Chesapeake Energy Corporation Reports 2019 First Quarter Financial And Operational Results

OKLAHOMA CITY, May 8, 2019 /PRNewswire/ -- Chesapeake Energy Corporation (NYSE:CHK) today reported financial and operational results for the 2019 first quarter. Highlights include:

• Early Brazos Valley (BVL) Success: Eliminated approximately $500,000 in costs per well since February 1, 2019, with additional savings forecasted by year-end, driven by faster drilling and more fracture stimulation stages completed per day; have achieved savings of over $1 million per well on certain individual wells; early production from first proprietary wells above expectations.
• On Track to Deliver Transformational Oil Growth in 2019: Driven by shallower production declines in South Texas due to well spacing and base production improvements and continued improvement in the Powder River Basin (PRB), which achieved record production during the quarter and again in the month of April 2019, the company remains on track to deliver oil growth of approximately 32% with a year-end oil mix of approximately 26%.
• Average Oil Production of Approximately 109,000 Barrels (Bbls) per Day: Year-over-year absolute growth of 18%, or 13% adjusted for asset purchases and sales, and approximately 22% of total net daily production.
• Average Production of Approximately 484,000 Barrels of Oil Equivalent (Boe) per Day
• Continued Shift to Higher Oil Mix and Focus on Reducing Expenses Results in Highest Operating Margin per Boe Since 2014

Doug Lawler, Chesapeake's President and Chief Executive Officer, commented, "We continue to execute on our strategic priorities and once again delivered strong financial and operational results. The encouraging early results from our Brazos Valley business unit, which we now project will be cash flow positive at the asset operating level in 2019, demonstrates our capability to apply our capital and operating efficiency to immediately transform a new asset in our portfolio. We believe we will see significantly more savings in the year ahead as we fully integrate our Brazos Valley operations into Chesapeake. With our transformational oil growth and capital efficiency continuing to improve, our confidence is strong as we drive towards achieving our strategic priorities of meaningful margin enhancement, sustainable free cash flow and a net debt to EBITDAX ratio of two times."

2019 First Quarter Results

Average daily production for the 2019 first quarter was approximately 484,000 boe and consisted of approximately 109,000 bbls of oil, 2.023 billion cubic feet (bcf) of natural gas and 39,000 bbls of natural gas liquids. Average daily production for the 2018 first quarter was approximately 554,000 boe and consisted of approximately 92,000 bbls of oil, 2.466 bcf of natural gas and 51,000 bbls of NGL. Oil production represented approximately 22% of the company's 2019 first quarter aggregate production compared to 17% in the 2018 first quarter.

Chesapeake's operating margin per boe increased significantly in the 2019 first quarter compared to the 2018 first quarter, primarily driven by a higher oil production mix and a decrease in certain of its cash operating expenses (production expenses, gathering, processing and transportation expenses, and general and administrative expenses). Chesapeake reduced its cash operating expenses on an absolute basis by $81 million, or approximately $0.18 per boe, primarily driven by significant reductions in the company's gathering, processing and transportation expenses primarily as a result of certain 2018 divestitures.

In the 2019 first quarter, Chesapeake converted to the successful efforts method of accounting for its oil and natural gas exploration and development activities. See the table below for successful efforts-based financial results and results as calculated under the full cost method.

Reconciliations of financial measures calculated in accordance with GAAP to non-GAAP measures and pro forma comparisons to the previously employed method of accounting are provided on pages 14-21 of this release.

Capital Spending Overview

Chesapeake incurred total capital expenditures of approximately $559 million during the 2019 first quarter, including capitalized interest of $6 million, compared to approximately $543 million in the 2018 first quarter. The increase in capital expenditures in the 2019 first quarter was largely attributable to a higher average rig count and an increase in gross wells spud, completed and connected. A summary is provided in the table below.

Balance Sheet and Liquidity

As of March 31, 2019, Chesapeake's principal amount of debt outstanding inclusive of BVL debt was approximately $9.978 billion, compared to $8.168 billion as of December 31, 2018. The increase in debt outstanding was largely a result of $1.375 billion in debt assumed by Chesapeake as part of the WildHorse acquisition on February 1, 2019. As of March 31, 2019, under the $3.0 billion Chesapeake credit facility, the company had borrowed $842 million, utilized approximately $61 million for various letters of credit and had additional borrowing capacity of approximately $2.097 billion. Under the $1.3 billion BVL credit facility, BVL had borrowed $688 million, utilized approximately $47 million for a letter of credit and had additional borrowing capacity of approximately $565 million.

