Chesapeake Energy Corporation Reports 2019 Third Quarter Financial And Operational Results, Maintains 2019 Guidance And Announces Plans To Reduce 2020 Capital Budget

OKLAHOMA CITY, Nov. 5, 2019 /PRNewswire/ -- Chesapeake Energy Corporation (NYSE:CHK) today reported financial and operational results for the 2019 third quarter. Highlights include:

• Maintaining 2019 Production and Capital Expenditure Guidance:
• 2019 fourth quarter oil production projected to increase approximately 10% over 2019 third quarter levels
• Brazos Valley sets net average oil production record of approximately 40,000 barrels (bbls) of oil per day for the month of October 2019; continue to deliver capital and operating costs ahead of projected synergies
• Powder River Basin (PRB) Turner well costs down approximately 10% year to date; first Niobrara well drilled and completed since 2014 produces more than 100,000 bbls of oil in first 87 days
• Continuing Progress on Prudently Managing Balance Sheet and Cash Costs:
• Recently re-affirmed borrowing base of Chesapeake credit facility
• Exchanged $693 million of Senior Notes and $40 million of preferred shares for 319 million common shares at an average discount of approximately 25%, reducing annual interest and preferred dividend payments
• Restructured gas gathering and crude oil transportation contracts in South Texas and Brazos Valley, improving future returns
• Reducing 2020 Capital Expenditure Forecast by Approximately 30%, Targeting Free Cash Flow:
• Anticipate flat oil production year over year, utilizing 10 to 13 rigs with projected total capital expenditures of approximately $1.3 to $1.6 billion, contingent upon commodity prices
• Expect to reduce 2020 production and general and administrative (G&A) expenses by approximately 10%

Doug Lawler, Chesapeake's President and Chief Executive Officer, commented, "We are pleased with our execution this quarter as we continue to successfully integrate and realize value from our Brazos Valley acquisition and maximize cash flow from our oil assets while reducing capital directed to our natural gas assets. We expect our oil production to grow approximately 10% in the fourth quarter, compared to the third quarter, and we remain on track to meet our 2019 total production and capital expenditure guidance. Our capital efficiency improvements, expected reduction in cash costs and anticipated capital plan position us to target free cash flow in 2020."

2019 Third Quarter Results

For the 2019 third quarter, Chesapeake reported a net loss of $61 million and a net loss available to common stockholders of $101 million, or $0.06 per diluted share.  Adjusting for items typically excluded by securities analysts, the 2019 third quarter adjusted net loss attributable to Chesapeake was $188 million, or $0.11 per share, while adjusted EBITDAX was $577 million. Reconciliations of financial measures calculated in accordance with GAAP to non-GAAP measures are provided on pages 16 - 20 of this release.

Average daily production for the 2019 third quarter was approximately 478,000 barrels of oil equivalent (boe), representing year-over-year growth of 3% adjusted for asset purchases and sales, and consisted of approximately 115,000 bbls of oil, 1.989 billion cubic feet (bcf) of natural gas and 32,000 bbls of natural gas liquids (NGL). Average daily production for the 2018 third quarter was approximately 537,000 boe and consisted of approximately 89,000 bbls of oil, 2.332 bcf of natural gas and 59,000 bbls of NGL. Oil production represented approximately 24% of the company's 2019 third quarter aggregate production, compared to 17% in the 2018 third quarter.

Despite lower average prices for our oil, natural gas and NGL sold, Chesapeake's operating margin remained flat in the 2019 third quarter, compared to the 2018 third quarter, due to an increase in oil production mix and a decrease in cash costs. Gathering, processing and transportation and G&A expenses decreased by $109 million, or approximately $1.39 per boe, while production expense increased $23 million, or $0.86 per boe, when compared to the same quarter in 2018.

Capital Spending Overview

Chesapeake invested total capital expenditures of approximately $640 million during the 2019 third quarter, including capitalized interest of $6 million, compared to approximately $551 million in the 2018 third quarter. The increase in capital expenditures in the 2019 third quarter was largely attributable to an increase in net wells spud, completed and connected.  See tables below for a summary of activity and expenditures.

