UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
Securities Exchange Act of 1934
Date of Report (Date of earliest event reported): February 27, 2019
CHESAPEAKE ENERGY CORPORATION | |||||||
(Exact name of Registrant as specified in its Charter) | |||||||
Oklahoma | 1-13726 | 73-1395733 | |||||
(State or other jurisdiction of incorporation) | (Commission File No.) | (IRS Employer Identification No.) | |||||
6100 North Western Avenue, Oklahoma City, Oklahoma | 73118 | ||||||
(Address of principal executive offices) | (Zip Code) | ||||||
(405) 848-8000 | |||||||
(Registrant’s telephone number, including area code) | |||||||
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):
o | Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425) | |
o | Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12) | |
o | Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b)) | |
o | Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c)) | |
Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§ 230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§ 240.12b-2 of this chapter). | ||
Emerging growth company | o | |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. | o | |
Item 2.02 Results of Operations and Financial Condition.
On February 27, 2019, Chesapeake Energy Corporation issued a press release reporting fourth quarter and full year 2018 financial and operational results and its 2019 outlook and capital expenditure program. A copy of the press release is attached as Exhibit 99.1 to this Current Report on Form 8-K.
The information in the press release is being furnished, not filed, pursuant to Item 2.02. Accordingly, the information in the press release will not be incorporated by reference into any registration statement filed by Chesapeake Energy Corporation under the Securities Act of 1933, as amended, except as set forth by specific reference in such filing.
Item 7.01 Regulation FD Disclosure.
On February 27, 2019, Chesapeake Energy Corporation will make a presentation about its financial and operating results for the fourth quarter and full year 2018 and its 2019 outlook and capital expenditure program, as noted in the press release described in Item 2.02 above. Chesapeake has made the presentation available on its website at http://www.chk.com/investors/presentations.
This information is being furnished, not filed, pursuant to Item 7.01. Accordingly, this information will not be incorporated by reference into any registration statement filed by Chesapeake Energy Corporation under the Securities Act of 1933, as amended, except as set forth by specific reference in such filing.
Item 9.01 Exhibits.
(d)
Exhibit No. | Document Description | |
Chesapeake Energy Corporation press release dated February 27, 2019 | ||
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
CHESAPEAKE ENERGY CORPORATION | |
By: | /s/ JAMES R. WEBB |
James R. Webb | |
Executive Vice President - General Counsel and Corporate Secretary | |
Date: February 27, 2019
Exhibit 99.1 | |
N E W S R E L E A S E |  |
FOR IMMEDIATE RELEASE
FEBRUARY 27, 2019
CHESAPEAKE ENERGY CORPORATION REPORTS 2018 FULL YEAR AND FOURTH QUARTER RESULTS AND ANNOUNCES 2019 GUIDANCE
OKLAHOMA CITY, February 27, 2019 – Chesapeake Energy Corporation (NYSE:CHK) today reported financial and operational results for the 2018 full year and fourth quarter. Highlights include:
2018 Results:
• | Portfolio evolution drives improved returns and leverage reduction: Divested lower-margin Utica and Mid-Continent assets and expanded higher-margin oil growth platform through strategic focus on the Powder River Basin (PRB) and announcement of the acquisition of WildHorse Resource Development Corporation (WildHorse); overall total debt reduction of $1.8 billion as of December 31, 2018, including the elimination of $2.6 billion in secured debt; |
• | Oil production growth: 2018 average daily oil production of approximately 90,000 barrels (bbls), up 10 percent compared to 2017 levels, adjusted for asset sales; December 2018 oil production equaled 21 percent of total production mix; |
• | Highest margins since 2014: 2018 net income available to common stockholders of $775 million, or $0.85 per diluted share; 2018 adjusted net income attributable to Chesapeake of $816 million, or $0.90 per diluted share; 2018 fourth quarter net income available to common stockholders of $486 million, or $0.49 per diluted share; 2018 fourth quarter adjusted net income attributable to Chesapeake of $238 million, or $0.21 per diluted share; highest adjusted EBITDA generated per barrel of oil equivalent (boe) of $12.81 since 2014. |
2019 Outlook:
• | Transformational oil growth: Projected 2019 average daily oil production of approximately 116,000 to 122,000 bbls, an absolute increase of approximately 32 percent (or 50 percent adjusted for asset sales), driven by the acquisition of the WildHorse asset and organic growth from the PRB; oil mix projected to be approximately 26 percent by 2019 fourth quarter; |
• | Capital expenditure program discipline: Projected 2019 capital expenditures range from $2.3 to $2.5 billion, effectively flat compared to $2.366 billion in 2018; |
• | Lower costs lead to improved capital efficiency and enhanced competitiveness: Cash costs projected to decrease by approximately $200 million, driven by lower gathering, processing and transportation (GP&T) expenses partially offset by slightly higher production and general and administrative expenses as a result of production and working interest mix; EBITDA generated per boe projected to increase by approximately 12 to 15 percent, based on recent strip prices. |
Doug Lawler, Chesapeake’s President and Chief Executive Officer, commented, “I am very pleased with Chesapeake’s operational and financial performance in 2018. Two transformational business transactions not only serve as a significant inflection point for the company, but also provide foundational support in our strategic goals of further reducing our net debt, achieving sustainable positive free cash flow, and enhancing margins. The recent acquisition of WildHorse, which we refer to as our Brazos Valley business unit, provides significant profitability, flexibility and optionality to our diverse, deep asset portfolio and facilitates our achieving these strategic goals.
INVESTOR CONTACT: | MEDIA CONTACT: | CHESAPEAKE ENERGY CORPORATION |
Brad Sylvester, CFA (405) 935-8870 ir@chk.com | Gordon Pennoyer (405) 935-8878 media@chk.com | 6100 North Western Avenue P.O. Box 18496 Oklahoma City, OK 73154 |
“Over the past five years, we have clearly established our operational and capital efficiency leadership. We have also materially improved our financial leverage and significantly reduced our obligations, commitments and complexity. Our 2018 accomplishments of 10 percent adjusted oil growth, improved realizations and lower absolute cash costs compared to 2017 resulted in the highest EBITDA generated per boe for Chesapeake since 2014, when oil averaged more than $90 per barrel and gas averaged more than $4 per thousand cubic feet. Our strategic focus on increasing our oil production is working, as we increased annual net oil volumes from the PRB by 78 percent in 2018, resulting in oil production representing 21 percent of our overall production mix in December. Our oil focus will be fully evident in 2019, as annual net oil volumes from the PRB are expected to more than double compared to 2018 and as we begin a robust drilling program on our Brazos Valley asset, while also attacking the base production in all our operating areas with full-field optimization and downtime reduction programs. As a result, we project our average oil mix to be approximately 24 percent of total volumes in 2019 compared to 17 percent in 2018, with our year-end 2019 oil mix approaching 26 percent.
“We are off to a fast start in 2019. With the integration of the Brazos Valley asset into Chesapeake fully underway, we are already seeing a significant amount of cost savings to be captured and strong performance from the asset. The Brazos Valley asset had very strong 2018 fourth quarter performance, with production, capital expenditures and cash flow better than we had originally projected at the time of the acquisition announcement.
“At today’s strip pricing, we expect our cash flow to be meaningfully stronger in 2019, as we continue to leverage our strength in capital efficiency and cash cost leadership. Chesapeake’s progress, portfolio and strategic plan provides a compelling investment opportunity and we look forward to driving differential value for our shareholders in the year ahead.”
2018 Full Year Results
For the 2018 full year, Chesapeake reported net income of $877 million and net income available to common stockholders of $775 million, or $0.85 per diluted share, compared to $953 million, $813 million, and $0.90 in 2017, respectively. The company's EBITDA for the 2018 full year was $2.499 billion, compared to $2.376 billion in 2017. Adjusting for items that are typically excluded by securities analysts, the 2018 full year adjusted net income attributable to Chesapeake was $816 million, or $0.90 per diluted share, compared to $742 million, or $0.82 per diluted share in 2017, while the company's adjusted EBITDA was $2.436 billion, compared to $2.160 billion in 2017. Reconciliations of financial measures calculated in accordance with GAAP to non-GAAP measures are provided on pages 14 - 17 of this release.
Average daily production for 2018 of approximately 521,000 boe increased by 4 percent compared to 2017 levels, adjusted for asset sales, and consisted of approximately 90,000 bbls of oil, 2.278 billion cubic feet (bcf) of natural gas and 52,000 bbls of NGL.
Production expenses in 2018 were $2.84 per boe, compared to $2.81 per boe in 2017. The per unit increase was the result of increased ad valorem tax primarily due to higher prices received for the company’s oil, natural gas and NGL production. General and administrative expenses (including stock-based compensation) in 2018 were $1.47 per boe, compared to $1.31 per boe in 2017. The increase was primarily due to less overhead allocated to production expenses, marketing expenses and capitalized general and administrative costs, as well as less overhead billed to working interest owners, due to certain divestitures in 2018 and 2017.