On April 3, 2019, Chesapeake exchanged approximately $919 million of new 8.0% Senior Notes due 2026 for approximately $884 million aggregate principal amount of its Senior Notes due 2020 and 2021. On April 15, 2019, Chesapeake repaid at maturity approximately $380 million of its Floating Rate Senior Notes due 2019.

Chesapeake has a robust hedge portfolio in place for 2019 to reduce its future revenue risk. As of May 3, 2019, including April and May derivative contracts that have settled, approximately 70% of the company's 2019 forecasted oil, natural gas and NGL production revenue was hedged, including approximately 70% and 80% of its remaining 2019 forecasted oil and natural gas production at average prices of $58.75 per bbl and $2.83 per thousand cubic feet (mcf), respectively. Additionally, Chesapeake has basis protection on approximately 6 million barrels (mmbbls) of its remaining projected 2019 Eagle Ford oil production at a premium to WTI of approximately $5.69 per bbl.

Operations Update

Chesapeake's average daily production for the 2019 first quarter was approximately 484,000 boe compared to approximately 554,000 boe in the 2018 first quarter. The following tables show average daily production and average daily sales prices received (excluding gains/losses on derivatives) by the company's operating areas for the 2019 and 2018 first quarters.

Brazos Valley

The company's new business unit, which operates in the northern part of the Eagle Ford Shale and Austin Chalk Trend located primarily in Burleson, Lee and Washington counties in Texas, has already seen significant operational improvements since the company's acquisition closed on February 1, 2019. Within the first two months of owning the asset, Chesapeake has dramatically improved cycle times with faster drilling and more fracture stimulation stages completed per day, resulting in significant cost reductions. Through the first two months of operations, the company has already realized savings of approximately $500,000 per well due to improved drilling and completion techniques, supply chain and logistics synergies and the switch to regional sand sourced from its wholly owned sand mine in Burleson County that commenced operations in February 2019. Additional cost savings have been identified and the company expects the per-well savings to increase throughout the year.

On the company's Eagle Ford Easy Rider pad located in Burleson County, Chesapeake initiated its first choke management test in the area yielding significantly improved results. With completed laterals of approximately 7,500 feet, the pad's two wells achieved 24-hour peak oil production rates of 898 bbls per day and 1,546 bbls per day, respectively, demonstrating an approximate 35% uplift to historical type curve estimates from the area.

Additionally, Chesapeake has drilled and completed its first set of proprietary Eagle Ford wells on the Bell pad located in Burleson County. These four wells were completed with decreased fluid volumes (8,000 bbls per stage compared to 10,000 to 12,000 bbls per stage previously) and were placed on production in April 2019. While the average production rate from the pad is still climbing, the pad has already achieved a peak 24-hour oil production rate of 2,723 bbls of oil. These results are encouraging as the company optimizes fracture stimulations with lower fluids and higher sand volumes, simultaneously reducing costs and increasing productivity.

The company is currently utilizing four rigs in the area, placed 13 wells on production (five gas wells and eight oil wells) during the 2019 first quarter and expects to place 27 wells on production (four gas wells and 23 oil wells) during the 2019 second quarter. Included in the company's first quarter capital program were wells in the process of being completed in the gas window of the Austin Chalk play at the time of the closing of the acquisition. The company has since moved all four rigs to the oil and volatile oil windows of the Eagle Ford due to better economics and oil volumes. Chesapeake now anticipates its 2019 drilling program will average a lateral length of approximately 9,000 feet per well, representing a 27% increase over 2018 levels. The combination of longer laterals, optimized completions and effective flow back procedures have already delivered significant improvements in capital efficiency and returns, as expected as part of the company's original acquisition analysis, with more improvements expected in the next few months.

Eagle Ford Shale

In the company's Eagle Ford Shale position in South Texas, Chesapeake continues to generate free cash flow through steady oil volume production. Well performance has been especially strong due to optimized well spacing, enhanced completion designs and base production improvements resulting in consistent, high-margin oil volumes and markedly shallower production declines. Additional base production management efforts are expected throughout the year. Chesapeake is currently utilizing four rigs in South Texas, placed 29 wells on production during the 2019 first quarter and expects to place 16 wells on production during the 2019 second quarter.

The company is able to access Gulf Coast premium markets resulting in higher realized crude oil pricing for both its Brazos Valley and legacy Eagle Ford areas, contributing to higher margins. The company has protected a portion of this pricing advantage with basis hedges on approximately 6 mmbbls of remaining projected 2019 oil production at a premium to WTI of approximately $5.69 per bbl.

Powder River Basin

As a part of its ongoing portfolio optimization, Chesapeake has recently shifted a portion of its planned capital dollars from its Marcellus Shale and Mid-Continent areas to the PRB, where the company has recently moved a sixth rig. While all six rigs are currently drilling in the Turner formation, the company will transition one of the rigs to selectively drill Niobrara wells later in the year.

Average net production from the PRB for the 2019 first quarter was approximately 36,000 boe per day, including 16,000 bbls of oil, after experiencing several significant downtime events due to winter weather. Average net production from the PRB for the month of April was approximately 39,000 boe per day, including 18,000 bbls of oil and, as of May 1, 2019, the company set a new production record of approximately 42,000 boe per day, including 20,000 bbls of oil. The company placed 13 wells on production during the 2019 first quarter and expects to place 15 wells on production during the 2019 second quarter. As a result of the additional capital allocated to the PRB, the company now expects to place an additional eight wells to sales during the 2019 third and fourth quarters than initially forecasted.

Chesapeake recently achieved a new record-setting Turner oil well, the RRC 5-34-70 USA B TR 21H, which reached a peak rate of approximately 4,000 boe per day (75% oil) on May 4, 2019, while flowing at 2,000 psi wellhead pressure on a 48/64 inch choke. The company is encouraged by the exceptional well results in this area and expects continued success in the 2019 development program.

In May 2019, Chesapeake began connecting pads into a new oil gathering pipeline system which will transport volumes to Guernsey, Wyoming. The company expects the system to be fully operational across the field by June 2019, resulting in significant cost savings and improved certainty of delivery compared to trucking volumes. Chesapeake will use this new gathering system as an entry point into interstate pipelines and is working to deliver these volumes both to Cushing, Oklahoma beginning this summer and to Gulf Coast premium markets at Corpus Christi beginning in late 2020.

Marcellus Shale

Chesapeake continues to generate significant free cash flow in the Marcellus Shale in northeast Pennsylvania, primarily driven by strong realized in-basin gas prices and record production from improved well productivity through enhanced completions and longer laterals. Chesapeake achieved a record daily gross production level of approximately 2.5 bcf of gas per day in January 2019, resulting in record average net production of 948 mcf of gas per day during the 2019 first quarter. The company is currently utilizing three rigs but plans to move to two rigs by the end of June 2019. Chesapeake placed nine wells on production during the 2019 first quarter and expects to place 14 wells on production during the 2019 second quarter.

Haynesville Shale

In the Haynesville Shale in Louisiana, Chesapeake expects to decrease its activity throughout the year, moving from two rigs to one rig by the end of May 2019. The company placed ten wells on production in the Haynesville Shale during the 2019 first quarter and expects to place nine wells on production during the 2019 second quarter.

Mid-Continent

In the company's Mid-Continent operating area in Oklahoma, Chesapeake dropped its only rig in May 2019. The company placed nine wells on production during the 2019 first quarter and expects to place five wells on production during the 2019 second quarter. The company expects to increase activity in the Mid-Continent area in 2020, after newly acquired 3D seismic has been interpreted and its drilling inventory has been high-graded.

Key Financial and Operational Results

The table below summarizes Chesapeake's key financial and operational results during the 2019 first quarter as compared to results in prior periods. The three months ended March 31, 2019 include two months of Brazos Valley operations. The three months ending March 31, 2018 do not include Brazos Valley operations.

2019 First Quarter Financial and Operational Results Conference Call Update

The conference call to discuss the company's financial and operational results has been scheduled on Wednesday, May 8 at 9:00 am EDT. The telephone number to access the conference call is 877-870-4263 or 1-412-317-0790 for international callers. The passcode for the call is 4269013. 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, expected lateral lengths of wells, anticipated timing of wells to be placed into production, anticipated timing of the Brazos Valley business unit becoming cash flow positive, general and administrative expenses, 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 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.