Balance Sheet and Liquidity

As of September 30, 2019, Chesapeake's principal amount of debt outstanding inclusive of Brazos Valley debt was approximately $9.732 billion, compared to $8.168 billion as of December 31, 2018. As of September 30, 2019, the company had borrowed $1.504 billion under the $3.0 billion Chesapeake credit facility, utilized approximately $53 million for various letters of credit, and had additional borrowing capacity of approximately $1.443 billion. Under the $1.3 billion Brazos Valley credit facility, the company had borrowed $900 million and had additional borrowing capacity of approximately $400 million. The borrowing base of the Chesapeake credit facility was re-affirmed in November 2019 and the redetermination process for the Brazos Valley credit facility is scheduled for the 2019 fourth quarter.

During the 2019 third quarter, Chesapeake exchanged approximately 319 million common shares for various series of Senior Notes and preferred shares totaling a principal amount of approximately $733 million. The company expects approximately $45 million in interest savings in 2020 as a result of these transactions. The company believes these transactions, together with its planned reduction in capital expenditures in 2020 and other efficiency measures, will reduce its debt levels and improve the ratios under the covenants in the company's revolving credit facility.

As of October 31, 2019, including October and November derivative contracts that have settled, approximately 80% of the company's remaining 2019 forecasted oil, natural gas and NGL production revenue was hedged, including approximately 74% and 75% of its remaining 2019 forecasted oil and natural gas production at average prices of $59.34 per bbl and $2.83 per thousand cubic feet (mcf), respectively. Additionally, Chesapeake has basis protection swaps on approximately 2 million barrels (mmbbls) of its remaining projected 2019 Eagle Ford oil production at a premium to WTI of approximately $5.67 per bbl.

In 2020, Chesapeake currently has downside protection on a portion of its 2020 projected oil production at an average price of $59.28 per bbl and on a portion of its 2020 projected gas production at an average price of $2.76 per mcf.

Operations Update and Highlights

Chesapeake's average daily production for the 2019 third quarter was approximately 478,000 boe compared to approximately 537,000 boe in the 2018 third quarter. The following tables show average daily production and average sales prices received (excluding gains/losses on derivatives) by the company's operating areas for the 2019 and 2018 third quarters.

Brazos Valley: Sets new production record

In Chesapeake's Brazos Valley area in central Texas, the company is currently utilizing four rigs and placed 25 wells on production during the 2019 third quarter, 14 of which were placed on production in the last five weeks of the quarter. As a result, the company set a new net oil production record for the month of October 2019 of approximately 40,000 bbls of oil per day, exceeding the monthly production record set by the previous operator in November 2018 while utilizing five rigs. The increase was also driven by improvements to the field's base decline through its well optimization and workover program.

As the company's subsurface understanding evolves, the commercial black oil area of the field continues to expand, further strengthening the inventory of the future drilling program. Since February 1, 2019, the company has placed 13 wells on production which have reached peak 24-hour rates of more than 1,000 bbls of oil per day. The company anticipates placing 20 wells on production in the 2019 fourth quarter.

Chesapeake continues to improve operational efficiencies in its Brazos Valley development program, resulting in a 21% decrease in completed well costs to approximately $830 per foot, and extending its average completed lateral length per well drilled to more than 9,000 feet.

Eagle Ford Shale: Gas gathering and crude oil transportation restructuring provides improved long term field economics, production anticipated to ramp in the fourth quarter

In the company's South Texas Eagle Ford asset, 2019 third quarter volumes were projected to represent the low for the year primarily due to timing of the company's development plan and longer cleanup periods associated with that development. Of the 47 wells Chesapeake placed on production during the 2019 third quarter, 46 were put to sales in August and September. The company is currently running four rigs in South Texas and anticipates placing 41 wells on production in the 2019 fourth quarter.

Additionally, Chesapeake continues to optimize its midstream and downstream commitments and has recently successfully restructured its gas gathering and crude transportation commitments in the Eagle Ford. These agreements allow the company to move away from a cost-of-service mechanism to fixed-fee gathering rate structures, as well as maximize its pipeline commitments going forward.

