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OKLAHOMA CITY, Feb. 23, 2017 /PRNewswire/ -- Chesapeake Energy Corporation (NYSE: CHK) today reported financial and operational results for the 2016 full year and fourth quarter plus other recent developments. Highlights include:

• Average 2016 production of 635,400 boe per day, comparable to 2015 levels, adjusted for asset sales
• Total oil and natural gas proved reserves of approximately 1.7 billion barrels of oil equivalent (bboe), a 14% increase compared to 2015 levels
• Replaced 249% of production through extensions and discoveries, compared to 93% in 2015 (excluding reserve revisions)
• Reduced production expenses by approximately $336 million, or 28% per boe of production, compared to 2015
• Reduced gathering, processing and transportation expenses by approximately $264 million, or 7% per boe of production, compared to 2015
• Improved financial flexibility and reduced leverage driven by noncore asset sales, refinancings, open market repurchases and exchanges of near and mid-term debt maturities as well as preferred stock
• Enhanced operating flexibility through reductions of future midstream commitments

Doug Lawler, Chesapeake's Chief Executive Officer, commented, "During 2016, we made significant progress in improving our capital efficiency, decreasing cash costs and future midstream commitments while improving our liquidity and leverage profile, which resulted in a much stronger foundation for Chesapeake going forward. In 2017, we are capitalizing on these improvements across our cost structure to increase shareholder returns from our high-quality, diversified oil and natural gas portfolio. Our increase in activity over 2016 levels positions Chesapeake to deliver increased profitability and long-term value for our shareholders."

2016 Full Year Results

For the 2016 full year, Chesapeake's revenues declined by 38% from the 2015 full year due to a decrease in the average realized commodity prices received for its oil and natural gas production, lower production volumes, increased unrealized hedging losses and a decrease in the volumes sold and prices received by the company's marketing affiliate on behalf of third-party producers. Average daily production for the 2016 full year of approximately 635,400 barrels of oil equivalent (boe) consisted of approximately 90,800 barrels (bbls) of oil, 2.867 billion cubic feet (bcf) of natural gas and 66,700 bbls of natural gas liquids (NGL). During 2016, Chesapeake divested properties with average daily production of approximately 73,500 boe.

Average production expenses during the 2016 full year were $3.05 per boe, while G&A expenses (including stock-based compensation) during the 2016 full year were $1.03 per boe. Combined production and G&A expenses (including stock-based compensation) during the 2016 full year were $4.08 per boe, a decrease of 21% from the 2015 full year. Gathering, processing and transportation expenses during the 2016 full year were $7.98 per boe, a decrease of 7% from the 2015 full year. A summary of the company's production and operating expense guidance for 2017 is provided in the Outlook dated February 23, 2017, beginning on page 21.

Chesapeake reported a net loss available to common stockholders of $4.881 billion, or $6.39 per share, while the company's ebitda for the 2016 full year was a loss of $3.142 billion. The primary drivers of the net loss were noncash impairments of the carrying value of Chesapeake's oil and natural gas properties totaling $2.520 billion, largely resulting from decreases in the trailing 12-month average first-day-of-the-month oil and natural gas prices used in the company's impairment calculations, Barnett Shale exit costs of approximately $645 million and unrealized hedging losses of $818 million as prices marginally recovered. Adjusting for these and other items that are typically excluded by securities analysts, the 2016  full year adjusted net loss available to common stockholders was $138 million, or $0.05 per common share, while the company's adjusted ebitda was $1.339 billion in the 2016 full year. Reconciliations of financial measures calculated in accordance with generally accepted accounting principles (GAAP) to non-GAAP measures are provided on pages 13 – 19 of this release.

2016 Fourth Quarter Results

For the 2016 fourth quarter, Chesapeake's revenues declined by 24% year over year due to a decrease in the average realized commodity prices for its oil production, lower production volumes and increased unrealized hedging losses. Average daily production for the 2016 fourth quarter of approximately 574,500 barrels of oil equivalent (boe) consisted of approximately 90,400 bbls of oil, 2.562 bcf of natural gas and 57,100 bbls of NGL.

Average production expenses during the 2016 fourth quarter were $2.98 per boe, while G&A expenses (including stock-based compensation) during the 2016 fourth quarter were $1.28 per boe. Combined production and G&A expenses (including stock-based compensation) during the 2016 fourth quarter were $4.26 per boe, a decrease of 8% year over year. Gathering, processing and transportation expenses during the 2016 fourth quarter were $7.92 per boe, a decrease of 30% year over year, primarily due to minimum volume commitment shortfall payments accrued in the 2015 fourth quarter for our Barnett Shale operating area.

