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Chesapeake Energy Corporation Reports 2018 Second Quarter Financial And Operational Results

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OKLAHOMA CITY, Aug. 1, 2018 /PRNewswire/ — Chesapeake Energy Corporation (NYSE:CHK) today reported financial and operational results for the 2018 second quarter. Highlights include:

  • 2018 second quarter net loss available to common stockholders of $40 million, or $0.04 per diluted share; 2018 second quarter adjusted net income attributable to Chesapeake of $139 million, or $0.15 per diluted share
  • Average 2018 second quarter production of approximately 530,000 barrels of oil equivalent (boe) per day, up 8 percent compared to 2017 second quarter, adjusted for asset sales
  • Average 2018 second quarter oil production of approximately 90,000 barrels of oil per day, up 11 percent compared to 2017 second quarter, adjusted for asset sales
  • Powder River Basin (PRB) production achieved a record daily rate of approximately 32,000 boe per day on July 22; company now expects production from the area to reach 38,000 boe per day by year-end primarily driven by Turner performance

Doug Lawler, Chesapeake’s President and Chief Executive Officer, commented, “Chesapeake continues to make significant progress in achieving our strategic priorities of reducing leverage, increasing margins and reaching cash flow neutrality. Last week’s announcement to sell our Utica position will allow us to retire nearly $2 billion of outstanding debt, while the recent significant ramp in our Powder River Basin volumes position us to replace the divested Utica EBITDA within a year. For the third consecutive quarter, we have recorded impressive cash flow driven by better-than-expected oil production. We expect to see continued meaningful improvements in growing our cash flow as our total oil production, adjusted for asset sales, moves higher throughout the rest of 2018 and into 2019. Lower total debt, improving margins and greater capital efficiency are positioning Chesapeake for significant equity value creation moving forward.”

2018 Second Quarter Results

For the 2018 second quarter, Chesapeake reported a net loss of $16 million and a net loss available to common stockholders of $40 million, or $0.04 per diluted share.  The company’s EBITDA for the 2018 second quarter was $382 million. Adjusting for items that are typically excluded by securities analysts, the 2018 second quarter adjusted net income attributable to Chesapeake was $139 million, or $0.15 per diluted share, while the company’s adjusted EBITDA was $536 million. Reconciliations of financial measures calculated in accordance with GAAP to non-GAAP measures are provided on pages 14 – 18 of this release.

Production expenses during the 2018 second quarter were $2.86 per boe, compared to $2.92 per boe in the 2017 second quarter, primarily as a result of certain 2018 and 2017 divestitures, partially offset by increased saltwater disposal costs. General and administrative expenses (including stock-based compensation) during the 2018 second quarter were $1.89 per boe, compared to $1.45 per boe in the 2017 second quarter. The increase was primarily driven by stock-based compensation awards. The company’s gathering, processing, and transportation expenses decreased by 5 percent year over year to $7.04 per boe from $7.44 per boe during the 2017 second quarter primarily as a result of certain 2018 and 2017 divestitures, reduced fees due to restructured midstream contracts and lower volume commitments.

Capital Spending Overview

Chesapeake’s total capital expenditures (including accruals) were approximately $595 million during the 2018 second quarter, including capitalized interest of $43 million, compared to approximately $667 million in the 2017 second quarter. A summary is provided in the table below.

Three Months Ended
June 30,



Operated activity comparison

Average rig count



Gross wells spud



Gross wells completed



Gross wells connected



Type of cost ($ in millions)

Drilling and completion capital expenditures





Exploration costs, leasehold and additions to other PP&E



Subtotal capital expenditures





Capitalized interest



Total capital expenditures





Balance Sheet and Liquidity

As of June 30, 2018, Chesapeake’s principal amount of debt outstanding was approximately $9.706 billion, compared to $9.981 billion as of December 31, 2017. The company had $506 million of outstanding borrowings and had used $183 million for various letters of credit under its senior secured revolving credit facility resulting in approximately $3.1 billion of available liquidity under the facility as of June 30, 2018. The company’s borrowing capacity on its revolving credit facility was re-affirmed in June 2018 at approximately $3.8 billion.

Operations Update

Chesapeake’s average daily production for the 2018 second quarter was approximately 530,000 boe compared to approximately 528,000 boe in the 2017 second quarter. The following tables show average daily production and average daily sales prices received by the company’s operating divisions for the 2018 and 2017 second quarters, respectively.

(a)   Includes assets retained as of June 30, 2018.

