Chesapeake Energy Corporation Reports 2018 Full Year And Fourth Quarter Results And Announces 2019 Guidance

OKLAHOMA CITY, Feb. 27, 2019 /PRNewswire/ -- Chesapeake Energy Corporation CHK today reported financial and operational results for the 2018 full year and fourth quarter. Highlights include:

2018 Results:

• Portfolio evolution drives improved returns and leverage reduction: Divested lower-margin Utica and Mid-Continent assets and expanded higher-margin oil growth platform through strategic focus on the Powder River Basin (PRB) and announcement of the acquisition of WildHorse Resource Development Corporation (WildHorse); overall total debt reduction of $1.8 billion as of December 31, 2018, including the elimination of $2.6 billion in secured debt;
• Oil production growth: 2018 average daily oil production of approximately 90,000 barrels (bbls), up 10 percent compared to 2017 levels, adjusted for asset sales; December 2018 oil production equaled 21 percent of total production mix;
• Highest margins since 2014: 2018 net income available to common stockholders of $775 million, or $0.85 per diluted share; 2018 adjusted net income attributable to Chesapeake of $816 million, or $0.90 per diluted share; 2018 fourth quarter net income available to common stockholders of $486 million, or $0.49 per diluted share; 2018 fourth quarter adjusted net income attributable to Chesapeake of $238 million, or $0.21 per diluted share; highest adjusted EBITDA generated per barrel of oil equivalent (boe) of $12.81 since 2014.

2019 Outlook:

• Transformational oil growth: Projected 2019 average daily oil production of approximately 116,000 to 122,000 bbls, an absolute increase of approximately 32 percent (or 50 percent adjusted for asset sales), driven by the acquisition of the WildHorse asset and organic growth from the PRB; oil mix projected to be approximately 26 percent by 2019 fourth quarter;
• Capital expenditure program discipline: Projected 2019 capital expenditures range from $2.3 to $2.5 billion, effectively flat compared to $2.366 billion in 2018;
• Lower costs lead to improved capital efficiency and enhanced competitiveness: Cash costs projected to decrease by approximately $200 million, driven by lower gathering, processing and transportation (GP&T) expenses partially offset by slightly higher production and general and administrative expenses as a result of production and working interest mix; EBITDA generated per boe projected to increase by approximately 12 to 15 percent, based on recent strip prices.

Doug Lawler, Chesapeake's President and Chief Executive Officer, commented, "I am very pleased with Chesapeake's operational and financial performance in 2018. Two transformational business transactions not only serve as a significant inflection point for the company, but also provide foundational support in our strategic goals of further reducing our net debt, achieving sustainable positive free cash flow, and enhancing margins. The recent acquisition of WildHorse, which we refer to as our Brazos Valley business unit, provides significant profitability, flexibility and optionality to our diverse, deep asset portfolio and facilitates our achieving these strategic goals.

"Over the past five years, we have clearly established our operational and capital efficiency leadership.  We have also materially improved our financial leverage and significantly reduced our obligations, commitments and complexity. Our 2018 accomplishments of 10 percent adjusted oil growth, improved realizations and lower absolute cash costs compared to 2017 resulted in the highest EBITDA generated per boe for Chesapeake since 2014, when oil averaged more than $90 per barrel and gas averaged more than $4 per thousand cubic feet. Our strategic focus on increasing our oil production is working, as we increased annual net oil volumes from the PRB by 78 percent in 2018, resulting in oil production representing 21 percent of our overall production mix in December. Our oil focus will be fully evident in 2019, as annual net oil volumes from the PRB are expected to more than double compared to 2018 and as we begin a robust drilling program on our Brazos Valley asset, while also attacking the base production in all our operating areas with full-field optimization and downtime reduction programs. As a result, we project our average oil mix to be approximately 24 percent of total volumes in 2019 compared to 17 percent in 2018, with our year-end 2019 oil mix approaching 26 percent.

"We are off to a fast start in 2019. With the integration of the Brazos Valley asset into Chesapeake fully underway, we are already seeing a significant amount of cost savings to be captured and strong performance from the asset. The Brazos Valley asset had very strong 2018 fourth quarter performance, with production, capital expenditures and cash flow better than we had originally projected at the time of the acquisition announcement.

"At today's strip pricing, we expect our cash flow to be meaningfully stronger in 2019, as we continue to leverage our strength in capital efficiency and cash cost leadership. Chesapeake's progress, portfolio and strategic plan provides a compelling investment opportunity and we look forward to driving differential value for our shareholders in the year ahead."

2018 Full Year Results

For the 2018 full year, Chesapeake reported net income of $877 million and net income available to common stockholders of $775 million, or $0.85 per diluted share, compared to $953 million, $813 million, and $0.90 in 2017, respectively.  The company's EBITDA for the 2018 full year was $2.499 billion, compared to $2.376 billion in 2017. Adjusting for items that are typically excluded by securities analysts, the 2018 full year adjusted net income attributable to Chesapeake was $816 million, or $0.90 per diluted share, compared to $742 million, or $0.82 per diluted share in 2017, while the company's adjusted EBITDA was $2.436 billion, compared to $2.160 billion in 2017. Reconciliations of financial measures calculated in accordance with GAAP to non-GAAP measures are provided on pages 14 - 17 of this release.

