a) |
81,052 | 86,256 | 98,321 | 111,280 | 147,817 | ||||||||||
Loss on investment in equity investees |
| | | | 409 | ||||||||||
Amortization of capitalized interest |
1,047 | 1,226 | 1,784 | 1,804 | 2,519 | ||||||||||
Bond discount amortization (c) |
| | | | | ||||||||||
Loan cost amortization |
3,338 | 3,669 | 4,022 | 4,962 | 4,254 | ||||||||||
Earnings |
$ | 120,467 | $ | 287,313 | $ | 465,825 | $ | 185,186 | $ | 655,951 | |||||
FIXED CHARGES: |
|||||||||||||||
Interest expense |
$ | 81,052 | $ | 86,256 | $ | 98,321 | $ | 111,280 | $ | 147,817 | |||||
Capitalized interest |
3,356 | 2,452 | 4,719 | 4,976 | 13,041 | ||||||||||
Bond discount amortization (c) |
| | | | | ||||||||||
Loan cost amortization |
3,338 | 3,669 | 4,022 | 4,962 | 4,254 | ||||||||||
Fixed Charges |
$ | 87,746 | $ | 92,377 | $ | 107,062 | $ | 121,218 | $ | 165,112 | |||||
Preferred Stock Dividends |
|||||||||||||||
Preferred Dividend Requirements |
$ | 16,711 | $ | 8,484 | $ | 2,050 | $ | 10,117 | $ | 22,469 | |||||
Ratio of income before provision for taxes to |
1.05 | N/A | 1.66 | 1.67 | 1.61 | ||||||||||
Subtotal Preferred Dividends |
$ | 17,597 | $ | 8,484 | $ | 3,411 | $ | 16,861 | $ | 36,240 | |||||
Combined Fixed Charges and Preferred Dividends |
$ | 105,343 | $ | 100,861 | $ | 110,473 | $ | 138,079 | $ | 201,352 | |||||
Ratio of Earnings to Fixed Charges |
1.4 | 3.1 | 4.4 | 1.5 | 4.0 | ||||||||||
Insufficient coverage |
$ | | $ | | $ | | $ | | $ | | |||||
Ratio of Earnings to Combined Fixed Charges and |
1.1 | 2.8 | 4.2 | 1.3 | 3.3 | ||||||||||
Insufficient coverage |
$ | | $ | | $ | | $ | | $ | |
(a) | Excludes the effect of unrealized gains or losses on interest rate derivatives. |
(b) | Amounts of income before provision for taxes and of net income exclude the cumulative effect of accounting change. |
(c) | Bond discount excluded since it is included in interest expense. |
Exhibit 21
SUBSIDIARIES OF CHESAPEAKE ENERGY CORPORATION
(an Oklahoma corporation)
March 10, 2004
Corporations |
State of Organization | |
Chesapeake EP Corporation |
Oklahoma | |
Chesapeake Energy Louisiana Corporation |
Oklahoma | |
Chesapeake Energy Marketing, Inc. |
Oklahoma | |
Chesapeake Operating, Inc. |
Oklahoma | |
Chesapeake Permian Acquisition, L.L.C. |
Oklahoma | |
Chesapeake PRH Corp. |
Oklahoma | |
Chesapeake South Texas Corp. |
Oklahoma | |
Nomac Drilling Corporation |
Oklahoma | |
Oxley Petroleum Co. |
Oklahoma | |
Limited Liability Companies |
State of Formation | |
The Ames Company, L.L.C. |
Oklahoma | |
Carmen Acquisition, L.L.C. |
Oklahoma | |
Chesapeake Acquisition, L.L.C. |
Oklahoma | |
Chesapeake ENO Acquisition, L.L.C. |
Oklahoma | |
Chesapeake Focus, L.L.C. |
Oklahoma | |
Chesapeake KNAN Acquisition, L.L.C. |
Oklahoma | |
Chesapeake Mountain Front, L.L.C. |
Oklahoma | |
Chesapeake ORC, L.L.C. |
Oklahoma | |
Chesapeake Royalty, L.L.C. |
Oklahoma | |
Gothic Energy, L.L.C. |
Oklahoma | |
Gothic Production, L.L.C. |
Oklahoma | |
John C. Oxley, L.L.C. |
Oklahoma | |
MC Mineral Company, L.L.C. |
Oklahoma | |
Mayfield Processing, LLC |