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2018 Fourth Quarter Results
For the 2018 fourth quarter, Chesapeake reported net income of $514 million and net income available to common stockholders of $486 million, or $0.49 per diluted share, compared to $334 million, $309 million, and $0.33 in the 2017 fourth quarter, respectively. The company's EBITDA for the 2018 fourth quarter was $910 million, compared to $764 million in the 2017 fourth quarter. Adjusting for items that are typically excluded by securities analysts, the 2018 fourth quarter adjusted net income attributable to Chesapeake was $238 million, or $0.21 per diluted share, compared to $314 million, or $0.30 per diluted share in the 2017 fourth quarter. The company's adjusted EBITDA was $574 million in the fourth quarter of 2018, compared to $706 million in the fourth quarter of 2017. Reconciliations of financial measures calculated in accordance with GAAP to non-GAAP measures are provided on pages 14 - 17 of this release.
Average daily production for the 2018 fourth quarter was approximately 464,000 boe, a 7 percent decrease compared to 2017 levels, adjusted for asset sales, and consisted of approximately 87,000 bbls of oil, 2.009 bcf of natural gas and 42,000 bbls of NGL.
Production expenses during the 2018 fourth quarter were $2.87 per boe, compared to $2.50 per boe in the 2017 fourth quarter. The increase was primarily a result of certain 2018 and 2017 divestitures and increased ad valorem tax due to higher prices received for the company’s oil, natural gas and NGL production. General and administrative expenses (including stock-based compensation) during the 2018 fourth quarter were $1.19 per boe, compared to $1.34 per boe in the 2017 fourth quarter. The decrease was primarily due to lower compensation expenses, partially offset by less overhead allocated to production expenses, marketing expenses and capitalized general and administrative costs. The company’s GP&T expenses increased to $7.92 per boe from $7.15 per boe during the 2017 fourth quarter, primarily due to a shortfall payment for Eagle Ford oil transportation volumes.
Capital Spending Overview
Chesapeake’s total capital investments were approximately $541 million during the 2018 fourth quarter and $2.366 billion during the 2018 full year, compared to approximately $523 million and $2.458 billion in the 2017 fourth quarter and 2017 full year, respectively. A summary of the company’s 2018 and 2017 capital expenditures, as well as the current 2019 capital expenditure guidance, is provided in the table below.
2017 | 2018 | 2019 | |||||||||||
Operated activity comparison | Q4 | FY | Q4 | FY | Outlook | ||||||||
Average rig count | 14 | 17 | 18 | 17 | 18 - 19 | ||||||||
Gross wells spud | 66 | 341 | 82 | 322 | 350 - 360 | ||||||||
Gross wells completed | 102 | 401 | 107 | 351 | 370 - 380 | ||||||||
Gross wells connected | 118 | 411 | 119 | 347 | 365 - 375 | ||||||||
Type of cost ($ in millions) | |||||||||||||
Drilling and completion costs | $ | 462 | $ | 2,190 | $ | 470 | $ | 2,086 | $2,050 - $2,250 | ||||
Exploration costs, leasehold and additions to other PP&E | 15 | 74 | 37 | 117 | 125 | ||||||||
Subtotal capital expenditures | $ | 477 | $ | 2,264 | $ | 507 | $ | 2,203 | $2,175 - $2,375 | ||||
Capitalized interest | 46 | 194 | 34 | 163 | 125 | ||||||||
Total capital expenditures | $ | 523 | $ | 2,458 | $ | 541 | $ | 2,366 | $2,300 - $2,500 | ||||
Balance Sheet and Hedge Position Update
As of December 31, 2018, Chesapeake’s principal amount of debt outstanding was approximately $8.168 billion, compared to $9.981 billion as of December 31, 2017, including $419 million drawn under its senior secured revolving bank credit facility. As of December 31, 2018, Chesapeake had utilized approximately
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$107 million for various letters of credit and had borrowing capacity of approximately $2.474 billion under the $3.0 billion Chesapeake senior secured revolving credit facility.
On February 1, 2019, Chesapeake acquired approximately $1.4 billion principal amount of debt upon the closing of the Brazos Valley asset (including $675 million drawn under the Brazos Valley senior secured revolving credit facility). The company had approximately $47 million of letters of credit issued and borrowing capacity of approximately $578 million under the $1.3 billion Brazos Valley senior secured revolving credit facility.
Chesapeake has a robust hedge portfolio in place for 2019 to prudently reduce its future revenue risk. As of February 22, 2019, including January and February derivative contracts that have settled, approximately 63 percent of the company's 2019 forecasted oil, natural gas and NGL production revenue was hedged, including approximately 56 percent and 81 percent of its 2019 forecasted oil and natural gas production (including Brazos Valley production from February 1, 2019) at average prices of $57.12 per bbl and $2.85 per thousand cubic feet (mcf), respectively. Additionally, Chesapeake has basis protection on approximately 7 million barrels (mmbbls) of its projected 2019 Eagle Ford oil production at a premium to WTI of approximately $6.01 per bbl.
Operations Update
Chesapeake's average daily production for the 2018 full year was approximately 521,000 boe compared to approximately 548,000 boe in the 2017 full year. A summary of the company's 2018 average daily production and average daily sales prices received by operating divisions can be found in the company's Form 10-K.
Chesapeake's average daily production for the 2018 fourth quarter was approximately 464,000 boe compared to approximately 593,000 boe in the 2017 fourth quarter. The following table shows average daily production and average daily sales prices received by the company's operating divisions for the 2018 fourth quarter and the 2017 fourth quarter.
Three Months Ended December 31, 2018 | |||||||||||||||||||||||||||
Oil | Natural Gas | NGL | Total | ||||||||||||||||||||||||
mbbl per day | $/bbl | mmcf per day | $/mcf | mbbl per day | $/bbl | mboe per day | % | $/boe | |||||||||||||||||||
Marcellus | — | — | 821 | 3.68 | — | — | 137 | 29 | 22.09 | ||||||||||||||||||
Haynesville | — | — | 725 | 3.50 | — | — | 121 | 26 | 21.02 | ||||||||||||||||||
Eagle Ford | 61 | 65.16 | 142 | 4.03 | 21 | 21.87 | 105 | 23 | 47.45 | ||||||||||||||||||
Mid-Continent | 9 | 57.84 | 65 | 3.50 | 5 | 26.03 | 25 | 5 | 35.74 | ||||||||||||||||||
Powder River Basin | 14 | 56.01 | 78 | 3.86 | 4 | 23.82 | 31 | 7 | 37.94 | ||||||||||||||||||
Retained assets | 84 | 62.84 | 1,831 | 3.64 | 30 | 22.85 | 419 | 90 | % | 30.14 | |||||||||||||||||
Divested assets | 3 | 67.45 | 178 | 3.12 | 12 | 30.44 | 45 | 10 | 24.92 | ||||||||||||||||||
Total | 87 | 62.98 | 2,009 | 3.59 | 42 | 25.11 | 464 | 100 | % | 29.64 | |||||||||||||||||
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Three Months Ended December 31, 2017 | |||||||||||||||||||||||||||
Oil | Natural Gas | NGL | Total | ||||||||||||||||||||||||
mbbl per day | $/bbl | mmcf per day | $/mcf | mbbl per day | $/bbl | mboe per day | % | $/boe | |||||||||||||||||||
Marcellus | — | — | 829 | 2.22 | — | — | 138 | 23 | 13.31 | ||||||||||||||||||
Haynesville | — | — | 923 | 2.73 | — | — | 154 | 26 | 16.37 | ||||||||||||||||||
Eagle Ford | 66 | 59.62 | 150 | 3.12 | 21 | 27.09 | 112 | 19 | 44.38 | ||||||||||||||||||
Mid-Continent | 9 | 53.98 | 79 | 2.52 | 6 | 26.75 | 28 | 5 | 30.46 | ||||||||||||||||||
Powder River Basin | 7 | 54.35 | 45 | 2.90 | 3 | 33.30 | 18 | 3 | 34.82 | ||||||||||||||||||
Retained assets | 82 | 58.52 | 2,026 | 2.54 | 30 | 27.72 | 450 | 76 | % | 24.02 | |||||||||||||||||
Divested assets | 18 | 52.25 | 577 | 2.66 | 30 | 29.36 | 143 | 24 | % | 23.16 | |||||||||||||||||
Total | 100 | 57.42 | 2,603 | 2.57 | 60 | 28.53 | 593 | 100 | % | 23.81 | |||||||||||||||||
In the PRB, average daily net production increased approximately 70 percent in 2018 to 25,100 boe compared to 14,800 boe in 2017, as total net annual production increased to 9.2 million barrels of oil equivalent (mmboe) from 5.4 mmboe in 2017. Currently, the company expects total net annual production from the PRB to double in 2019 compared to 2018.