Average daily production for 2018 of approximately 521,000 boe increased by 4 percent compared to 2017 levels, adjusted for asset sales, and consisted of approximately 90,000 bbls of oil, 2.278 billion cubic feet (bcf) of natural gas and 52,000 bbls of NGL.

Production expenses in 2018 were $2.84 per boe, compared to $2.81 per boe in 2017. The per unit increase was the result of increased ad valorem tax primarily due to higher prices received for the company's oil, natural gas and NGL production. General and administrative expenses (including stock-based compensation) in 2018 were $1.47 per boe, compared to $1.31 per boe in 2017. 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 2018 and 2017.

2018 Fourth Quarter Results

For the 2018 fourth quarter, Chesapeake reported net income of $514 million and net income available to common stockholders of $486 million, or $0.49 per diluted share, compared to $334 million, $309 million, and $0.33 in the 2017 fourth quarter, respectively. The company's EBITDA for the 2018 fourth quarter was $910 million, compared to $764 million in the 2017 fourth quarter. Adjusting for items that are typically excluded by securities analysts, the 2018 fourth quarter adjusted net income attributable to Chesapeake was $238 million, or $0.21 per diluted share, compared to $314 million, or $0.30 per diluted share in the 2017 fourth quarter. The company's adjusted EBITDA was $574 million in the fourth quarter of 2018, compared to $706 million in the fourth quarter of 2017. Reconciliations of financial measures calculated in accordance with GAAP to non-GAAP measures are provided on pages 14 - 17 of this release.

Average daily production for the 2018 fourth quarter was approximately 464,000 boe, a 7 percent decrease compared to 2017 levels, adjusted for asset sales, and consisted of approximately 87,000 bbls of oil, 2.009 bcf of natural gas and 42,000 bbls of NGL.

Production expenses during the 2018 fourth quarter were $2.87 per boe, compared to $2.50 per boe in the 2017 fourth quarter. The increase was primarily a result of certain 2018 and 2017 divestitures and increased ad valorem tax due to higher prices received for the company's oil, natural gas and NGL production. General and administrative expenses (including stock-based compensation) during the 2018 fourth quarter were $1.19 per boe, compared to $1.34 per boe in the 2017 fourth quarter. The decrease was primarily due to lower compensation expenses, partially offset by less overhead allocated to production expenses, marketing expenses and capitalized general and administrative costs. The company's GP&T expenses increased to $7.92 per boe from $7.15 per boe during the 2017 fourth quarter, primarily due to a shortfall payment for Eagle Ford oil transportation volumes.

Capital Spending Overview

Chesapeake's total capital investments were approximately $541 million during the 2018 fourth quarter and $2.366 billion during the 2018 full year, compared to approximately $523 million and $2.458 billion in the 2017 fourth quarter and 2017 full year, respectively. A summary of the company's 2018 and 2017 capital expenditures, as well as the current 2019 capital expenditure guidance, is provided in the table below.

Balance Sheet and Hedge Position Update

As of December 31, 2018, Chesapeake's principal amount of debt outstanding was approximately $8.168 billion, compared to $9.981 billion as of December 31, 2017, including $419 million drawn under its senior secured revolving bank credit facility. As of December 31, 2018, Chesapeake had utilized approximately $107 million for various letters of credit and had borrowing capacity of approximately $2.474 billion under the $3.0 billion Chesapeake senior secured revolving credit facility.

On February 1, 2019, Chesapeake acquired approximately $1.4 billion principal amount of debt upon the closing of the Brazos Valley asset (including $675 million drawn under the Brazos Valley senior secured revolving credit facility). The company had approximately $47 million of letters of credit issued and borrowing capacity of approximately $578 million under the $1.3 billion Brazos Valley senior secured revolving credit facility.

Chesapeake has a robust hedge portfolio in place for 2019 to prudently reduce its future revenue risk. As of February 22, 2019, including January and February derivative contracts that have settled, approximately 63 percent of the company's 2019 forecasted oil, natural gas and NGL production revenue was hedged, including approximately 56 percent and 81 percent of its 2019 forecasted oil and natural gas production (including Brazos Valley production from February 1, 2019) at average prices of $57.12 per bbl and $2.85 per thousand cubic feet (mcf), respectively. Additionally, Chesapeake has basis protection on approximately 7 million barrels (mmbbls) of its projected 2019 Eagle Ford oil production at a premium to WTI of approximately $6.01 per bbl.

Operations Update

Chesapeake's average daily production for the 2018 full year was approximately 521,000 boe compared to approximately 548,000 boe in the 2017 full year. A summary of the company's 2018 average daily production and average daily sales prices received by operating divisions can be found in the company's Form 10-K.

Chesapeake's average daily production for the 2018 fourth quarter was approximately 464,000 boe compared to approximately 593,000 boe in the 2017 fourth quarter. The following table shows average daily production and average daily sales prices received by the company's operating divisions for the 2018 fourth quarter and the 2017 fourth quarter.