Powder River Basin: Turner capital efficiency continues to advance and first Niobrara well drilled since 2014 delivers record results

Chesapeake continues to recognize operational efficiencies in the Turner sandstone formation which have driven costs out of its operations, including reductions in cycle times by 25% year over year and in average drilling and completion costs by approximately $800,000, or 10%, per well through the first nine months of 2019 compared to 2018 results. These efficiency enhancements have resulted in a recent four-well Turner pad being drilled and completed for approximately $6.0 million per well, with the last 25 wells turned to sales averaging approximately $7.2 million per well.

While the Turner sandstone formation has been Chesapeake's primary focus in its PRB development program, the company remains enthusiastic about the stacked pay potential in the basin. The company recently placed on production its first Niobrara well since 2014, and in the first 87 days it has produced approximately 106,500 bbls of oil, reaching a 24-hour peak rate of greater than 1,600 bbls of oil per day. The company currently plans to drill and complete four additional Niobrara wells in 2019 and expects that more than 25% of its projected 2020 capital program will be targeting the Niobrara formation. The company is currently utilizing four rigs in the PRB, placed 26 wells on production in the 2019 third quarter and anticipates placing 17 wells on production in the 2019 fourth quarter.

Production volumes in the 2019 third quarter were less than expected, primarily driven by the impact from a group of nine wells placed on production earlier in the year in the northern edge of Chesapeake's Turner acreage. These isolated wells encountered poorer reservoir quality, resulting in lower than expected performance compared to other company-operated wells in the rest of the field. Production volumes were also negatively impacted by unplanned outages due to electrical power issues that interrupted portions of the field's midstream system. The company is working with local utility companies and its midstream partners to ensure reliable power to support all production, gathering and transportation systems.

Marcellus Shale: Recent well performance highlights capital efficiency gains

In the Marcellus Shale, the company continues its strategy of maintaining its operated production to capture the value from seasonal basin congestion and pricing, while achieving lower costs and capital requirements due to the strong performance of recent wells. Wider spacing averaging approximately 1,350 feet between well bores, fit-for-purpose modern completions and improved cycle times continue to yield impressive results for Chesapeake in the Marcellus Shale, with six wells recently turned to sales reaching peak 24-hour flow rates between 60 million cubic feet (mmcf) of gas per day to a record 85 mmcf per day. The company is currently utilizing two rigs in the Marcellus, placed 17 wells on production in the 2019 third quarter and anticipates placing four wells on production in the 2019 fourth quarter.

Haynesville Shale, Mid-Continent: Allocating capital to higher-return areas in 2020

In the Haynesville Shale in Louisiana, Chesapeake placed five wells on production during the 2019 third quarter. The company has released its operated rigs and completion crews in both the Haynesville Shale and Mid-Continent areas for the rest of the year.

Key Financial and Operational Results

The table below summarizes Chesapeake's key financial and operational results during the 2019 third quarter as compared to results in the same quarter in 2018. The three months ended September 30, 2019 include Brazos Valley operations. The three months ended September 30, 2018 do not include Brazos Valley operations.

2019 Third Quarter Financial and Operational Results Conference Call Update

The conference call to discuss the company's financial and operational results has been scheduled on Tuesday, November 5 at 9:00 am EDT. The telephone number to access the conference call is 1-888-317-6003 or 1-412-317-6061 for international callers. The passcode for the call is 2440889. 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, cost-cutting measures, reductions in expenditures, proposed refinancing transactions, capital exchange transactions, asset divestitures, reductions in capital expenditures, operational efficiencies, production and well connection forecasts, estimates of operating costs, anticipated capital and operational efficiencies, planned development drilling and expected drilling cost reductions, expected lateral lengths of wells, anticipated timing and number of wells to be placed into production, expected oil growth trajectory, anticipated timing of execution of new gathering agreement, expected savings in connection with new oil gathering and pipeline agreements, projected capital expenditures, 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 our ability to comply with the covenants under our revolving credit facilities and other indebtedness and the related impact on our ability to continue as a going concern, 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.