Chesapeake reported a net loss available to common stockholders of $741 million, or $0.84 per share, while the company's ebitda for the 2016 fourth quarter was a loss of $198 million. The primary drivers of the net loss were $395 million in unrealized losses on the company's oil and natural gas commodity derivatives and the loss on exchange of preferred stock of $428 million which represents the fair value of the additional shares of common stock issued in the exchange over the shares that would have been issuable pursuant to the original conversion terms. Adjusting for these and other items that are typically excluded by securities analysts, the 2016 fourth quarter adjusted net income available to common stockholders was $93 million, or $0.07 per common share, while the company's adjusted ebitda was $385 million in the 2016 fourth quarter. Reconciliations of financial measures calculated in accordance with GAAP to non-GAAP measures are provided on pages 13 – 19 of this release.

Capital Spending Overview

Chesapeake's total capital investments were approximately $1.7 billion during the 2016 full year, compared to approximately $3.6 billion in the 2015 full year. A summary of the company's 2016 and 2015 capital expenditures as well as the current 2017 guidance is provided in the table below.

 

Balance Sheet and Liquidity

As of December 31, 2016, Chesapeake's debt principal balance was approximately $10.0 billion, compared to $9.7 billion as of December 31, 2015, with approximately $882 million cash on hand. Subsequent to December 31, 2016, Chesapeake reduced its debt principal balance by approximately $901 million through the following actions:

• repayment upon maturity of $258 million of our 6.25% Euro-denominated senior notes due January 2017;
• retirement of approximately $287 million of principal amount of our outstanding contingent convertible senior notes and $2 million of non-convertible senior notes for an aggregate of $286 million pursuant to tender offers;
• redemption and retirement of $133 million remaining principal balance of our outstanding 6.5% Senior Notes due 2017; and
• open market repurchases of approximately $221 million principal amount of our outstanding unsecured senior notes for $224 million.

Following the 2017 reductions in the principal balance of the company's outstanding debt, Chesapeake has approximately $9.1 billion in outstanding debt, with no outstanding borrowings on its revolving credit facility. Since December 31, 2015, Chesapeake has reduced the principal amount of debt due or that could be put to the company in 2017 and 2018 by approximately $2.7 billion, or 97%, from $2.770 billion to $77 million.

Also in January 2017, the company completed private exchanges of an aggregate of approximately 10 million shares of its common stock for (i) 150,948 shares of 5.00% Cumulative Convertible Preferred Stock (Series 2005B), (ii) 72,600 shares of 5.75% Cumulative Convertible Preferred Stock and (iii) 12,500 shares of 5.75% Cumulative Convertible Preferred Stock (Series A), with an aggregate liquidation value of approximately $100 million. On February 15, 2017, Chesapeake reinstated the payment of dividends on each series of its outstanding convertible preferred stock and paid our dividends in arrears.

Following the debt principal reductions, reinstatement of preferred dividends inclusive of payment of dividends in arrears and reductions in midstream obligations detailed below, Chesapeake expects to end February with approximately $300 million in cash on hand.

Asset Acquisitions and Divestitures Update

In the 2016 third quarter, the company entered into an agreement to convey its interests in the Barnett Shale operating area located in north central Texas to Total S.A. (NYSE: TOT) and simultaneously terminate a portion of future gas gathering and transportation commitments associated with this asset. Chesapeake received approximately $218 million in proceeds for these assets, which closed on October 31, 2016.

Also in the 2016 third quarter, the company sold the majority of its upstream and midstream assets in the Devonian Shale located in West Virginia, Kentucky, and Virginia. In connection with this divestiture, the company repurchased one of its two remaining volumetric production payment (VPP) transactions, resulting in nominal net proceeds. Chesapeake retained the deeper drilling rights in the area after this disposition, which closed on December 21, 2016.

In the 2017 first quarter, Chesapeake closed on two separate sales transactions of acreage and producing properties in its Haynesville Shale operating area in northern Louisiana for gross proceeds of approximately $915 million. Included in the sale were approximately 119,500 net acres and approximately 576 wells producing 80 million cubic feet of gas (mmcf) per day. Chesapeake continues to focus on select asset divestitures and is planning to sell additional noncore and non-operated properties in 2017.

Midstream Update

In the 2016 fourth quarter, Chesapeake signed a definitive contract to restructure its natural gas gathering and service agreement in its Powder River Basin operating area with Williams Partners L.P. and Crestwood Equity Partners L.P. The restructured services replaced the current cost-of-service arrangement and improved economics that support increased development across an expanded area of dedication in the region and became effective January 1, 2017, for a 20-year term.

Chesapeake continues to work to reduce and optimize its gathering, processing and transportation commitments across all of its operating areas. In February 2017, the company successfully reduced crude transportation commitments related to the Seaway Pipeline by assigning these commitments to a separate third party, effective April 1, 2017. These commitments totaled approximately $450 million and Chesapeake paid approximately $290 million to assign the contract. As a result, the company expects its marketing margin to improve significantly in 2018 over 2017 expected levels and return to profitability after 2018. In addition, the company utilized $100 million of the proceeds from the divestiture of its assets in the Barnett Shale to buy down approximately $110 million of its related natural gas transportation obligations. This new agreement is expected to be effective March 1, 2017.