In the PRB, average daily net production increased approximately 70 percent in 2018 to 25,100 boe compared to 14,800 boe in 2017, as total net annual production increased to 9.2 million barrels of oil equivalent (mmboe) from 5.4 mmboe in 2017. Currently, the company expects total net annual production from the PRB to double in 2019 compared to 2018.

Chesapeake is operating five rigs in the PRB, all of which are currently drilling the Turner formation. Several records were achieved in the PRB during the 2018 fourth quarter, including the fastest per lateral foot drilling time in the Turner formation from spud to total depth of 18.5 days for the BB 2-35-71 USA A TR 18H well with a drilled lateral length of approximately 10,100 feet. Chesapeake also recorded its highest producing oil well to date, including the SFU 7-34-71 USA A TR 20H well which was placed on production in November 2018 and recorded a 24-hour oil volume of 2,387 bbls (78 percent oil, or 3,068 boe).

In 2019, Chesapeake is moving to development mode in the Turner formation, moving to central production facilities which will handle up to 30,000 bbls of oil per day, consolidating drilling activity to the more economic oil window located primarily in the northern and western part of the play where there tends to be lower gas-to-oil ratios. As a result, the company expects to double its oil production from the PRB in 2019 by placing up to 64 Turner wells on production, compared to 32 Turner wells in 2018 and its first three wells drilled in the formation in 2017. While the primary focus of the 2019 PRB program will be on the Turner formation, the team will continue appraisal work on the Niobrara and other horizons across the basin.

Driven by the increase in oil volumes the company is projecting going forward, Chesapeake signed an oil gathering agreement during the 2018 fourth quarter that will deliver its oil volumes via pipelines into the Guernsey, Wyoming market at a substantially lower cost than the company was incurring by trucking volumes. This oil gathering system will also connect directly to interstate pipelines with available capacity to the Cushing, Oklahoma market and further to Gulf Coast premium markets, providing additional takeaway options to Chesapeake in the future as basin production grows.

In the company's legacy Eagle Ford Shale position in south Texas, Chesapeake is currently utilizing four drilling rigs and expects to place on production up to 125 wells in 2019, compared to 157 wells in 2018. Of the wells planned for 2019, Chesapeake expects to test up to 10 Upper Eagle Ford and Austin Chalk wells. The company continues to focus on its base production and has implemented new field technologies to reduce downtime across the field. As a result, Chesapeake recorded a 17 percent reduction in controllable down volumes per day in 2018, which equated to an additional 1,100 barrels of oil sold every day. The company's significantly higher margins in the Eagle Ford are primarily driven by premium Gulf Coast crude oil pricing and are further protected with basis hedges on approximately 7 mmbbls of projected 2019 Eagle Ford oil production at a premium to WTI of approximately $6.00 per bbl.

The company's Brazos Valley business unit will be focused on targeting both Eagle Ford and Austin Chalk wells in the large acreage position gained in the WildHorse acquisition. Chesapeake will operate four rigs in the Brazos Valley area in 2019 and expects to place on production up to 83 wells, including 10 wells targeting the Austin Chalk formation, with average completed lateral lengths of approximately 8,000 feet. The business unit is aggressively attacking numerous opportunities to drive capital efficiencies across all areas of the value chain. Through a combination of operational improvements and supply chain savings, the team has implemented and negotiated approximately $200,000 to $350,000 per well in capital savings within the first month of taking over operations. Early cycle time improvements have been recognized through increased drilling penetration rates and a two stage per day increase by the completions team. Additionally, the Burleson Sand Mine commenced operations in February 2019 and is anticipated to yield additional savings to the company's completions program.

In the Marcellus Shale in northeast Pennsylvania, Chesapeake is currently utilizing three drilling rigs and expects to place on production up to 48 wells in 2019, compared to 54 wells in 2018. Chesapeake projects to again create significant free cash flow in 2019 as stronger realized in-basin gas prices are expected to continue. Current total gross production from the region is approximately 2.4 bcf per day, after reaching a record 2.5 bcf per day in January 2019. In February 2019, Chesapeake placed two Upper Marcellus wells on production in Susquehanna County that reached a combined peak 24-hour rate of approximately 60 million cubic feet (mmcf) of gas per day. Of the company's 48 wells expected to be placed on production in 2019, seven wells will target the Upper Marcellus formation.

In the company's Haynesville Shale position in Louisiana, Chesapeake is currently utilizing two drilling rigs and intends to drop to one rig in the 2019 second quarter. The company expects to place on production up to 24 wells in 2019, compared to 26 wells in 2018.

In the company's Mid-Continent operating area in Oklahoma, Chesapeake is currently utilizing one drilling rig and expects to place on production 25 wells in 2019, compared to 38 wells in 2018.

2018 Fourth Quarter and Year-End Results Conference Call Information

A conference call to discuss this release has been scheduled on Wednesday, February 27, 2019 at 9:00 am EST. The telephone number to access the conference call is 334-323-0522 or toll-free 877-260-1479. The passcode for the call is 1327759. 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 1327759. 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 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.