Chesapeake Energy : Reports 2015 First Quarter Financial and Operational Results

Chesapeake Energy Corporation (NYSE:CHK) today reported financial and operational results for the 2015 first quarter. Highlights include:

• Average production of approximately 686,000 boe per day, an increase of 14% year over year, adjusted for asset sales
• Adjusted net income of $0.11 per fully diluted share and adjusted ebitda of $928 million
• 2015 total production guidance increased to 640 – 650 mboe per day
• 2015 capital guidance of approximately $3.5 – $4.0 billion reiterated
• Additional 600 – 700 new Eagle Ford locations added following successful down spacing test results

Doug Lawler, Chesapeake’s Chief Executive Officer, commented, “Chesapeake is meeting the challenge of low commodity prices head-on and delivered a very strong first quarter. Adjusted for asset sales, our production in the 2015 first quarter grew by 14% compared to the 2014 first quarter. Our cash costs remain at industry-low levels and we expect our assets to continue delivering greater efficiencies even as we reduce our activity levels throughout 2015. We remain on target to balance our capital spending and our cash flow by year-end, and the capital efficiencies that we are seeing in each of our operating areas are helping to strengthen that cash flow. During this challenging commodity price environment, our talented employees and high-quality assets are delivering competitive, differential performance.”

2015 First Quarter Financial Results

For the 2015 first quarter, Chesapeake reported a net loss available to common stockholders of $3.782 billion, or ($5.72) per fully diluted share, which compares to net income available to common stockholders of $374 million, or $0.54 per fully diluted share in the 2014 first quarter. Items typically excluded by securities analysts in their earnings estimates reduced 2015 first quarter net income by approximately $3.824 billion on an after-tax basis and are presented on Page 11 of this release. The primary source of this reduction was an impairment in the carrying value of Chesapeake's oil and natural gas properties largely resulting from significant decreases in the trailing 12-month average first-day-of-the-month oil and natural gas prices as of March 31, 2015, compared to December 31, 2014. Adjusting for this and other items, 2015 first quarter net income available to common stockholders was $42 million, or $0.11 per fully diluted share, which compares to adjusted net income available to common stockholders of $405 million, or $0.59 per fully diluted share, in the 2014 first quarter.

Adjusted ebitda was $928 million in the 2015 first quarter, compared to $1.515 billion in the 2014 first quarter. Operating cash flow was $910 million in the 2015 first quarter, compared to $1.614 billion in the 2014 first quarter. The year-over-year decreases in adjusted ebitda and operating cash flow were primarily the result of lower realized oil, natural gas and natural gas liquid (NGL) prices.

Adjusted net income available to common stockholders, operating cash flow, ebitda and adjusted ebitda are non-GAAP financial measures. Reconciliations of these measures to comparable financial measures calculated in accordance with generally accepted accounting principles are provided on pages 11 – 13 of this release.

2015 First Quarter Average Daily Production of 686,000 Boe Increased 14% Year Over Year and 2% Sequentially, Adjusted for Asset Sales

Chesapeake’s daily production for the 2015 first quarter averaged approximately 686,000 barrels of oil equivalent (boe), a year-over-year increase of 14%, adjusted for asset sales. Average daily production in the 2015 first quarter consisted of approximately 121,900 barrels (bbls) of oil, 2.9 billion cubic feet (bcf) of natural gas and 75,800 bbls of NGL, which represent year-over-year increases of 17%, 12% and 19%, respectively, adjusted for asset sales.

Capital Spending and Cost Overview

Chesapeake’s drilling and completion capital expenditures during the 2015 first quarter were approximately $1.3 billion, and capital expenditures for leasehold, geological and geophysical costs and other property, plant and equipment were approximately $63 million, for a total of approximately $1.4 billion. Total capital expenditures, including capitalized interest of $123 million, were approximately $1.5 billion in the 2015 first quarter, compared to approximately $1.8 billion in the 2014 fourth quarter and $1.4 billion in the 2014 first quarter and are reconciled below.

Chesapeake's focus on cost discipline continued to generate reductions in costs associated with production and general and administrative (G&A) expenses. Average production expenses during the 2015 first quarter were $4.84 per boe, a decrease of 5% from the 2014 fourth quarter and an increase of 2% year over year. G&A expenses (including stock-based compensation) during the 2015 first quarter were $0.91 per boe, a decrease of 34% from the 2014 fourth quarter and 30% year over year.

