Chesapeake Energy Corporation Reports 2018 Third Quarter Financial And Operational Results And Time Change For Earnings Call

OKLAHOMA CITY, Oct. 30, 2018 /PRNewswire/ -- Chesapeake Energy Corporation (NYSE:CHK) today reported financial and operational results for the 2018 third quarter. Highlights include:

• 2018 third quarter net income available to common stockholders of $60 million, or $0.07 per diluted share; 2018 third quarter adjusted net income attributable to Chesapeake of $174 million, or $0.19 per diluted share
• 2018 third quarter cash flow from operating activities of $504 million, up 52 percent from 2017 third quarter levels
• Average 2018 third quarter production of approximately 537,000 barrels of oil equivalent (boe) per day, up 5 percent compared to 2017 third quarter, adjusted for asset sales
• Average 2018 third quarter oil production of approximately 89,000 barrels (bbls) of oil per day, up 13 percent compared to 2017 third quarter, adjusted for asset sales, primarily driven by higher volume growth from the Powder River Basin (PRB)

Doug Lawler, Chesapeake's President and Chief Executive Officer, commented, "Chesapeake continues to make significant progress on our strategic priorities, as demonstrated by our improved cash flow from operations, which was more than 50 percent higher than the 2017 third quarter due to higher average realized commodity prices and 13 percent growth in our adjusted oil production. We plan to focus the vast majority of our projected 2019 activity on our high-margin, higher-return oil opportunities in the PRB and Eagle Ford Shale, while decreasing capital and activity directed toward our natural gas portfolio, which will generate additional free cash flow. Our capital expenditures for 2018 remain on track, as we execute on our priorities of reducing leverage, increasing margins and reaching sustainable positive cash flow, and we expect continued progress in 2019."

2018 Third Quarter Results

For the 2018 third quarter, Chesapeake reported net income of $85 million and net income available to common stockholders of $60 million, or $0.07 per diluted share.  The company's EBITDA for the 2018 third quarter was $504 million. Adjusting for items that are typically excluded by securities analysts, the 2018 third quarter adjusted net income attributable to Chesapeake was $174 million, or $0.19 per diluted share, while the company's adjusted EBITDA was $594 million. Reconciliations of financial measures calculated in accordance with GAAP to non-GAAP measures are provided on pages 13 - 18 of this release.

Production expenses during the 2018 third quarter were $2.68 per boe, compared to $3.03 per boe in the 2017 third quarter. The decrease was primarily a result of certain 2018 and 2017 divestitures, in addition to lower workover activity in the Eagle Ford Shale. General and administrative expenses (including stock-based compensation) during the 2018 third quarter were $1.34 per boe, compared to $1.08 per boe in the 2017 third quarter. 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 2017 and 2018. The company's gathering, processing and transportation expenses decreased to $7.36 per boe from $7.40 per boe during the 2017 third 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 incurred total capital expenditures, including capitalized interest of $42 million, of approximately $619 million during the 2018 third quarter, compared to approximately $692 million in the 2017 third quarter. A summary is provided in the table below.

Balance Sheet and Liquidity

As of September 30, 2018, Chesapeake's principal amount of debt outstanding was approximately $9.862 billion, compared to $9.981 billion as of December 31, 2017. Also as of September 30, 2018, the company had $645 million of outstanding borrowings and $182 million for various letters of credit under its senior secured revolving credit facility resulting in approximately $2.2 billion of available liquidity under the facility.

Chesapeake continues to focus on reducing future interest expense charges, eliminating complexity and simplifying its balance sheet. On September 12, 2018, the company amended and restated its senior secured revolving credit facility with an initial borrowing base of $3.0 billion maturing in September 2023. The collateral securing the initial borrowing base does not include any properties sold in the company's $2.0 billion Utica Shale transaction, which closed in October 2018, therefore the borrowing base was not affected.