Chesapeake is operating five rigs in the PRB, all of which are currently drilling the Turner formation. Several records were achieved in the PRB during the 2018 fourth quarter, including the fastest per lateral foot drilling time in the Turner formation from spud to total depth of 18.5 days for the BB 2-35-71 USA A TR 18H well with a drilled lateral length of approximately 10,100 feet. Chesapeake also recorded its highest producing oil well to date, including the SFU 7-34-71 USA A TR 20H well which was placed on production in November 2018 and recorded a 24-hour oil volume of 2,387 bbls (78 percent oil, or 3,068 boe).
In 2019, Chesapeake is moving to development mode in the Turner formation, moving to central production facilities which will handle up to 30,000 bbls of oil per day, consolidating drilling activity to the more economic oil window located primarily in the northern and western part of the play where there tends to be lower gas-to-oil ratios. As a result, the company expects to double its oil production from the PRB in 2019 by placing up to 64 Turner wells on production, compared to 32 Turner wells in 2018 and its first three wells drilled in the formation in 2017. While the primary focus of the 2019 PRB program will be on the Turner formation, the team will continue appraisal work on the Niobrara and other horizons across the basin.
Driven by the increase in oil volumes the company is projecting going forward, Chesapeake signed an oil gathering agreement during the 2018 fourth quarter that will deliver its oil volumes via pipelines into the Guernsey, Wyoming market at a substantially lower cost than the company was incurring by trucking volumes. This oil gathering system will also connect directly to interstate pipelines with available capacity to the Cushing, Oklahoma market and further to Gulf Coast premium markets, providing additional takeaway options to Chesapeake in the future as basin production grows.
In the company’s legacy Eagle Ford Shale position in south Texas, Chesapeake is currently utilizing four drilling rigs and expects to place on production up to 125 wells in 2019, compared to 157 wells in 2018. Of the wells planned for 2019, Chesapeake expects to test up to 10 Upper Eagle Ford and Austin Chalk wells. The company continues to focus on its base production and has implemented new field technologies to reduce downtime across the field. As a result, Chesapeake recorded a 17 percent reduction in controllable down volumes per day in 2018, which equated to an additional 1,100 barrels of oil sold every day. The company's significantly higher margins in the Eagle Ford are primarily driven by premium Gulf Coast crude oil pricing and are further protected with basis hedges on approximately 7 mmbbls of projected 2019 Eagle Ford oil production at a premium to WTI of approximately $6.00 per bbl.
The company’s Brazos Valley business unit will be focused on targeting both Eagle Ford and Austin Chalk wells in the large acreage position gained in the WildHorse acquisition. Chesapeake will operate four rigs in the Brazos Valley area in 2019 and expects to place on production up to 83 wells, including 10 wells targeting the Austin Chalk formation, with average completed lateral lengths of approximately 8,000 feet. The business unit is aggressively attacking numerous opportunities to drive capital efficiencies across all
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areas of the value chain. Through a combination of operational improvements and supply chain savings, the team has implemented and negotiated approximately $200,000 to $350,000 per well in capital savings within the first month of taking over operations. Early cycle time improvements have been recognized through increased drilling penetration rates and a two stage per day increase by the completions team. Additionally, the Burleson Sand Mine commenced operations in February 2019 and is anticipated to yield additional savings to the company's completions program.
In the Marcellus Shale in northeast Pennsylvania, Chesapeake is currently utilizing three drilling rigs and expects to place on production up to 48 wells in 2019, compared to 54 wells in 2018. Chesapeake projects to again create significant free cash flow in 2019 as stronger realized in-basin gas prices are expected to continue. Current total gross production from the region is approximately 2.4 bcf per day, after reaching a record 2.5 bcf per day in January 2019. In February 2019, Chesapeake placed two Upper Marcellus wells on production in Susquehanna County that reached a combined peak 24-hour rate of approximately 60 million cubic feet (mmcf) of gas per day. Of the company's 48 wells expected to be placed on production in 2019, seven wells will target the Upper Marcellus formation.
In the company’s Haynesville Shale position in Louisiana, Chesapeake is currently utilizing two drilling rigs and intends to drop to one rig in the 2019 second quarter. The company expects to place on production up to 24 wells in 2019, compared to 26 wells in 2018.
In the company's Mid-Continent operating area in Oklahoma, Chesapeake is currently utilizing one drilling rig and expects to place on production 25 wells in 2019, compared to 38 wells in 2018.
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Key Financial and Operational Results
The table below summarizes Chesapeake’s key financial and operational results during the 2018 fourth quarter and full year as compared to results in prior periods.
Three Months Ended December 31, | Years Ended December 31, | ||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||
Barrels of oil equivalent production (in mboe) | 42,711 | 54,572 | 190,266 | 199,933 | |||||||
Barrels of oil equivalent production (mboe/d) | 464 | 593 | 521 | 548 | |||||||
Oil production (in mbbl/d) | 87 | 100 | 90 | 90 | |||||||
Average realized oil price ($/bbl)(a) | 56.86 | 56.47 | 57.42 | 53.19 | |||||||
Natural gas production (in mmcf/d) | 2,009 | 2,603 | 2,278 | 2,406 | |||||||
Average realized natural gas price ($/mcf)(a) | 3.19 | 2.76 | 3.00 | 2.75 | |||||||
NGL production (in mbbl/d) | 42 | 59 | 52 | 57 | |||||||
Average realized NGL price ($/bbl)(a) | 25.36 | 27.98 | 25.84 | 22.98 | |||||||
Production expenses ($/boe) | 2.87 | 2.50 | 2.84 | 2.81 | |||||||
Gathering, processing and transportation expenses ($/boe) | 7.92 | 7.15 | 7.35 | 7.36 | |||||||
Oil - ($/bbl) | 6.02 | 3.90 | 4.30 | 3.94 | |||||||
Natural Gas - ($/mcf) | 1.41 | 1.30 | 1.32 | 1.34 | |||||||
NGL - ($/bbl) | 7.40 | 7.83 | 8.37 | 7.88 | |||||||
Production taxes ($/boe) | 0.77 | 0.45 | 0.65 | 0.44 | |||||||
General and administrative expenses ($/boe)(b) | 1.04 | 1.19 | 1.32 | 1.13 | |||||||
General and administrative expenses (stock-based compensation) (non-cash) ($/boe) | 0.15 | 0.15 | 0.15 | 0.18 | |||||||
Depreciation, depletion and amortization ($/boe) | 6.52 | 5.60 | 6.02 | 4.98 | |||||||
Interest expense ($/boe)(a) | 2.78 | 2.25 | 2.55 | 2.11 | |||||||
Marketing net margin ($ in millions) (c) | (18 | ) | 1 | (63 | ) | (65 | ) | ||||
Net cash provided by operating activities ($ in millions) | 405 | 472 | 2,000 | 745 | |||||||
Net cash provided by operating activities ($/boe) | 9.47 | 8.65 | 10.51 | 3.73 | |||||||
Operating cash flow ($ in millions)(d) | 367 | 577 | 1,846 | 1,216 | |||||||
Operating cash flow ($/boe) | 8.59 | 10.57 | 9.70 | 6.09 | |||||||
Net income ($ in millions) | 514 | 334 | 877 | 953 | |||||||
Net income available to common stockholders ($ in millions) | 486 | 309 | 775 | 813 | |||||||
Net income per share available to common stockholders – diluted ($) | 0.49 | 0.33 | 0.85 | 0.90 | |||||||
Adjusted EBITDA ($ in millions)(e) | 574 | 706 | 2,436 | 2,160 | |||||||
Adjusted EBITDA ($/boe) | 13.43 | 12.94 | 12.81 | 10.80 | |||||||
Adjusted net income attributable to Chesapeake ($ in millions)(f) | 238 | 314 | 816 | 742 | |||||||
Adjusted net income attributable to Chesapeake per share - diluted ($ in millions)(g) | 0.21 | 0.30 | 0.90 | 0.82 | |||||||
(a) | Includes the effects of realized gains (losses) from hedging, but excludes the effects of unrealized gains (losses) from hedging. |
(b) | Excludes expenses associated with stock-based compensation, which are recorded in general and administrative expenses in Chesapeake's Condensed Consolidated Statement of Operations. |
(c) | Excludes non-cash amortization of $5 million for the three months ended December 31, 2018 and 2017, and $19 million and $22 million for the year ended December 31, 2018 and 2017, respectively. |
(d) | Defined as cash flow provided by operating activities before changes in components of working capital and other assets and liabilities. This is a non-GAAP measure. See reconciliation to cash provided by operating activities on page 16. |
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(e) | Defined as net income before interest expense, income taxes and depreciation, depletion and amortization expense, as adjusted to remove the effects of certain items detailed on page 17. This is a non-GAAP measure. See reconciliation of net income to EBITDA on page 16 and reconciliation of EBITDA to adjusted EBITDA on page 17. |
(f) | Defined as net income attributable to Chesapeake, as adjusted to remove the effects of certain items detailed on pages 14 - 15. This is a non-GAAP measure. See reconciliation of net income to adjusted net income available to Chesapeake on pages 14 - 15. |
(g) | Our presentation of diluted adjusted net income attributable to Chesapeake per share excludes 1 million and 60 million shares for the three months ended December 31, 2018 and 2017, respectively, and 207 million shares for the years ended December 31, 2018 and 2017, considered antidilutive when calculating diluted earnings per share. |
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2018 Fourth Quarter and Year-End Results Conference Call Information
A conference call to discuss this release has been scheduled on Wednesday, February 27, 2019 at 9:00 am EST. The telephone number to access the conference call is 334-323-0522 or toll-free 877-260-1479. The passcode for the call is 1327759. The number to access the conference call replay is 719-457-0820 or toll-free 888-203-1112 and the passcode for the replay is 1327759. The conference call will be webcast and can be found at www.chk.com in the “Investors” section of the company’s website. The webcast of the conference will be available on the website for one year.