A summary of the company’s guidance for 2015 is provided in the Outlook dated May 6, 2015, attached to this release as Schedule "A” beginning on Page 14.

Operational Results – Southern Division

Eagle Ford Shale (South Texas): Eagle Ford net production averaged approximately 113 thousand barrels of oil equivalent (mboe) per day (242 gross operated mboe per day) during the 2015 first quarter, an increase of 7% sequentially. The full-year 2014 average completed well cost was $5.9 million with an average completed lateral length of 5,850 feet and 18 frac stages, compared to the full-year 2013 average completed well cost of $6.9 million with an average completed lateral length of 5,850 feet and 18 frac stages. Well cost-reduction efforts continue and the company anticipates completed well costs of $5.5 million by year-end 2015. The company has successfully drilled five wells with laterals in excess of 10,000 feet. This technical achievement will heavily influence future development in the field as the company prioritizes front-loading its drill schedule with this well design. Chesapeake has successfully completed down spacing tests in various sections of its acreage, adding 600 – 700 incremental locations to its undrilled inventory. The company plans to test its first Upper Eagle Ford well in the 2015 fourth quarter. The average peak production rate of the 105 wells that commenced first production in the Eagle Ford during the 2015 first quarter was approximately 763 boe per day.

Haynesville Shale and Bossier Shale (Northwest Louisiana): Haynesville net production averaged approximately 616 million cubic feet of natural gas equivalent (mmcf) per day (996 gross operated mmcf per day) during the 2015 first quarter, an increase of 4% sequentially. The full-year 2014 average completed well cost was $8.4 million with an average completed lateral length of 4,900 feet and 14 frac stages, compared to an average completed well cost of $8.9 million in 2013 with an average completed lateral length of 4,400 feet and 18 frac stages. In April 2015, the company placed its initial two modern extended lateral (7,500 feet) Haynesville wells on line, the Nguyen 8-15-14 1H ALT and the Nguyen 5-15-14 2H ALT at peak 24-hour rates of 18.5 mmcf per day and 16.7 mmcf per day, respectively, with flowing surface pressures of approximately 600 PSI per foot greater than surrounding in-unit wells. The average peak production rate of the 19 wells that commenced first production in the Haynesville during the 2015 first quarter was approximately 15.4 mmcf per day. Chesapeake also recently turned in line two successful tests in the Bossier Shale utilizing enhanced stimulation techniques. These wells are producing at a restricted rate of 12.0 mmcf per day paving the way for future Bossier development of 200 – 400 wells that can utilize both enhanced stimulation and extended laterals.

Mid-Continent North: Mississippian Lime (Northern Oklahoma): Mississippian Lime net production averaged approximately 32 mboe per day (75 gross operated mboe per day) during the 2015 first quarter, an increase of 11% sequentially. The full-year 2014 average completed well cost was $3.0 million with an average completed lateral length of 4,500 feet, compared to an average completed well cost of $3.5 million in 2013 with an average completed lateral length of 4,500 feet. The company anticipates completed well costs of $2.5 million in 2015, resulting in a 45% capital reduction in three years. The average peak production rate of the 48 wells that commenced first production in the Mississippian Lime during the 2015 first quarter was approximately 733 boe per day.

Operational Results – Northern Division

Utica Shale (Eastern Ohio): Utica net production averaged approximately 110 mboe per day (190 gross operated mboe per day) during the 2015 first quarter, an increase of 10% sequentially. The full-year 2014 average completed well cost was $7.2 million with an average completed lateral length of 6,200 feet and 29 frac stages, compared to an average completed well cost of $6.7 million in 2013 with an average completed lateral length of 5,150 feet and 17 frac stages. Chesapeake anticipates average completed well costs of $8.2 million in 2015 while extending laterals to 7,900 feet with 41 frac stages. The average peak production rate of the 38 wells that commenced first production in the Utica during the 2015 first quarter was approximately 1,272 boe per day.

Marcellus Shale (Northern Pennsylvania): Marcellus net production averaged approximately 832 mmcf per day (1.932 gross operated bcf per day) during the 2015 first quarter, an increase of 2% sequentially. The 2014 full-year average completed well cost was $7.5 million with an average completed lateral length of 5,950 feet and 27 frac stages, compared to an average completed well cost of $7.9 million in 2013 with an average completed lateral length of 5,400 feet and 13 frac stages. With ample existing drilled inventory and significant curtailed volumes, Chesapeake expects to maintain production at current levels throughout 2015 in the Marcellus. The average peak production rate of the 16 wells that commenced first production in the northern Marcellus during the 2015 first quarter was approximately 15.8 mmcf per day.