Chesapeake continues to benefit from the depth and breadth of its portfolio, which offers stacked pay potential across a diverse set of assets. The company remains focused on optimizing these resources through enhanced completions, longer laterals and spacing optimization and continues to drive costs lower to enhance its cash flow.

The Powder River Basin (PRB) in Wyoming is quickly establishing itself as the growth engine of the company, as recently demonstrated by a 78 percent increase in net production compared to the average 2017 fourth quarter rate. On July 22, 2018, total net production hit a new record of approximately 32,000 net boe per day (42% oil, 41% natural gas and 17% natural gas liquids), compared to an average 2017 fourth quarter rate of 18,000 boe per day. Chesapeake now projects net production from the area will reach approximately 38,000 boe per day by year-end 2018, and expects total net annual production from the PRB to more than double in 2019 compared to 2018.

In late-June and July 2018, Chesapeake placed a total of five Turner wells on production with initial daily rates ranging from approximately 1,500 boe per day to 3,200 boe per day, with oil production representing approximately 65 percent. These wells are still in flow back and cleaning up and the company expects higher rates from several over the next 30 days. The Turner program continues to deliver impressive results across a broad area, with wells now producing across an area over 20 miles wide in the field.

In April 2018, six Turner wells were placed on production and spaced at approximately 1,980 to 2,300 feet apart to test well performance with reduced spacing. As the wells continue to clean up, all six wells are currently performing as well as or better than previously unbounded wells, or wells spaced approximately 2,640 feet apart. With days on production ranging from 85 to 100, all six wells have reached daily gross production rates of approximately 1,600 boe per day to 2,600 boe per day, with oil production ranging from 35 percent to 45 percent.

In July 2018, Chesapeake moved to five rigs in the PRB, all of which are primarily focused on the Turner formation. The company placed nine wells on production during the 2018 second quarter, and expects to place 14 wells on production during the 2018 third quarter and 14 wells on production during the 2018 fourth quarter. In addition, the company is exploring the potential of adding a sixth rig in 2019 and remains encouraged about the future growth potential offered by additional formations such as the Teapot, Parkman, Niobrara, Sussex and Mowry, among others.

To support anticipated rig activity, Chesapeake recently reached an agreement with Williams Partners, L.P. and Crestwood Equity Partners, L.P. for an expansion of their existing gas gathering system and processing facility at the existing competitive fee-rate structure. The company is also in active discussions with several midstream and downstream providers on awarding its crude and water gathering business in the basin.

The Eagle Ford Shale in South Texas remains Chesapeake’s EBITDA-generating backbone, consistently delivering high-margin oil volumes and stable production. The company continues to drive costs out of its operations and is currently utilizing four rigs in the Eagle Ford. The company placed 48 wells on production during the 2018 second quarter, and expects to place 38 wells on production during the 2018 third quarter and 47 wells on production during the 2018 fourth quarter.

Similar to the PRB, Chesapeake continues to appraise liquid-rich opportunities across its expansive acreage position in its Mid-Continent operating area in Oklahoma and is deploying advanced completions and longer laterals to test new concepts. In the meantime, Oswego volumes continue to climb with average 30-day production rates of 1,015 boe per day and over 80 percent oil cuts. Chesapeake is currently utilizing two rigs in the Mid-Continent. The company placed eight wells on production during the 2018 second quarter, and expects to place 12 wells on production during the 2018 third quarter and nine wells on production during the 2018 fourth quarter.

The Haynesville Shale in Louisiana continues to deliver consistent production volumes, and with approximately 75 percent of the development locations remaining undeveloped, offers significant potential for future growth. To date, the advances provided by enhanced completions and longer laterals, including the first 15,000-foot lateral ever drilled in the basin, have allowed the company to grow 2018 second quarter production by approximately 15% year over year while utilizing the same number of rigs. Additionally, with ample takeaway capacity, Chesapeake is well positioned to access Henry Hub pricing and other premium markets. Chesapeakemoved an additional rig into the Haynesville in July and is currently utilizing four rigs. The company placed 12 wells on production during the 2018 second quarter, and expects to place six wells on production during the 2018 third quarter and nine wells on production during the 2018 fourth quarter.