On September 27, 2018, the company issued $1.25 billion of senior notes, consisting of $850 million of 7.00% senior notes due 2024 and $400 million of 7.50% senior notes due 2026. Chesapeake used the net proceeds from the offering, together with borrowings under its revolving credit facility, to repay its secured term loan due 2021 which carried a floating interest rate equating to approximately 9.60%, in its entirety. The impact of this refinancing is projected to result in cash interest expense savings of approximately $30 million in 2019.

On October 29, 2018, the company delivered a notice of redemption to the trustee for its 8.00% Senior Secured Second Lien Notes due 2022 to call for redemption approximately $1.416 billion aggregate principal amount of the outstanding notes, representing 100% of the aggregate principal amount of the outstanding notes. The settlement of the redemption is expected to occur approximately 30 days from the notice delivery date and be funded with proceeds from the sale of the company's Utica Shale assets in Ohio.

Operations Update

Chesapeake's average daily production for the 2018 third quarter was approximately 537,000 boe compared to approximately 542,000 boe in the 2017 third 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 third quarters, respectively.

Momentum is building in the PRB, where additional spacing and step-out tests further validate the exceptional rock quality, productivity and repeatable performance of the Turner formation. Daily net production from the basin continues to climb as demonstrated by the 107 percent increase compared to the average 2017 third quarter daily rate and 32 percent sequential growth compared to the 2018 second quarter. Chesapeake expects net production from the area will reach approximately 38,000 boe per day as an exit rate in 2018, and currently projects total net annual production from the PRB to more than double in 2019 compared to 2018.

In July 2018, Chesapeake moved to five rigs in the PRB, all of which are currently drilling the Turner formation. The company placed 13 wells on production during the 2018 third quarter, eight of which were Turner wells, bringing the total number of Turner wells on production to 24. Included was the company's best well drilled to date in the Turner with the Wyoming 36-34-69 B TR 1H well reaching a peak 24-hour average rate of 3,133 boe per day (47 percent oil) from a 10,246-foot lateral. In the 2018 third quarter, Chesapeake also drilled and completed three successful step-out Turner wells located along the western periphery of its acreage position. The wells yielded peak 24-hour production rates ranging from 1,480 to 2,725 boe per day with an average oil cut of 82 percent. With these well results, Chesapeake has delineated an area covering more than 50 square miles, or approximately 60 percent of its prospective Turner acreage, strengthening its confidence in future development plans.

The company continues to experiment with tighter spacing tests and is currently drilling its second set of wells spaced at approximately 1,980 feet. In April 2018, Chesapeake drilled six Turner wells spaced at approximately 1,980 to 2,300 feet apart and, with more than 190 days on production for each well, the company has seen no degradation from the tighter-spaced Turner wells compared to wells spaced at approximately 2,680 feet. The company expects to drill additional spacing tests in 2019, as well as move to development pad drilling in the more oil-prone (lower gas-to-oil ratio) portion of the field.

Chesapeake expects to place an additional 15 wells on production in the 2018 fourth quarter and is currently projecting an additional 65 to 70 Turner wells to be placed on production in 2019. The company is exploring the potential of adding a sixth rig in 2019, which would likely begin to focus on the Parkman and Niobrara formations.

To support the company's anticipated oil production growth, Chesapeake has recently finalized an agreement, subject to a right of first refusal, to lower its gathering and transporting costs by switching from trucking to pipeline transportation. The agreement will provide for the gathering and transportation of a portion of the company's crude oil volumes via pipeline from its development area to Guernsey, Wyoming beginning in the 2019 second quarter. The company's fixed-fee rate under this agreement is approximately one-third the cost the market is presently paying to gather and transport oil volumes to Guernsey by trucking. Chesapeake is evaluating long-haul transportation options to take volumes to Cushing, Oklahoma, to increase market access as production grows.

The Eagle Ford Shale in Texas continues to deliver steady, high-margin oil volumes that receive premium Gulf Coast pricing. While the region is typically unaffected by major weather events, production from the area was affected by abnormal flooding resulting in a decline in average net oil volumes sold of approximately 1,300 bbls of oil per day for the months of September and October 2018. The company is currently utilizing four rigs in the Eagle Ford, placed 29 wells on production during the 2018 third quarter and expects to place 53 wells on production during the 2018 fourth quarter. Chesapeake plans to add a fifth rig in 2019, as it continues to delineate additional opportunities in the Upper Eagle Ford and the Austin Chalk formations.

Chesapeake's position in the Marcellus Shale in Pennsylvania continues to create significant free cash flow driven by higher realized in-basin gas prices in the 2018 third quarter compared to a year ago, enhanced completions and longer laterals. Chesapeake is currently utilizing two rigs in the Marcellus, placed seven wells on production during the 2018 third quarter, and expects to place 25 wells on production during the 2018 fourth quarter.

In the 2018 third quarter, Chesapeake entered into a long-term supply agreement with a liquefied natural gas (LNG) provider for a portion of the company's in-basin net Marcellus gas production. Chesapeake has agreed to supply approximately 260 to 365 million British thermal units per day of net Marcellus gas production to the LNG provider for a 15-year term.

In the Haynesville Shale in Louisiana, Chesapeake moved an additional rig into the area in July and is currently utilizing four rigs, one of which is drilling the company's second well with a proposed lateral length of approximately 15,000 feet. Chesapeake drilled its first 15,000-foot well, the GEPH 30&19&18-16-15 1HC, in December 2017, which was placed on production in May, 2018. After approximately 170 days, the well is producing approximately 24.9 million cubic feet of natural gas (mmcf) per day and has produced a cumulative of 5.8 billion cubic feet of natural gas (bcf). Given higher-margin oil drilling opportunities in Chesapeake's portfolio, the company expects to decrease its activity in the area and move to operating one to two rigs in 2019. The company placed four wells on production in the Haynesville Shale during the 2018 third quarter, and expects to place seven wells on production during the 2018 fourth quarter.

In July 2018, Chesapeake announced that it entered into an agreement to sell its interests in the Utica Shale operating area located in Ohio for approximately $2.0 billion, subject to certain customary closing conditions including the receipt of third-party consents. This transaction closed in October 2018. Chesapeake is currently operating two rigs in the area and placed 11 Utica wells on production during the 2018 third quarter.

2018 Third Quarter Financial and Operational Results Conference Call Update

The conference call to discuss this release has been re-scheduled on Tuesday, October 30, 2018 at 9:00 am EDT. The telephone number to access the conference call is 877-871-3172 or 412-902-6603. The passcode for the call is 0118883. The conference call will be webcast and can be found at www.chk.com in the "Investors" section of the company's website.

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.

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 October 26, 2018, including October derivative contracts that have settled, the company had downside price protection on a portion of its 2018 oil, natural gas and natural gas liquids production. The company had downside oil price protection through swaps at an average price of $54.09 per bbl, and under three-way collar arrangements based on an average bought put NYMEX price of $47.00 per bbl and exposure below an average sold put NYMEX price of $39.15 per bbl. The company had downside natural gas price protection through swaps and two-way collars at an average price of $3.00 per mcf. Chesapeake also had downside ethane, propane, butane, isobutane and natural gasoline price protection through swaps at an average price of $0.29, $0.79, $0.88, $0.92 and $1.42 per gallon (as well as a portion of butane at 70.5 percent of WTI), respectively. Further details summarized below.

In addition, the company had downside protection, through open swaps on a portion of its 2019 oil production at an average price of $59.44 per bbl. The company also initiated downside protection on a portion of its 2019 natural gas production through open swaps and two-way collars at an average price of $2.82 per mcf and under three-way collar arrangements based on an average bought put NYMEX price of $2.80 per mcf and exposure below an average sold put NYMEX price of $2.50 per mcf.

The company's crude oil hedging positions were as follows:

The company's natural gas hedging positions were as follows:

The company's natural gas liquids hedging positions were as follows:

SOURCE Chesapeake Energy Corporation

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