Headquartered in Oklahoma City, Chesapeake Energy Corporation's (NYSE: CHK) operations are focused on discovering and developing its large and geographically diverse resource base of unconventional oil and natural gas assets onshore in the United States.
This news release and the accompanying Outlook include "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 are statements other than statements of historical fact. They include statements that give our current expectations, management's outlook guidance or forecasts of future events, production and well connection forecasts, estimates of operating costs, anticipated capital and operational efficiencies, planned development drilling and expected drilling cost reductions, anticipated timing of wells to be placed into production, general and administrative expenses, capital expenditures, the timing of anticipated asset sales and proceeds to be received therefrom, the expected use of proceeds of anticipated asset sales, projected cash flow and liquidity, our ability to enhance our cash flow and financial flexibility, plans and objectives for future operations, the ability of our employees, portfolio strength and operational leadership to create long-term value, and the assumptions on which such statements are based. Although we believe the expectations and forecasts reflected in the forward-looking statements are reasonable, we can give no assurance they will prove to have been correct. They can be affected by inaccurate or changed assumptions or by known or unknown risks and uncertainties.
Factors that could cause actual results to differ materially from expected results include those described under "Risk Factors” in Item 1A of our annual report on Form 10-K and any updates to those factors set forth in Chesapeake's subsequent quarterly reports on Form 10-Q or current reports on Form 8-K (available at http://www.chk.com/investors/sec-filings). These risk factors include the volatility of oil, natural gas and NGL prices; the limitations our level of indebtedness may have on our financial flexibility; our inability to access the capital markets on favorable terms; the availability of cash flows from operations and other funds to finance reserve replacement costs or satisfy our debt obligations; downgrade in our credit rating requiring us to post more collateral under certain commercial arrangements; write-downs of our oil and natural gas asset carrying values due to low commodity prices; our ability to replace reserves and sustain production; uncertainties inherent in estimating quantities of oil, natural gas and NGL reserves and projecting future rates of production and the amount and timing of development expenditures; our ability to generate profits or achieve targeted results in drilling and well operations; leasehold terms expiring before production can be established; commodity derivative activities resulting in lower prices realized on oil, natural gas and NGL sales; the need to secure derivative liabilities and the inability of counterparties to satisfy their obligations; adverse developments or losses from pending or future litigation and regulatory proceedings, including royalty claims; charges incurred in response to market conditions and in connection with our ongoing actions to reduce financial leverage and complexity; drilling and operating risks and resulting liabilities; effects of environmental protection laws and regulation on our business; legislative and regulatory initiatives further regulating hydraulic fracturing; our need to secure adequate supplies of water for our drilling operations and to dispose of or recycle the water used; impacts of potential legislative and regulatory actions addressing climate change; federal and state tax proposals affecting our industry; potential OTC derivatives regulation limiting our ability to hedge against commodity price fluctuations; competition in the oil and gas exploration and production industry; a deterioration in general economic, business or industry conditions; negative public perceptions of our industry; limited control over properties we do not operate; pipeline and gathering system capacity constraints and transportation interruptions; terrorist activities and cyber-attacks adversely impacting our operations; an interruption in operations at our headquarters due to a catastrophic event; certain anti-takeover provisions that affect shareholder rights; and our inability to increase or maintain our liquidity through debt repurchases, capital exchanges, asset sales, joint ventures, farmouts or other means.
In addition, disclosures concerning the estimated contribution of derivative contracts to our future results of operations are based upon market information as of a specific date. These market prices are subject to significant volatility. Our production forecasts are also dependent upon many assumptions, including estimates of production decline rates from existing wells and the outcome of future drilling activity. Expected asset sales may not be completed in the time frame anticipated or at all. We caution you not to place undue reliance on our forward-looking statements, which speak only as of the date of this news release, and we undertake no obligation to update any of the information provided in this release or the accompanying Outlook, except as required by applicable law. In addition, this news release contains time-sensitive information that reflects management's best judgment only as of the date of this news release.
9
CHESAPEAKE ENERGY CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS ($ in millions except per share data) (unaudited) | |||||||||||||||
Three Months Ended December 31, | Years Ended December 31, | ||||||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||||||
REVENUES: | |||||||||||||||
Oil, natural gas and NGL | $ | 1,731 | $ | 1,258 | $ | 5,155 | $ | 4,985 | |||||||
Marketing | 1,338 | 1,261 | 5,076 | 4,511 | |||||||||||
Total Revenues | 3,069 | 2,519 | 10,231 | 9,496 | |||||||||||
OPERATING EXPENSES: | |||||||||||||||
Oil, natural gas and NGL production | 122 | 136 | 539 | 562 | |||||||||||
Oil, natural gas and NGL gathering, processing and transportation | 338 | 390 | 1,398 | 1,471 | |||||||||||
Production taxes | 33 | 25 | 124 | 89 | |||||||||||
Marketing | 1,360 | 1,265 | 5,158 | 4,598 | |||||||||||
General and administrative | 51 | 73 | 280 | 262 | |||||||||||
Restructuring and other termination costs | — | — | 38 | — | |||||||||||
Provision for legal contingencies, net | 9 | (73 | ) | 26 | (38 | ) | |||||||||
Depreciation, depletion and amortization | 278 | 306 | 1,145 | 995 | |||||||||||
Loss on sale of oil and natural gas properties | 578 | — | 578 | — | |||||||||||
Impairments | 2 | 2 | 53 | 5 | |||||||||||
Other operating (income) expense | 4 | (10 | ) | 10 | 413 | ||||||||||
Total Operating Expenses | 2,775 | 2,114 | 9,349 | 8,357 | |||||||||||
INCOME FROM OPERATIONS | 294 | 405 | 882 | 1,139 | |||||||||||
OTHER INCOME (EXPENSE): | |||||||||||||||
Interest expense | (120 | ) | (124 | ) | (487 | ) | (426 | ) | |||||||
Gains on investments | — | — | 139 | — | |||||||||||
Gains on purchases or exchanges of debt | 331 | 50 | 263 | 233 | |||||||||||
Other income | 7 | 3 | 70 | 9 | |||||||||||
Total Other Income (Expense) | 218 | (71 | ) | (15 | ) | (184 | ) | ||||||||
INCOME BEFORE INCOME TAXES | 512 | 334 | 867 | 955 | |||||||||||
INCOME TAX EXPENSE (BENEFIT): | |||||||||||||||
Current income taxes | (2 | ) | (11 | ) | — | (9 | ) | ||||||||
Deferred income taxes | — | 11 | (10 | ) | 11 | ||||||||||
Total Income Tax Expense (Benefit) | (2 | ) | — | (10 | ) | 2 | |||||||||
NET INCOME | 514 | 334 | 877 | 953 | |||||||||||
Net income attributable to noncontrolling interests | (1 | ) | (1 | ) | (4 | ) | (4 | ) | |||||||
NET INCOME ATTRIBUTABLE TO CHESAPEAKE | 513 | 333 | 873 | 949 | |||||||||||
Preferred stock dividends | (23 | ) | (23 | ) | (92 | ) | (85 | ) | |||||||
Loss on exchange of preferred stock | — | — | — | (41 | ) | ||||||||||
Earnings allocated to participating securities | (4 | ) | (1 | ) | (6 | ) | (10 | ) | |||||||
NET INCOME AVAILABLE TO COMMON STOCKHOLDERS | $ | 486 | $ | 309 | $ | 775 | $ | 813 | |||||||
EARNINGS PER COMMON SHARE: | |||||||||||||||
Basic | $ | 0.53 | $ | 0.34 | $ | 0.85 | $ | 0.90 | |||||||
Diluted | $ | 0.49 | $ | 0.33 | $ | 0.85 | $ | 0.90 | |||||||
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions): | |||||||||||||||
Basic | 910 | 907 | 909 | 906 | |||||||||||
Diluted | 1,116 | 1,053 | 909 | 906 | |||||||||||
10
CHESAPEAKE ENERGY CORPORATION CONDENSED CONSOLIDATED BALANCE SHEETS ($ in millions) (unaudited) | |||||||
December 31, 2018 | December 31, 2017 | ||||||
Cash and cash equivalents | $ | 4 | $ | 5 | |||
Other current assets | 1,594 | 1,520 | |||||
Total Current Assets | 1,598 | 1,525 | |||||
Property and equipment, net | 9,030 | 10,680 | |||||
Other long-term assets | 319 | 220 | |||||
Total Assets | $ | 10,947 | $ | 12,425 | |||
Current liabilities | $ | 2,828 | $ | 2,356 | |||
Long-term debt, net | 7,341 | 9,921 | |||||
Other long-term liabilities | 311 | 520 | |||||
Total Liabilities | 10,480 | 12,797 | |||||
Preferred stock | 1,671 | 1,671 | |||||
Noncontrolling interests | 123 | 124 | |||||
Common stock and other stockholders’ equity (deficit) | (1,327 | ) | (2,167 | ) | |||
Total Equity (Deficit) | 467 | (372 | ) | ||||
Total Liabilities and Equity | $ | 10,947 | $ | 12,425 | |||
Common shares outstanding (in millions) | 914 | 909 | |||||
Principal amount of debt outstanding | $ | 8,168 | $ | 9,981 | |||
11
CHESAPEAKE ENERGY CORPORATION SUPPLEMENTAL DATA – OIL, NATURAL GAS AND NGL PRODUCTION, SALES AND INTEREST EXPENSE (unaudited) | |||||||||||||||
Three Months Ended December 31, | Years Ended December 31, | ||||||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||||||
Net Production: | |||||||||||||||
Oil (mmbbl) | 8 | 9 | 33 | 33 | |||||||||||
Natural gas (bcf) | 185 | 239 | 832 | 878 | |||||||||||
NGL (mmbbl) | 4 | 5 | 19 | 21 | |||||||||||
Oil equivalent (mmboe) | 43 | 55 | 190 | 200 | |||||||||||
Average daily production (mboe) | 464 | 593 | 521 | 548 | |||||||||||
Oil, Natural Gas and NGL Sales ($ in millions): | |||||||||||||||
Oil sales | $ | 503 | $ | 528 | $ | 2,201 | $ | 1,668 | |||||||
Natural gas sales | 664 | 615 | 2,486 | 2,422 | |||||||||||
NGL sales | 98 | 156 | 502 | 484 | |||||||||||
Total oil, natural gas and NGL sales | 1,265 | 1,299 | 5,189 | 4,574 | |||||||||||
Financial Derivatives: | |||||||||||||||
Oil derivatives – realized gains (losses)(a) | (48 | ) | (9 | ) | (321 | ) | 70 | ||||||||
Natural gas derivatives – realized gains (losses)(a) | (76 | ) | 44 | 7 | (9 | ) | |||||||||
NGL derivatives – realized gains (losses)(a) | 1 | (3 | ) | (13 | ) | (4 | ) | ||||||||
Total realized gains (losses) on financial derivatives | (123 | ) | 32 | (327 | ) | 57 | |||||||||
Oil derivatives – unrealized gains (losses)(a) | 560 | (179 | ) | 445 | (134 | ) | |||||||||
Natural gas derivatives – unrealized gains (losses)(a) | 14 | 105 | (154 | ) | 489 | ||||||||||
NGL derivatives – unrealized gains (losses)(a) | 15 | 1 | 2 | (1 | ) | ||||||||||
Total unrealized gains (losses) on financial derivatives | 589 | (73 | ) | 293 | 354 | ||||||||||
Total financial derivatives | 466 | (41 | ) | (34 | ) | 411 | |||||||||
Total oil, natural gas and NGL sales | $ | 1,731 | $ | 1,258 | $ | 5,155 | $ | 4,985 | |||||||
Average Sales Price (excluding gains (losses) on derivatives): | |||||||||||||||
Oil ($ per bbl) | $ | 62.98 | $ | 57.42 | $ | 67.25 | $ | 51.03 | |||||||
Natural gas ($ per mcf) | $ | 3.59 | $ | 2.57 | $ | 2.99 | $ | 2.76 | |||||||
NGL ($ per bbl) | $ | 25.11 | $ | 28.54 | $ | 26.50 | $ | 23.18 | |||||||
Oil equivalent ($ per boe) | $ | 29.64 | $ | 23.81 | $ | 27.27 | $ | 22.88 | |||||||
Average Sales Price (excluding unrealized gains (losses) on derivatives): | |||||||||||||||
Oil ($ per bbl) | $ | 56.86 | $ | 56.47 | $ | 57.42 | $ | 53.19 | |||||||
Natural gas ($ per mcf) | $ | 3.19 | $ | 2.76 | $ | 3.00 | $ | 2.75 | |||||||
NGL ($ per bbl) | $ | 25.36 | $ | 27.98 | $ | 25.84 | $ | 22.98 | |||||||
Oil equivalent ($ per boe) | $ | 26.75 | $ | 24.41 | $ | 25.56 | $ | 23.17 | |||||||
Interest Expense ($ in millions): | |||||||||||||||
Interest expense(b) | $ | 121 | $ | 123 | $ | 488 | $ | 425 | |||||||
Interest rate derivatives – realized (gains) losses(c) | (1 | ) | — | (3 | ) | (3 | ) | ||||||||
Interest rate derivatives – unrealized (gains) losses(c) | — | 1 | 2 | 4 | |||||||||||
Total interest expense | $ | 120 | $ | 124 | $ | 487 | $ | 426 | |||||||
(a) | Realized gains (losses) include the following items: (i) settlements and accruals for settlements of undesignated derivatives related to current period production revenues, (ii) prior period settlements for option premiums and for early-terminated derivatives originally scheduled to settle against current period production revenues, and (iii) gains (losses) related to de-designated cash flow hedges originally designated to settle against current period production revenues. Unrealized gains (losses) include the change in fair value of open derivatives scheduled to settle against future period production revenues (including current period settlements for option premiums and early terminated derivatives) offset by amounts reclassified as realized gains (losses) during the period. Although we no longer designate our derivatives as cash flow hedges for accounting purposes, we believe these definitions are useful to management and investors in determining the effectiveness of our price risk management program. |
(b) | Net of amounts capitalized. |
(c) | Realized (gains) losses include interest rate derivative settlements related to current period interest and the effect of (gains) losses on early-terminated trades. Settlements of early-terminated trades are reflected in realized (gains) losses over the original life of the hedged item. Unrealized (gains) losses include amounts reclassified to realized (gains) losses during the period. |
12
CHESAPEAKE ENERGY CORPORATION CONDENSED CONSOLIDATED CASH FLOW DATA ($ in millions) (unaudited) | |||||||||||||||
Three Months Ended December 31, | Years Ended December 31, | ||||||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||||||
Beginning cash and cash equivalents | $ | 4 | $ | 5 | $ | 5 | $ | 882 | |||||||
Net cash provided by operating activities | 405 | 472 | 2,000 | 745 | |||||||||||
Cash flows from investing activities: | |||||||||||||||
Drilling and completion costs(a) | (477 | ) | (589 | ) | (1,958 | ) | (2,186 | ) | |||||||
Acquisitions of proved and unproved properties(b) | (44 | ) | (59 | ) | (288 | ) | (285 | ) | |||||||
Proceeds from divestitures of proved and unproved properties | 1,836 | 56 | 2,231 | 1,249 | |||||||||||
Additions to other property and equipment | (10 | ) | (9 | ) | (21 | ) | (21 | ) | |||||||
Proceeds from sales of other property and equipment | 72 | 15 | 147 | 55 | |||||||||||
Proceeds from sales of investments | — | — | 74 | — | |||||||||||
Net cash provided by (used in) investing activities | 1,377 | (586 | ) | 185 | (1,188 | ) | |||||||||
Net cash provided by (used in) financing activities | (1,782 | ) | 114 | (2,186 | ) | (434 | ) | ||||||||
Change in cash and cash equivalents | — | — | (1 | ) | (877 | ) | |||||||||
Ending cash and cash equivalents | $ | 4 | $ | 5 | $ | 4 | $ | 5 | |||||||
(a) | Includes capitalized interest of $2 million for the three months ended December 31, 2018 and 2017. Includes capitalized interest of $9 million for the years ended December 31, 2018 and 2017. |
(b) | Includes capitalized interest of $32 million and $44 million for the three months ended December 31, 2018 and 2017, respectively. Includes capitalized interest of $153 million and $184 million for the years ended December 31, 2018 and 2017, respectively. |
13
CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF ADJUSTED NET INCOME ATTRIBUTABLE TO CHESAPEAKE ($ in millions except per share data) (unaudited) | ||||||||||||||||
Three Months Ended December 31, | ||||||||||||||||
2018 | 2017 | |||||||||||||||
$ | $/Share(a)(b) | $ | $/Share(a)(b) | |||||||||||||
Net income available to common stockholders (GAAP) | $ | 486 | $ | 0.53 | $ | 309 | $ | 0.34 | ||||||||
Effect of dilutive securities | 59 | 35 | ||||||||||||||
Diluted earnings per common stockholder (GAAP) | $ | 545 | $ | 0.49 | $ | 344 | $ | 0.33 | ||||||||
Adjustments: | ||||||||||||||||
Unrealized (gains) losses on oil, natural gas and NGL derivatives | (596 | ) | (0.53 | ) | 73 | 0.07 | ||||||||||
Provision for legal contingencies, net | 9 | 0.01 | (73 | ) | (0.07 | ) | ||||||||||
Loss on sale of oil and natural gas properties (c) | 578 | 0.52 | — | — | ||||||||||||
Impairments | 2 | — | 2 | — | ||||||||||||
Other operating (income) expense | 4 | — | (10 | ) | — | |||||||||||
Gains on purchases or exchanges of debt | (331 | ) | (0.30 | ) | (50 | ) | (0.05 | ) | ||||||||
Income tax expense (benefit)(d) | — | — | — | — | ||||||||||||
Other | — | — | 4 | — | ||||||||||||
Adjusted net income available to common stockholders(a) (b) (Non-GAAP) | 211 | 0.19 | 290 | 0.28 | ||||||||||||
Preferred stock dividends | 23 | 0.02 | 23 | 0.02 | ||||||||||||
Earnings allocated to participating securities | 4 | — | 1 | — | ||||||||||||
Total adjusted net income attributable to Chesapeake(a) (b) (Non-GAAP) | $ | 238 | $ | 0.21 | $ | 314 | $ | 0.30 | ||||||||
(a) | Adjusted net income available to common stockholders and total adjusted net income attributable to Chesapeake, both in the aggregate and per dilutive share, are not measures of financial performance under GAAP, and should not be considered as an alternative to, or more meaningful than, net income available to common stockholders or earnings per share. Adjusted net income available to common stockholders and adjusted earnings per share exclude certain items that management believes affect the comparability of operating results. The company believes these adjusted financial measures are a useful adjunct to earnings calculated in accordance with GAAP because: |
(i) | Management uses adjusted net income available to common stockholders to evaluate the company's operational trends and performance relative to other oil and natural gas producing companies. |
(ii) | Adjusted net income available to common stockholders is more comparable to earnings estimates provided by securities analysts. |
(iii) | Items excluded generally are one-time items or items whose timing or amount cannot be reasonably estimated. Accordingly, any guidance provided by the company generally excludes information regarding these types of items. |
Because adjusted net income available to common stockholders and total adjusted net income attributable to Chesapeake exclude some, but not all, items that affect net income available to common stockholders and total adjusted net income attributable to Chesapeake may vary among companies, our calculation of adjusted net income available to common stockholders and total adjusted net income attributable to Chesapeake may not be comparable to similarly titled financial measures of other companies.
(b) | Our presentation of diluted net income available to common stockholders and diluted adjusted net income per share excludes 1 million and 60 million shares considered antidilutive for the three months ended December 31, 2018 and 2017, respectively. The number of shares used for the non-GAAP calculation were determined in a manner consistent with GAAP. |
(c) | Loss on sale of oil and natural gas properties for the three months ended December 31, 2018 includes a $578 million loss related to the Utica divestiture. |
(d) No income tax effect from the adjustments has been included in determining adjusted net income for the three months ended December 31, 2018 and 2017. Our effective tax rate in both periods was 0% due to our valuation allowance position.
14
CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF ADJUSTED NET INCOME ATTRIBUTABLE TO CHESAPEAKE ($ in millions except per share data) (unaudited) | ||||||||||||||||
Years Ended December 31, | ||||||||||||||||
2018 | 2017 | |||||||||||||||
$ | $/Share(a)(b) | $ | $/Share(a)(b) | |||||||||||||
Net income available to common stockholders (GAAP) | $ | 775 | $ | 0.85 | $ | 813 | 0.90 | |||||||||
Effect of dilutive securities | — | — | ||||||||||||||
Diluted earnings per common stockholder (GAAP) | $ | 775 | $ | 0.85 | $ | 813 | $ | 0.90 | ||||||||
Adjustments: | ||||||||||||||||
Unrealized gains on oil, natural gas and NGL derivatives | (300 | ) | (0.33 | ) | (354 | ) | (0.39 | ) | ||||||||
Restructuring and other termination costs | 38 | 0.04 | — | — | ||||||||||||
Provision for legal contingencies, net | 26 | 0.03 | (38 | ) | (0.04 | ) | ||||||||||
Loss on sale of oil and natural gas properties (c) | 578 | 0.64 | — | — | ||||||||||||
Impairments | 53 | 0.06 | 5 | — | ||||||||||||
Other operating expense | 10 | 0.01 | 413 | 0.46 | ||||||||||||
Gains on investments | (139 | ) | (0.15 | ) | — | — | ||||||||||
Gains on purchases or exchanges of debt | (263 | ) | (0.29 | ) | (233 | ) | (0.26 | ) | ||||||||
Loss on exchange of preferred stock | — | — | 41 | 0.04 | ||||||||||||
Income tax expense (benefit)(d) | — | — | — | — | ||||||||||||
Other (e) | (60 | ) | (0.07 | ) | — | — | ||||||||||
Adjusted net income available to common stockholders(a) (b) (Non-GAAP) | 718 | 0.79 | 647 | 0.71 | ||||||||||||
Preferred stock dividends | 92 | 0.10 | 85 | 0.10 | ||||||||||||
Earnings allocated to participating securities | 6 | 0.01 | 10 | 0.01 | ||||||||||||
Total adjusted net income attributable to Chesapeake(a) (b) (Non-GAAP) | $ | 816 | $ | 0.90 | $ | 742 | $ | 0.82 | ||||||||
(a) | Adjusted net income available to common stockholders and total adjusted net income attributable to Chesapeake, both in the aggregate and per dilutive share, are not measures of financial performance under accounting principles generally accepted in the United States (GAAP), and should not be considered as an alternative to, or more meaningful than, net income available to common stockholders or earnings per share. Adjusted net income available to common stockholders and adjusted earnings per share exclude certain items that management believes affect the comparability of operating results. The company believes these adjusted financial measures are a useful adjunct to earnings calculated in accordance with GAAP because: |
(i) | Management uses adjusted net income available to common stockholders to evaluate the company's operational trends and performance relative to other oil and natural gas producing companies. |
(ii) | Adjusted net income available to common stockholders is more comparable to earnings estimates provided by securities analysts. |
(iii) | Items excluded generally are one-time items or items whose timing or amount cannot be reasonably estimated. Accordingly, any guidance provided by the company generally excludes information regarding these types of items. |
Because adjusted net income available to common stockholders and total adjusted net income attributable to Chesapeake exclude some, but not all, items that affect net income available to common stockholders and total adjusted net income attributable to Chesapeake may vary among companies, our calculation of adjusted net income available to common stockholders and total adjusted net income attributable to Chesapeake may not be comparable to similarly titled financial measures of other companies.
(b) | Our presentation of diluted net income available to common stockholders and diluted adjusted net income attributable to Chesapeake per share excludes 207 million shares considered antidilutive for the years ended December 31, 2018 and 2017. The number of shares used for the non-GAAP calculation were determined in a manner consistent with GAAP. |
(c) | Loss on sale of oil and natural gas properties for the year ended December 31, 2018 includes a $578 million loss related to the Utica divestiture. |
(d) No income tax effect from the adjustments has been included in determining adjusted net income for the years ended December 31, 2018 and 2017. Our effective tax rate in both periods was 0% due to our valuation allowance position.
(e) Other for the year ended December 31, 2018 includes a $61 million gain related to an extinguishment of the CHK Utica overriding royalty interest conveyance obligation.