Chesapeake’s premium Marcellus Shale position in Pennsylvania continues to be a significant cash flow generator for the company. The company’s enhanced completions and longer laterals continue to create additional value across the company’s Lower Marcellus and Upper Marcellus formations, and the company plans to test the deeper Utica formation found under its acreage position in 2019. In July 2018, Chesapeakesuccessfully drilled its longest lateral to date in the Lower Marcellus Shale at approximately 13,380 feet, only to be surpassed by an even longer planned lateral of approximately 14,500 feet currently being drilled. Both wells are expected to be placed on production before year-end 2018. Chesapeake is currently utilizing three rigs in the Marcellus. The company placed 10 wells on production during the 2018 second quarter, and expects to place 14 wells on production during the 2018 third quarter and 18 wells on production during the 2018 fourth quarter.

Chesapeake recently announced that it has entered into an agreement to sell its interests in the Utica Shale operating area located in Ohio for approximately $2.0 billion, plus the right to receive an additional $100 millionin consideration based on future natural gas prices, to Encino Acquisition Partners, a private oil and gas company headquartered in Houston, Texas. The transaction, which is subject to certain customary closing conditions, including the receipt of third-party consents, is expected to close in the 2018 fourth quarter. Chesapeake is currently utilizing no rigs and placed seven wells on production during the 2018 second quarter. The company expects to move two rigs back into the Utica in the near term, in accordance with the recent purchase and sale agreement signed last week regarding the asset, and expects to place 14 wells on production during the 2018 third quarter.

Key Financial and Operational Results

The table below summarizes Chesapeake’s key financial and operational results during the 2018 second quarter as compared to results in prior periods.

Three Months Ended
June 30,



Barrels of oil equivalent production (in mboe)



Barrels of oil equivalent production (mboe/d)



Oil production (in mbbl/d)



Average realized oil price ($/bbl)(a)



Natural gas production (in mmcf/d)



Average realized natural gas price ($/mcf)(a)



NGL production (in mbbl/d)



Average realized NGL price ($/bbl)(a)



Production expenses ($/boe)



Gathering, processing and transportation expenses ($/boe)



Oil – ($/bbl)



Natural Gas – ($/mcf)



NGL – ($/bbl)



Production taxes ($/boe)



General and administrative expenses ($/boe)(b)



General and administrative expenses (stock-based compensation) (non-cash) ($/boe)



DD&A of oil and natural gas properties ($/boe)



DD&A of other assets ($/boe)



Interest expense ($/boe)



Marketing gross margin ($ in millions)



Net cash provided by (used in) operating activities ($ in millions)



Net cash provided by (used in) operating activities ($/boe)



Operating cash flow ($ in millions)(c)



Operating cash flow ($/boe)



Net income (loss) ($ in millions)



Net income (loss) available to common stockholders ($ in millions)



Net income (loss) per share available to common stockholders – diluted ($)



Adjusted EBITDA ($ in millions)(d)



Adjusted EBITDA ($/boe)



Adjusted net income attributable to Chesapeake ($ in millions)(e)



Adjusted net income attributable to Chesapeake
per share – diluted ($ in millions)(f)




Includes the effects of realized gains (losses) from hedging, but excludes the effects of unrealized gains (losses) from hedging.


Excludes expenses associated with stock-based compensation, which are recorded in general and administrative expenses in Chesapeake’s Condensed Consolidated Statement of Operations.


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 of cash provided by (used in) operating activities to operating cash flow on page 16.


Defined as net income (loss) before interest expense, income taxes and depreciation, depletion and amortization expense, as adjusted to remove the effects of certain items detailed on page 18. This is a non-GAAP measure. See reconciliation of net income (loss) to EBITDA on page 16 and reconciliation of EBITDA to adjusted EBITDA on page 18.


Defined as net income (loss) attributable to Chesapeake, as adjusted to remove the effects of certain items detailed on page 14. This is a non-GAAP measure. See reconciliation of net income to adjusted net income (loss) available to Chesapeake on page 14.


Our presentation of diluted adjusted net income (loss) attributable to Chesapeake per share excludes 207 million and 1 million shares for the three months ended June 30, 2018 and 2017, respectively, considered antidilutive when calculating diluted earnings per share.

2018 Second Quarter Financial and Operational Results Conference Call Information

A conference call to discuss this release has been scheduled on Wednesday, August 1, 2018 at 9:00 am EDT. The telephone number to access the conference call is 323-994-2093 or toll-free 888-254-3590. The passcode for the call is 9446629. 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 9446629. The conference call will be webcast and can be found at 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 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.



Brad Sylvester, CFA   

  Gordon Pennoyer

(405) 935-8870  

  (405) 935-8878

[email protected]   

  [email protected]

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