Operations Update

Chesapeake's average daily production for the 2016 fourth quarter was approximately 574,500 boe and is further detailed in the table below. For the 2017 first quarter, the company expects its average daily production to range between 515,000 and 535,000 boe, of which average daily oil production is expected to range between 80,000 and 85,000 barrels per day, which is consistent with prior guidance. Chesapeake's projected production volumes and capital expenditure program are subject to capital allocation decisions throughout the year and can be adjusted based on prevailing market conditions.

 

Chesapeake is currently utilizing 17 drilling rigs across its operating areas, six of which are located in the Eagle Ford Shale, four in the Mid-Continent area, three in the Haynesville Shale, two in the Powder River Basin and two in Northeast Appalachia. Chesapeake plans to utilize an average of 17 rigs throughout the year and intends to spud and place in production approximately 400 and 450 gross operated wells, respectively, in 2017.

Key Financial and Operational Results

The table below summarizes Chesapeake's key financial and operational results during the 2016 fourth quarter and full year as compared to results in prior periods.

 

2016 Fourth Quarter and Year-End Financial and Operational Results Conference Call Information

A conference call to discuss this release has been scheduled on Thursday, February 23, 2017 at 9:00 am EDT. The telephone number to access the conference call is 719-325-2355 or toll-free 888-417-8531. The passcode for the call is 2585187. 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 2585187. 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.  The company also owns oil and natural gas marketing and natural gas gathering and compression businesses.

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 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, general and administrative expenses, capital expenditures, the timing of anticipated noncore asset sales and proceeds to be received therefrom, projected cash flow and liquidity, our ability to enhance our cash flow and financial flexibility, plans and objectives for future operations (including our ability to optimize base production and execute gas gathering agreements), 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; potential challenges by Seventy Seven Energy Inc.'s (SSE) former creditors in connection with SSE's recently completed bankruptcy under Chapter 11 of the U.S. Bankruptcy Code; an interruption in operations at our headquarters due to a catastrophic event; the continuation of suspended dividend payments on our common stock; 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.

 

 

 

 

 

PV-10 is discounted (at 10%) future net cash flows before income taxes. The standardized measure of discounted future net cash flows includes the effects of estimated future income tax expenses and is calculated in accordance with Accounting Standards Codification Topic 932. Management uses PV-10 as one measure of the value of the company's current proved reserves and to compare relative values among peer companies without regard to income taxes. We also understand that securities analysts and rating agencies use this measure in similar ways. While PV-10 is based on prices, costs and discount factors which are consistent from company to company, the standardized measure is dependent on the unique tax situation of each individual company.

The company's PV-10 and standardized measure were calculated using the following prices, before basis differential adjustments: $42.75 per bbl of oil and $2.49 per mcf of natural gas as of December 31, 2016, and $50.28 per bbl of oil and $2.58 per mcf of natural gas as of December 31, 2015.

 

 

 

 

 

 

 

 

 

 

 

CHESAPEAKE ENERGY CORPORATION
RECONCILIATION OF PV-9 AND PV-10 TO STANDARDIZED MEASURE
($ in millions)
(unaudited)

PV-9 is a non-GAAP metric used in the determination of the value of collateral under Chesapeake's credit facility. 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 following table shows the reconciliation of PV-9 and 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, 2015 and for the period ended December 31, 2016. Management believes that PV-9 provides useful information to investors regarding the company's collateral position and that PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and natural gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, management believes the use of a pre-tax measure is valuable for evaluating the company. Neither PV-9 nor PV-10 should be considered as an alternative to the standardized measure of discounted future net cash flows as computed under GAAP.

 

CHESAPEAKE ENERGY CORPORATION
MANAGEMENT'S OUTLOOK AS OF FEBRUARY 23, 2017

Chesapeake periodically provides guidance on certain factors that affect the company's future financial performance. New information or changes from the company's February 14, 2017 Outlook are italicized bold below.

 

Oil, Natural Gas and Natural Gas Liquids Hedging Activities

Chesapeake enters into commodity 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, 2017, the company had downside protection, through open swaps, on its 2017 oil production at an average price of $50.19 per bbl. The company had downside price protection, through open swaps and two-way collars, on its 2017 natural gas production at an average price of $3.07 per mcf.  Chesapeake also had downside price protection, through open swaps, on a portion of its 2017 ethane production at an average price of $0.28 per gallon.

In addition, the company had downside protection, through open swaps and two-way collars, on a portion of its 2018 natural gas production at an average price of $3.09 per mcf.

The company's crude oil hedging positions as of February 22, 2017 were as follows:

 

 

The company's natural gas hedging positions as of February 22, 2017 were as follows:

 

 

 

 

The company's natural gas liquids hedging positions as of February 22, 2017 were as follows:

 

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SOURCE Chesapeake Energy Corporation