15
CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF OPERATING CASH FLOW AND EBITDA ($ in millions) (unaudited) | |||||||||||||||
Three Months Ended December 31, | Years Ended December 31, | ||||||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||||||
CASH PROVIDED BY OPERATING ACTIVITIES (GAAP) | $ | 405 | $ | 472 | $ | 2,000 | $ | 745 | |||||||
Changes in components of working capital and other assets and liabilities | (38 | ) | 105 | (154 | ) | 471 | |||||||||
OPERATING CASH FLOW (Non-GAAP)(a) | $ | 367 | $ | 577 | $ | 1,846 | $ | 1,216 | |||||||
Three Months Ended December 31, | Years Ended December 31, | ||||||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||||||
NET INCOME (GAAP) | $ | 514 | $ | 334 | $ | 877 | $ | 953 | |||||||
Interest expense | 120 | 124 | 487 | 426 | |||||||||||
Income tax expense (benefit) | (2 | ) | — | (10 | ) | 2 | |||||||||
Depreciation, depletion and amortization | 278 | 306 | 1,145 | 995 | |||||||||||
EBITDA (Non-GAAP)(b) | $ | 910 | $ | 764 | $ | 2,499 | $ | 2,376 | |||||||
Three Months Ended December 31, | Years Ended December 31, | ||||||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||||||
CASH PROVIDED BY OPERATING ACTIVITIES (GAAP) | $ | 405 | $ | 472 | $ | 2,000 | $ | 745 | |||||||
Changes in assets and liabilities | (38 | ) | 105 | (154 | ) | 471 | |||||||||
Interest expense | 120 | 124 | 487 | 426 | |||||||||||
Gains (losses) on oil, natural gas and NGL derivatives, net | 473 | (41 | ) | (26 | ) | 411 | |||||||||
Cash (receipts) payments on derivative settlements, net | 183 | (28 | ) | 345 | 18 | ||||||||||
Stock-based compensation | (7 | ) | (11 | ) | (32 | ) | (49 | ) | |||||||
Loss on sale of oil and natural gas properties (c) | (578 | ) | — | (578 | ) | — | |||||||||
Impairments | (2 | ) | (2 | ) | (53 | ) | (5 | ) | |||||||
Gains on investments | — | — | 139 | — | |||||||||||
Gains on purchases or exchanges of debt | 331 | 50 | 263 | 235 | |||||||||||
Other items(d) | 23 | 95 | 108 | 124 | |||||||||||
EBITDA (Non-GAAP)(b) | $ | 910 | $ | 764 | $ | 2,499 | $ | 2,376 | |||||||
(a) | Operating cash flow represents net cash provided by operating activities before changes in components of working capital and other. Operating cash flow is presented because management believes it is a useful adjunct to net cash provided by operating activities under GAAP and provides useful information to investors for analysis of the Company's ability to generate cash to fund exploration and development, and to service debt. Operating cash flow is widely accepted as a financial indicator of an oil and natural gas company's ability to generate cash that is used to internally fund exploration and development activities and to service debt. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies within the oil and natural gas exploration and production industry. Operating cash flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating activities as an indicator of cash flows, or as a measure of liquidity. Because operating cash flow excludes some, but not all, items that affect net cash provided by operating activities and may vary among companies, our calculation of operating cash flow may not be comparable to similarly titled measures of other companies. The increase in operating cash flow for the year ended December 31, 2018 is mainly due to an increase in prices and volumes. |
(b) | EBITDA represents net income before interest expense, income tax expense, and depreciation, depletion and amortization expense. EBITDA is presented as a supplemental financial measurement in the evaluation of our business. We believe that it provides additional information regarding our ability to meet our future debt service, capital expenditures and working capital requirements. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies. EBITDA is also a financial measurement that, with certain negotiated adjustments, is reported to our lenders pursuant to our bank credit agreements and is used in the financial covenants in our bank credit agreements. EBITDA is not a measure of financial performance (or liquidity) under GAAP. Accordingly, it should not be considered as a substitute for net income, income from operations or cash flows from operating activities prepared in accordance with GAAP. |
(c) | Loss on sale of oil and natural gas properties for the three months ended December 31, 2018 and the year ended December 31, 2018 includes a $578 million loss related to the Utica divestiture. |
(d) | Other items for the year ended December 31, 2018 includes a $61 million gain related to an extinguishment of the CHK Utica overriding royalty interest conveyance obligation. |
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CHESAPEAKE ENERGY CORPORATION RECONCILIATION OF ADJUSTED EBITDA ($ in millions) (unaudited) | |||||||||||||||
Three Months Ended December 31, | Years Ended December 31, | ||||||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||||||
EBITDA (Non-GAAP)(a) | $ | 910 | $ | 764 | $ | 2,499 | $ | 2,376 | |||||||
Adjustments: | |||||||||||||||
Unrealized losses (gains) on oil, natural gas and NGL derivatives | (596 | ) | 73 | (300 | ) | (354 | ) | ||||||||
Restructuring and other termination costs | — | — | 38 | — | |||||||||||
Provision for legal contingencies, net | 9 | (73 | ) | 26 | (38 | ) | |||||||||
Loss on sale of oil and natural gas properties (b) | 578 | — | 578 | — | |||||||||||
Impairments | 2 | 2 | 53 | 5 | |||||||||||
Other operating (income) expense | 4 | (10 | ) | 10 | 413 | ||||||||||
Gains on investments | — | — | (139 | ) | — | ||||||||||
Gains on purchases or exchanges of debt | (331 | ) | (50 | ) | (263 | ) | (233 | ) | |||||||
Net income attributable to noncontrolling interests | (1 | ) | (1 | ) | (4 | ) | (4 | ) | |||||||
Other (c) | (1 | ) | 1 | (62 | ) | (5 | ) | ||||||||
Adjusted EBITDA (Non-GAAP)(a) | $ | 574 | $ | 706 | $ | 2,436 | $ | 2,160 | |||||||
(a) | EBITDA and Adjusted EBITDA are not measures of financial performance under GAAP, and should not be considered as an alternative to, or more meaningful than, net income or cash flow provided by (used in) operations prepared in accordance with GAAP. Adjusted EBITDA excludes certain items that management believes affect the comparability of operating results. The company believes these non-GAAP financial measures are a useful adjunct to EBITDA because: |
(i) | Management uses adjusted EBITDA to evaluate the company's operational trends and performance relative to other oil and natural gas producing companies. |
(ii) | Adjusted EBITDA is more comparable to estimates provided by securities analysts. |
(iii) | Items excluded generally are one-time items or items whose timing or amount cannot be reasonably estimated. Accordingly, any guidance provided by the company generally excludes information regarding these types of items. |
Because adjusted EBITDA excludes some, but not all, items that affect net income, our calculations of adjusted EBITDA may not be comparable to similarly titled measures of other companies.
(b) | Loss on sale of oil and natural gas properties for the three months ended December 31, 2018 and the year ended December 31, 2018 includes a $578 million loss related to the Utica divestiture. |
(c) Other for the year ended December 31, 2018 includes a $61 million gain related to an extinguishment of the CHK Utica overriding royalty interest conveyance obligation.
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CHESAPEAKE ENERGY CORPORATION ROLL-FORWARD OF PROVED RESERVES YEAR ENDED DECEMBER 31, 2018 (unaudited) | ||||
Mmboe(a) | ||||
Beginning balance, December 31, 2017 | 1,912 | |||
Production | (190 | ) | ||
Extensions, discoveries and other additions | 270 | |||
Revisions of previous estimates | 15 | |||
Sale of reserves in-place | (559 | ) | ||
Purchase of reserves in-place | — | |||
Ending balance, December 31, 2018 | 1,448 | |||
Proved reserves growth rate before acquisitions and divestitures | 5 | % | ||
Proved reserves growth rate after acquisitions and divestitures | (24 | )% | ||
Proved developed reserves | 748 | |||
Proved developed reserves percentage | 52 | % | ||
Standardized measure of discounted future net cash flows ($ in millions) (GAAP) | $ | 9,495 | ||
Add: Present value of future income taxes discounted at 10% per annum(a) | 32 | |||
PV-10 ($ in millions)(a) (Non-GAAP) | $ | 9,527 | ||
(a) | Reserve volumes and PV-10 value estimated using SEC reserve recognition standards and pricing assumptions based on the trailing 12-month average first-day-of-the-month prices as of December 31, 2018 of $65.56 per bbl of oil and $3.10 per mcf of natural gas, before basis differential adjustments. PV-10 is a non-GAAP metric used by the industry, investors and analysts to estimate the present value, discounted at 10% per annum, of estimated future cash flows of the company's estimated proved reserves before income tax. The table above shows the reconciliation of PV-10 to the company's standardized measure of discounted future net cash flows, the most directly comparable GAAP measure for the year ended December 31, 2018. Future income taxes in the calculation of the standardized measure of discounted future net cash flows were $32 million as of December 31, 2018. |
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CHESAPEAKE ENERGY CORPORATION
MANAGEMENT’S OUTLOOK AS OF FEBRUARY 27, 2019
Chesapeake periodically provides guidance on certain factors that affect the company’s future financial performance.