Oklahoma | |
Sap Acquisition, L.L.C. |
Oklahoma | |
Partnerships |
||
Chesapeake Exploration Limited Partnership |
Oklahoma | |
Chesapeake Louisiana, L.P. |
Oklahoma | |
Chesapeake Panhandle Limited Partnership |
Oklahoma | |
Chesapeake Permian, L.P. |
Oklahoma | |
Chesapeake Sigma, L.P. |
Oklahoma | |
Chesapeake-Staghorn Acquisition L.P. |
Oklahoma | |
Chesapeake Zapata, L.P. |
Oklahoma | |
MidCon Compression, L.P. |
Oklahoma |
Exhibit 23.1
CONSENT OF INDEPENDENT AUDITORS
We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (File Nos. 33-84258, 33-89282, 33-88196, 333-27525, 333-07255, 333-30324, 333-46129, 333-30478, 333-52666, 333-52668, 333-67734, 333-67736, 333-67740 and 333-109162), Form S-3 (File Nos. 333-61508, 333-76546, 333-104394 and 333-109657), and Form S-4 (File No. 333-104396) of Chesapeake Energy Corporation of our report dated February 29, 2004 relating to the consolidated financial statements and financial statement schedule, which appears in this Form 10-K.
PricewaterhouseCoopers LLP
Oklahoma City, Oklahoma
March 12, 2004
EXHIBIT 23.2
CONSENT OF RYDER SCOTT COMPANY, L.P.
As independent oil and gas consultants, Ryder Scott Company, L.P. hereby consents to the incorporation by reference in the Registration Statements on Form S-8 (File Nos. 33-84258, 33-89282, 33-88196, 333-27525, 333-07255, 333-30324, 333-46129, 333-30478, 333-52666, 333-52668, 333-67734, 333-67736, 333-67740 and 333-109162), Form S-3 (File Nos. 333-61508, 333-76546, 333-104394 and 333-109657), and Form S-4 (File No. 333-104396) of Chesapeake Energy Corporation of information from our reserve report dated February 23, 2004, entitled Estimated Future Reserves and Income Attributable to Certain Leasehold Interests (SEC Parameters) as of December 31, 2003 and all references to our firm included in or made a part of the Chesapeake Energy Corporation Annual Report on Form 10-K to be filed with the Securities and Exchange Commission on or about March 15, 2004.
RYDER SCOTT COMPANY, L.P.
Houston, Texas
March 15, 2004
EXHIBIT 23.3
CONSENT OF LEE KEELING AND ASSOCIATES, INC.
As independent oil and gas consultants, Lee Keeling and Associates, Inc. hereby consents to the incorporation by reference in the Registration Statements on Form S-8 (File Nos. 33-84258, 33-89282, 33-88196, 333-27525, 333-07255, 333-30324, 333-46129, 333-30478, 333-52666, 333-52668, 333-67734, 333-67736, 333-67740 and 333-109162), Form S-3 (File Nos. 333-61508, 333-76546, 333-104394 and 333-109657), and Form S-4 (File No. 333-104396) of Chesapeake Energy Corporation of information from our reserve report dated February 16, 2004, entitled Appraisal Oil and Gas Properties Interests Owned by Chesapeake Energy Corporation Selected Properties Constant Prices and Expenses Effective Date January 1, 2004 for disclosure to the Securities and Exchange Commission, and all references to our firm included in or made a part of the Chesapeake Energy Corporation Annual Report on Form 10-K to be filed with the Securities and Exchange Commission on or about March 15, 2004.
