Chesapeake Energy Corporation Reports 2015 Third Quarter Financial And Operational Results

OKLAHOMA CITY, Nov. 4, 2015 /PRNewswire/ -- Chesapeake Energy Corporation CHK today reported financial and operational results for the 2015 third quarter. Highlights include:

• Production averaged approximately 667,000 boe per day, an increase of 3% year over year, adjusted for asset sales
• Adjusted net loss of $0.05 per fully diluted share and adjusted ebitda of $560 million
• 2015 total production guidance increased to 670 – 680 mboe per day
• 2015 production expense and general and administrative expense guidance lowered significantly
• 2015 capital guidance reduced to $3.4 – $3.9 billion

Doug Lawler, Chesapeake's Chief Executive Officer, commented, "The many actions that we have taken this quarter, including executing new gas gathering agreements, amending our revolving credit facility, reducing complexity and commitments and lowering our business costs, have significantly increased Chesapeake's ability to create additional value. Our focus on optimizing base production and continuing to generate efficiencies in the field drove a 3% increase in production compared to last year, adjusted for asset sales. In addition, the elimination of $200 million of annualized, controllable production and general and administrative expenses represents another step in our commitment to financial discipline."

Lawler continued, "We lowered our 2015 capital guidance to $3.4 to $3.9 billion and are prepared to execute on a significantly lower capital program in 2016. While the current price environment presents many challenges for our industry, we will continue focusing on our capital and operating cost efficiency, enhancing our cash flow and financial flexibility and optimizing our base production. The power of our people, the strength of our portfolio and our operational leadership will continue to create value for Chesapeake for the long term."

2015 Third Quarter Financial Results

For the 2015 third quarter, Chesapeake reported a net loss available to common stockholders of $4.695 billion, or $7.08 per fully diluted share, which compares to net income available to common stockholders of $169 million, or $0.26 per fully diluted share, in the 2014 third quarter.  Items typically excluded by securities analysts in their earnings estimates reduced 2015 third quarter net income by approximately $4.612 billion on an after-tax basis and are presented on Page 12 of this release.  The primary source of this reduction was a noncash impairment of 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 September 30, 2015, compared to June 30, 2015.  Adjusting for this and other items, the 2015 third quarter net loss available to common stockholders was $83 million, or $0.05 per fully diluted share, which compares to adjusted net income available to common stockholders of $251 million, or $0.38 per fully diluted share, in the 2014 third quarter.

Adjusted ebitda was $560 million in the 2015 third quarter, compared to $1.236 billion in the 2014 third quarter.  Operating cash flow was $476 million in the 2015 third quarter, compared to $1.293 billion in the 2014 third 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, partially offset by higher realized hedging gains and lower production expenses, general and administrative (G&A) expenses and production taxes.

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 12 – 17 of this release.

2015 Third Quarter Average Daily Production of 667,000 Boe Increased 3% Year Over Year, Adjusted for Asset Sales

Chesapeake's daily production for the 2015 third quarter averaged approximately 667,000 barrels of oil equivalent (boe), a year-over-year increase of 3% adjusted for asset sales.  Average daily production in the 2015 third quarter consisted of approximately 114,100 barrels (bbls) of oil, 2.9 billion cubic feet (bcf) of natural gas and 76,200 bbls of NGL, which represent year-over-year increases of 4%, 2% and 7%, respectively, adjusted for asset sales. During the 2015 third quarter, the company had average curtailed production of approximately 51,000 boe per day. The company has increased its total 2015 production guidance to 670,000 – 680,000 boe per day, representing a 6% – 8% increase over 2014 results, adjusted for asset sales.

Capital Spending and Cost Overview

Chesapeake's 2015 third quarter drilling and completion capital expenditures decreased 41% sequentially to approximately $467 million, and capital expenditures for leasehold, geological and geophysical costs and other property, plant and equipment remained flat at approximately $57 million, for a total of approximately $524 million.  Total 2015 third quarter capital expenditures of $623 million, including capitalized interest of $99 million, decreased 35% and 59% compared to 2015 second quarter and 2014 third quarter results, respectively, and are detailed in the table below. For 2015, the company has reduced its estimated total capital expenditures to $3.4 – $3.9 billion, compared to $3.5 – $4.0 billion as previously provided.

 

Chesapeake's focus on cost discipline continued to generate reductions in production and G&A expenses.  Production expenses during the 2015 third quarter were $4.09 per boe, while G&A expenses (including stock-based compensation) during the 2015 third quarter were $0.79 per boe.  Combined production expenses and G&A expenses (including stock-based compensation) during the 2015 third quarter decreased 10% sequentially and 9% year over year.  