Year Ending 12/31/2019 | |
Production Growth Adjusted for Asset Sales(a) | 13% to 20% |
Absolute Production: | |
Oil - mmbbls | 42.5 - 44.5 |
NGL - mmbbls | 13.0 - 15.0 |
Natural gas - bcf | 710 - 750 |
Total absolute production - mmboe | 174 - 184 |
Absolute daily rate - mboe | 475 - 505 |
Estimated Realized Hedging Effects(b) (based on 2/22/19 strip prices): | |
Oil - $/bbl | ($0.17) |
Natural gas - $/mcf | ($0.07) |
Estimated Basis to NYMEX Prices: | |
Oil - $/bbl | $1.20 - $1.60 |
Natural gas - $/mcf | ($0.10) - ($0.20) |
NGL - realizations as a % of WTI | 33% to 36% |
Operating Costs per Boe of Projected Production: | |
Production expense | $3.25 - $3.50 |
Gathering, processing and transportation expenses | $6.00 - $6.50 |
Oil - $/bbl | $3.35 - $3.55 |
Natural gas - $/mcf | $1.20 - $1.30 |
Production taxes | $0.75 - $0.85 |
General and administrative(c) | $1.50 - $1.60 |
Stock-based compensation (non-cash) | $0.10 - $0.20 |
DD&A of natural gas and liquids assets | $5.50 - $6.50 |
Depreciation of other assets | $0.40 - $0.50 |
Interest expense | $3.20 - $3.40 |
Marketing Net Margin(d) | ($25) - ($45) |
Book Tax Rate | 0% |
Adjusted EBITDA, based on 2/22/19 strip prices ($ in millions)(e) | $2,500 - $2,700 |
Capital Expenditures ($ in millions)(f) | $2,175 - $2,375 |
Capitalized Interest ($ in millions) | $125 |
Total Capital Expenditures ($ in millions) | $2,300 - $2,500 |
(a) | Based on 2018 production of 422 mboe per day, adjusted for asset sales. |
(b) | Includes expected settlements for oil, natural gas and NGL derivatives adjusted for option premiums. For derivatives closed early, settlements are reflected in the period of original contract expiration. |
(c) | Excludes expenses associated with stock-based compensation, which are recorded in general and administrative expenses in Chesapeake's Condensed Consolidated Statement of Operations. |
(d) | Excludes non-cash amortization of approximately $8.7 million related to the buydown of a transportation agreement. |
(e) | Adjusted EBITDA is a non-GAAP measure used by management to evaluate the company's operational trends and performance relative to other oil and natural gas producing companies. Adjusted EBITDA excludes certain items that management believes affect the comparability of operating results. The most directly comparable GAAP measure is net income but, it is not possible, without unreasonable efforts, to identify the amount or significance of events or transactions that may be included in future GAAP net income but that management does not believe to be representative of underlying business performance. The company further believes that providing estimates of the amounts that would be required to reconcile forecasted adjusted EBITDA to forecasted GAAP net income would imply a degree of precision that may be confusing or misleading to investors. Items excluded from net income to arrive at adjusted EBITDA include interest expense, income |
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taxes, and depreciation, depletion and amortization expense as well as one-time items or items whose timing or amount cannot be reasonably estimated.
(f) | Includes capital expenditures for drilling and completion, leasehold, geological and geophysical costs, rig termination payments and other property, plant and equipment. Excludes any additional proved property acquisitions. |
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Oil, Natural Gas and Natural Gas Liquids Hedging Activities
Chesapeake enters into oil, natural gas and NGL derivative transactions in order to mitigate a portion of its exposure to adverse changes in market prices. Please see the quarterly reports on Form 10-Q and annual reports on Form 10-K filed by Chesapeake with the SEC for detailed information about derivative instruments the company uses, its quarter-end derivative positions and accounting for oil, natural gas and natural gas liquids derivatives.
As of February 22, 2019, including January and February derivative contracts that have settled, approximately 63 percent of the company's 2019 forecasted oil, natural gas and NGL production revenue was hedged, including approximately 56 percent and 81 percent of its 2019 forecasted oil and natural gas production (including Brazos Valley production from February 1, 2019) at average prices of $57.12 per bbl and $2.85 per mcf, respectively.
In addition, the company had downside protection on a portion of its 2020 oil production at an average price of $59.72 per bbl and on a portion of its 2020 gas production at an average price of $2.75 per mcf.
The company’s crude oil hedging positions were as follows:
Open Crude Oil Swaps | |||||
Open Swaps (mmbbls) | Avg. NYMEX Price of Swaps | ||||
Q1 2019 | 5 | $ | 57.04 | ||
Q2 2019 | 5 | $ | 57.09 | ||
Q3 2019 | 4 | $ | 57.28 | ||
Q4 2019 | 3 | $ | 57.33 | ||
Total 2019 | 17 | $ | 57.16 | ||
Total 2020 | 7 | $ | 58.28 | ||
Oil Two-Way Collars | |||||||||
Collars (mmbbls) | Avg. NYMEX Bought Put Price | Avg. NYMEX Sold Call Price | |||||||
Q1 2019 | 1 | $ | 58.00 | $ | 67.75 | ||||
Q2 2019 | 1 | $ | 58.00 | $ | 67.75 | ||||
Q3 2019 | 2 | $ | 58.00 | $ | 67.75 | ||||
Q4 2019 | 2 | $ | 58.00 | $ | 67.75 | ||||
Total 2019 | 6 | $ | 58.00 | $ | 67.75 | ||||
Total 2020 | 2 | $ | 65.00 | $ | 83.25 | ||||
Oil Puts | |||||
Volume (mbbls) | Avg. NYMEX Bought Put Price | ||||
Q1 2019 | 110 | $ | 50.00 | ||
Q2 2019 | 221 | $ | 52.63 | ||
Q3 2019 | 587 | $ | 54.14 | ||
Q4 2019 | 832 | $ | 54.43 | ||
Total 2019 | 1,750 | $ | 53.83 | ||
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Oil Basis Protection Swaps | |||||
Volume (mmbbls) | Avg. NYMEX plus/(minus) | ||||
Q1 2019 | 2 | $ | 5.93 | ||
Q2 2019 | 3 | $ | 5.93 | ||
Q3 2019 | 1 | $ | 6.20 | ||
Q4 2019 | 1 | $ | 6.20 | ||
Total 2019 | 7 | $ | 6.01 | ||
The company’s natural gas hedging positions were as follows:
Open Natural Gas Swaps | |||||
Swaps (bcf) | Avg. NYMEX Price of Swaps | ||||
Q1 2019 | 109 | $ | 2.98 | ||
Q2 2019 | 119 | $ | 2.84 | ||
Q3 2019 | 115 | $ | 2.84 | ||
Q4 2019 | 110 | $ | 2.84 | ||
Total 2019 | 453 | $ | 2.87 | ||
Total 2020 | 217 | $ | 2.75 | ||
Natural Gas Two-Way Collars | |||||||||
Collars (bcf) | Avg. NYMEX Bought Put Price | Avg. NYMEX Sold Call Price | |||||||
Q1 2019 | 27 | $ | 2.75 | $ | 3.13 | ||||
Q2 2019 | 9 | $ | 2.75 | $ | 2.91 | ||||
Q3 2019 | 10 | $ | 2.75 | $ | 2.91 | ||||
Q4 2019 | 9 | $ | 2.75 | $ | 2.91 | ||||
Total 2019 | 55 | $ | 2.75 | $ | 3.02 | ||||
Natural Gas Three-Way Collars | |||||||||||||
Collars (bcf) | Avg. NYMEX Sold Put Price | Avg. NYMEX Bought Put Price | Avg. NYMEX Sold Call Price | ||||||||||
Q1 2019 | 22 | $ | 2.50 | $ | 2.80 | $ | 3.10 | ||||||
Q2 2019 | 22 | $ | 2.50 | $ | 2.80 | $ | 3.10 | ||||||
Q3 2019 | 22 | $ | 2.50 | $ | 2.80 | $ | 3.10 | ||||||
Q4 2019 | 22 | $ | 2.50 | $ | 2.80 | $ | 3.10 | ||||||
Total 2019 | 88 | $ | 2.50 | $ | 2.80 | $ | 3.10 | ||||||
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Natural Gas Net Written Call Options | |||||
Call Options (bcf) | Avg. NYMEX Strike Price | ||||
Q1 2019 | 5 | $ | 12.00 | ||
Q2 2019 | 5 | $ | 12.00 | ||
Q3 2019 | 6 | $ | 12.00 | ||
Q4 2019 | 6 | $ | 12.00 | ||
Total 2019 | 22 | $ | 12.00 | ||
Total 2020 | 22 | $ | 12.00 | ||
Natural Gas Net Written Call Swaptions | |||||
Call Options (bcf) | Avg. NYMEX Strike Price | ||||
Total 2020 | 106 | $ | 2.77 | ||
Natural Gas Basis Protection Swaps | |||||
Volume (bcf) | Avg. NYMEX plus/(minus) | ||||
Q1 2019 | 12 | $ | (0.36 | ) | |
Q2 2019 | 18 | $ | (0.84 | ) | |
Q3 2019 | 14 | $ | (0.45 | ) | |
Q4 2019 | 6 | $ | (0.39 | ) | |
Total 2019 | 50 | $ | (0.56 | ) | |
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