LEE KEELING AND ASSOCIATES, INC.
By:
Kenneth Renberg, Vice President
Tulsa, Oklahoma
March 15, 2004
EXHIBIT 23.4
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS
As independent oil and gas consultants, Netherland, Sewell & Associates, Inc. hereby consents to the incorporation by reference in the Registration Statements on Form S-8 (File Nos. 33-84258, 33-89282, 33-88196, 333-27525, 333-07255, 333-30324, 333-46129, 333-30478, 333-52666, 333-52668, 333-67734, 333-67736, 333-67740 and 333-109162), Form S-3 (File Nos. 333-61508, 333-76546, 333-104394 and 333-109657), and Form S-4 (File No. 333-104396) of Chesapeake Energy Corporation of information from our reserve report dated on or about February 17, 2004, entitled Estimate of Reserves and Future Revenue to the Chesapeake Energy Corporation Interest in Certain Oil and Gas Properties located in Oklahoma and Texas as of December 31, 2003, Based on Constant Prices and Costs in accordance with Securities and Exchange Commission Guidelines and all references to our firm included in or made a part of the Chesapeake Energy Corporation Annual Report on Form 10-K to be filed with the Securities and Exchange Commission on or about March 15, 2004.
NETHERLAND, SEWELL & ASSOCIATES, INC. | ||
By: |
| |
Frederic D. Sewell Chairman and Chief Executive Officer |
Dallas, Texas
March 15, 2004
Exhibits 31.1
CERTIFICATION
I, Aubrey K. McClendon, certify that:
1. I have reviewed this annual report on Form 10-K of Chesapeake Energy Corporation;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrants other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
(a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b) evaluated the effectiveness of the registrants disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(c) disclosed in this report any change is the registrants internal control over financial reporting that occurred during the registrants most recent fiscal quarter (the registrants fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to affect, the registrants internal control over financial reporting; and
5. The registrants other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrants auditors and the audit committee of the registrants board of directors (or persons performing the equivalent functions):
(a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrants ability to record, process, summarize and report financial information; and
(b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrants internal control over financial reporting.
Date: March 15, 2004 |
By: |
/s/ AUBREY K. MCCLENDON | ||
Aubrey K. McClendon Chairman and Chief Executive Officer |
Exhibit 31.2
CERTIFICATION
I, Marcus C. Rowland, certify that:
1. I have reviewed this report on Form 10-K of Chesapeake Energy Corporation;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrants other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
(a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b) evaluated the effectiveness of the registrants disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(c) disclosed in this report any change is the registrants internal control over financial reporting that occurred during the registrants most recent fiscal quarter (the registrants fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to affect, the registrants internal control over financial reporting; and
5. The registrants other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrants auditors and the audit committee of the registrants board of directors (or persons performing the equivalent functions):
(a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrants ability to record, process, summarize and report financial information; and
(b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrants internal control over financial reporting.
Date: March 15, 2004 |
By: |
/s/ MARCUS C. ROWLAND | ||
Marcus C. Rowland Executive Vice President and Chief Financial Officer |
Exhibit 32.1
CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO SECTION 906
OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Annual Report of Chesapeake Energy Corporation (the Company) on Form 10-K for the period ended December 31, 2003 as filed with the Securities and Exchange Commission on the date hereof (the Report), I, Aubrey K. McClendon, Chairman and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:
1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
/s/ AUBREY K. MCCLENDON |
Aubrey K. McClendon Chairman and Chief Executive Officer |
Date: March 15, 2004
Exhibit 32.2
CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO SECTION 906
OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Annual Report of Chesapeake Energy Corporation (the Company) on Form 10-K for the period ended December 31, 2003 as filed with the Securities and Exchange Commission on the date hereof (the Report), I, Marcus C. Rowland, Executive Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:
1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
/s/ MARCUS C. ROWLAND |
Marcus C. Rowland Executive Vice President and Chief Financial Officer |
Date: March 15, 2004