A summary of the company's guidance for 2015 is provided in the Outlook dated November 4, 2015, beginning on Page 18.

Operational Results – Southern Division

Eagle Ford Shale (South Texas): Eagle Ford net production averaged approximately 108 thousand barrels of oil equivalent (mboe) per day (234 gross operated mboe per day) during the 2015 third quarter, an increase of 3% sequentially. Average completed well costs to date in 2015 are $5.3 million with an average completed lateral length of 6,000 feet and 21 frac stages, compared to the full-year 2014 average completed well cost of $5.9 million with an average completed lateral length of 5,850 feet and 18 frac stages. Chesapeake continues to realize significant efficiencies with longer laterals and larger completions in the area. Recent third quarter well results include the Rogers E-1H and Faith San Pedro F-4H wells, which had completed lateral lengths of 12,488 and 13,151 feet, respectively, and reached peak 24-hour production rates of 1,479 and 1,067 bbls of oil per day, respectively. These two long-lateral wells have an average field estimated completed well cost of $7.8 million each. The JEA Unit XIV LAS S 4H East Four Corners well was also completed in the third quarter using an enhanced design on a 4,611-foot completed lateral and reached a peak 24-hour rate of 1,311 bbls of oil per day. The field estimated completed well cost of this well is $4.8 million. The company placed 30 wells on production during the 2015 third quarter, compared to 89 wells in the 2014 third quarter. Chesapeake's operated rig count in the Eagle Ford averaged three rigs in the 2015 third quarter, and the company anticipates maintaining three operated rigs through the end of the year.

Haynesville Shale and Bossier Shales (Northwest Louisiana): Haynesville net production averaged approximately 636 million cubic feet of natural gas (mmcf) per day (1.03 gross operated bcf per day) during the 2015 third quarter, a decrease of 5% sequentially. Average completed well costs to date in 2015 are $7.7 million with an average completed lateral length of 5,000 feet and 14 frac stages, compared to the full-year 2014 average completed well cost of $8.4 million with an average completed lateral length of 4,900 feet and 14 frac stages. The company placed seven wells on production during the 2015 third quarter, compared to 14 wells in the 2014 third quarter. Operated rig count in the Haynesville averaged six rigs in the 2015 third quarter, and the company anticipates maintaining six operated rigs through the end of the year.

Mid-Continent: Mississippian Lime (Northern Oklahoma): Mississippian Lime net production averaged approximately 31 mboe per day (74 gross operated mboe per day) during the 2015 third quarter, a decrease of 1% sequentially. Average completed well costs to date in 2015 are $2.8 million with an average completed lateral length of 4,500 feet and nine frac stages, compared to the full-year 2014 average completed well cost of $3.0 million with an average completed lateral length of 4,450 feet and nine frac stages. During the 2015 third quarter, the company drilled a record lateral length of 9,395 feet in the JJJ 23-25-11 1H well, which is currently being completed. Chesapeake also drilled its first multi-lateral well in the Mississippian Lime. The Wilber 26-27-11 1H, which had dual laterals of 4,653 feet and 4,556 feet, is currently being completed. The company placed 13 wells on production during the 2015 third quarter, compared to 44 wells in the 2014 third quarter. Operated rig count in the Mississippian Lime averaged three rigs during the 2015 third quarter, and the company has released all operated rigs in the area through the end of the year.

Oklahoma STACK (Northwest and Central Oklahoma): The company has identified multiple stacked liquids-rich opportunities on its extensive Oklahoma STACK leasehold position, substantially all of which is held by production. During the 2015 third quarter, the company drilled its first two wells targeting the Meramec formation, and is currently drilling a third well, with encouraging results. The Rouce 4-17-10 1H, which has a completed lateral of 9,350 feet, was recently placed on production and has reached over 870 bbls of oil per day after three days. The Wittrock 16-16-9 1H has been drilled with a lateral length of 9,220 feet and is currently being completed. The Stangl 36-16-9 1H is currently drilling with a planned lateral length of 9,426 feet. The company intends to keep one operated rig in the STACK area through the end of the year.

Operational Results – Northern Division

Utica Shale (Eastern Ohio): Utica net production averaged approximately 106 mboe per day (183 gross operated mboe per day) during the 2015 third quarter, a decrease of 15% sequentially, as the company voluntarily curtailed approximately 20 net mboe per day during the quarter as a result of weak product pricing. During the 2015 fourth quarter, a new regional pipeline is expected to be placed in-service, allowing the company to move an additional 350 mmcf per day out of the basin and greater access to Gulf Coast pricing. Average completed well costs to date in 2015 are $7.7 million with an average completed lateral length of 7,900 feet and 40 frac stages, compared to the full-year 2014 average completed well cost of $7.2 million with an average completed lateral length of 6,200 feet and 29 frac stages. During the 2015 third quarter, the company drilled a new record lateral length in the Utica of 12,976 feet. Additionally, the average cycle time for Utica wells drilled in the third quarter was 9.9 days, with a record cycle time of 6.8 days. Operated rig count in the Utica averaged two rigs in the 2015 third quarter, and the company anticipates maintaining two operated rigs through the end of the year.

Marcellus Shale (Northern Pennsylvania): Marcellus net production averaged approximately 809 mmcf per day (1.77 gross operated bcf per day) during the 2015 third quarter, a decrease of 1% sequentially. Chesapeake has been voluntarily curtailing production from the area since the 2015 first quarter, primarily due to weak in-basin gas prices. The company anticipates maintaining Marcellus curtailments for the remainder of the year and actively managing its production through the winter months. Average completed well costs to date in 2015 are $6.4 million with an average completed lateral length of 6,800 feet and 29 frac stages, compared to the full-year 2014 average completed well cost of $7.5 million with an average completed lateral length of 6,000 feet and 27 frac stages. Recent third quarter well results include two tests of the Upper Marcellus formation located in Bradford County, Pennsylvania, which had completed lateral lengths of 5,600 feet and 4,800 feet, respectively, and reached peak 24-hour production rates of approximately 19,000 mcf per day and 17,000 mcf per day, respectively. The company believes that these successful completions in the Upper Marcellus could provide more than 1,000 potential new drilling locations. Operated rig count in the Marcellus averaged one rig in the 2015 third quarter, and the company anticipates maintaining one operated rig through the end of the year.

Powder River Basin (PRB) (Wyoming): PRB net production averaged approximately 21 mboe per day (31 gross operated mboe per day) during the 2015 third quarter, an increase of 5% sequentially. Average completed well costs to date in 2015 are $10.6 million with an average completed lateral length of 5,900 feet and 22 frac stages, compared to the full-year 2014 average completed well cost of $10.6 million with an average completed lateral length of 5,400 feet and 20 frac stages. Recent third quarter well results include the Barton 32-34-67 USA A 1H, which was placed on production in October with a completed lateral length of 9,500 feet and reached a peak 24-hour production rate of 1,500 boe per day (85% black oil) from the Niobrara formation. Operated rig count in the PRB averaged one rig in the 2015 third quarter, and the company has released all operated rigs in the area through the end of the year.

Key Financial and Operational Results

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

 

2015 Third Quarter Financial and Operational Results Conference Call Information

A conference call to discuss this release has been scheduled for Wednesday, November 4, 2015 at 9:00 am EST. The telephone number to access the conference call is 913-312-6690 or toll-free 888-600-4885. The passcode for the call is 4959206. We encourage those who would like to participate in the call to place calls between 8:50 and 9:00 am EST. For those unable to participate in the live conference call, a replay will be available for audio playback at 12:00 pm EST on Wednesday, November 4, 2015, and will run through 12:00 pm EST on Wednesday, November 18, 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 4959206. The conference call will also be webcast live 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.

Chesapeake Energy Corporation CHK is the second-largest producer of natural gas and the 12th 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 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; 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 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.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Accordingly, adjusted EBITDA should not be considered as a substitute for net income, income from operations or cash flow provided by operating activities prepared in accordance with GAAP.

CHESAPEAKE ENERGY CORPORATION

MANAGEMENT'S OUTLOOK AS OF NOVEMBER 4, 2015

Chesapeake periodically provides management guidance on certain factors that affect the company's future financial performance.  Changes from the company's August 5, 2015 Outlook are italicized bold below.

 

Oil and Natural Gas Hedging Activities

Chesapeake enters into oil and natural gas 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 and natural gas derivatives.

As of October 31, 2015, the company had downside protection, through open swaps, on approximately 38% of its projected 2015 fourth quarter oil production at an average price of $86.89 per bbl. In addition, the company had downside price protection under three-way collar arrangements on approximately 11% of its projected 2015 fourth quarter oil production 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.  The company had downside price protection, through open swaps, on approximately 20% of the company's projected 2015 fourth quarter natural gas production at an average price of $3.94 per mcf. In addition, the company had downside price protection under three-way collar arrangements on approximately 14% of its projected 2015 fourth quarter natural gas production 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. On three-way collars, if the actual price at settlement is below the sold put, the company's gain will be the difference between the bought put and the sold put.

The company's crude oil hedging positions as of October 31, 2015 were as follows:

 

 

 

 

 

 

The company's natural gas hedging positions as of October 31, 2015 were as follows:

 

 

 

 

 

 

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SOURCE Chesapeake Energy Corporation