Powder River Basin (PRB): Niobrara and Upper Cretaceous (Wyoming): PRB net production averaged approximately 20 mboe per day (30 gross operated mboe per day) during the 2015 first quarter, an increase of 10% sequentially. The 2014 full-year average completed well cost (including multiple exploratory wells) was $10.6 million per well with an average completed lateral length of 5,425 feet and 20 frac stages, compared to an average completed well cost of $10.1 million per well in 2013 with an average completed lateral length of 5,050 feet and 15 frac stages. Chesapeake continues to improve operational efficiency and has successfully tested multiple Upper Cretaceous test wells. The average peak production rate of the 11 wells that commenced first production in the PRB during the 2015 first quarter was approximately 1,594 boe per day.

Key Financial and Operational Results

The table below summarizes Chesapeake’s key financial and operational results during the 2015 first quarter, as compared to results in prior periods.

2015 First Quarter Financial and Operational Results Conference Call Information

A conference call to discuss this release has been scheduled for Wednesday, May 6, 2015, at 9:00 am EDT. The telephone number to access the conference call is 913-312-1393 or toll-free 888-797-2983. The passcode for the call is 3887326. We encourage those who would like to participate in the call to place calls between 8:50 and 9:00 am EDT. For those unable to participate in the live conference call, a replay will be available for audio playback at 2:00 pm EDT on Wednesday, May 6, 2015, and will run through 2:00 pm EDT on Wednesday, May 20, 2015. The number to access the conference call replay is 719-457-0820 or toll-free 888-203-1112. The passcode for the replay is 3887326. The conference call will also be webcast live on Chesapeake’s website at www.chk.com and a replay will be available following the call. An investor presentation has been posted on the company's website at www.chk.com/investors/presentations. The latest investor presentation that will be referenced during the call provides additional financial and operational disclosure and will be available in the Investor Relations section of the company's website.

Chesapeake Energy Corporation (NYSE:CHK) is the second-largest producer of natural gas and the 11th largest producer of oil and natural gas liquids in the U.S.Headquartered in Oklahoma City, the company's operations are focused on discovering and developing its large and geographically diverse resource base of unconventional oil and natural gas assets onshore in the U.S.The company also owns substantial marketing and compression businesses.Further information is available at www.chk.com where Chesapeake routinely posts announcements, updates, events, investor information, presentations and news releases.

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, production growth and well connection forecasts, estimates of operating costs, planned development drilling and expected drilling cost reductions, capital expenditures, expected efficiency gains, anticipated assets sales and proceeds to be received therefrom, projected cash flow and liquidity, business strategy and other plans and objectives for future operations, 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; write-downs of our oil and natural gas carrying values due to declines in prices; the availability of operating cash flow and other funds to finance reserve replacement costs; 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; the limitations our level of indebtedness may have on our financial flexibility; charges incurred in response to market conditions and in connection with 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; federal and state tax proposals affecting our industry; potential OTC derivatives regulation limiting our ability to hedge against commodity price fluctuations; impacts of potential legislative and regulatory actions addressing climate change; 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; cyber attacks adversely impacting our operations; and interruption in operations at our headquarters due to a catastrophic event.

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 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.

Oil, Natural Gas and NGL 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 NGL derivatives.

As of April 30, 2015, the company had downside protection on approximately 43% of its remaining projected 2015 oil production at an average price of $93.48 per bbl of which 12% is hedged under three-way collar arrangements based on an average bought put NYMEX price of $90 per bbl and exposure below an average sold put NYMEX price of $80 per bbl. Approximately 40% of the company's remaining projected 2015 natural gas production has downside protection at an average price of $3.85 per one thousand cubic feet of natural gas (mcf), of which 14% is hedged under three-way collar arrangements based on an average bought put NYMEX price of $4.17 per mcf and exposure below an average sold put NYMEX price of $3.38 per mcf.

The company’s crude oil hedging positions as of April 30, 2015, were as follows:

The company’s natural gas hedging positions as of April 30, 2015 were as follows: