The fair value of our derivatives is based on third-party pricing models, which utilize inputs that are either readily available in the public market, such as oil, natural gas, oil and NGL forward curves and discount rates, or can be corroborated from active markets or broker quotes.quotes, and, as such, are classified as Level 2. These values are compared to the values given by our counterparties for reasonableness. Since oil, natural gas, NGL and cross currency swaps do not include optionality and therefore generally have no unobservable inputs, they are classified as Level 2. All other derivatives have some level of unobservable input, such as volatility curves, and are therefore classified as Level 3. Derivatives are also subject to the risk that either party to a contract will be unable to meet its obligations. We factor non-performance risk into the valuation of our derivatives using current published credit default swap rates. To date, this has not had a material impact on the values of our derivatives.
ContentsCHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
On October 12, 2017, we issued in a private placement $300 million aggregate principal amount of 8.00% Senior Notes due 2025 (New 2025 Notes) at 101.25% of par, plus accrued interest from July 15, 2017, and $550 million aggregate principal amount of 8.00% Senior Notes due 2027 (New 2027 Notes) at 99.75% of par, plus accrued interest from June 6, 2017. The New 2025 Notes are an additional issuance of our outstanding 8.00% Senior Notes due 2025, which we issued in December 2016 in an original aggregate principal amount of $1.0 billion. The New 2025 Notes issued and the previously issued senior notes due 2025 will be treated as a single class of notes under the indenture. The New 2027 Notes are an additional issuance of our outstanding 8.00% Senior Notes due 2027, which we issued in June 2017 in an original aggregate principal amount of $750 million. The New 2027 Notes issued and the previously issued senior notes due 2027 will be treated as a single class of notes under the indenture. Aggregate net proceeds from the issuance of the New 2025 Notes and New 2027 Notes, excluding the accrued interest received, were approximately $842 million.
On October 13, 2017, we used a portion of the net proceeds from the offering discussed above to finance $550 million in tender offers for certain of our senior notes. We repurchased approximately $320 million principal amount of our 8.00% Senior Secured Second Lien Notes due 2022 for $350 million plus accrued and unpaid interest, approximately $136 million principal amount of our 6.625% Senior Notes due 2020 for $141 million plus accrued and unpaid interest, approximately $51 million principal amount of our 6.875% Senior Notes due 2020 for $53 million plus accrued and unpaid interest, approximately $3 million principal amount of our 6.125% Senior Notes due 2021 for $3 million plus accrued and unpaid interest and approximately $3 million principal amount of our 5.375% Senior Notes due 2021 for $3 million plus accrued and unpaid interest.
In addition, in October 2017, we used additional proceeds from the issuances described above to repurchase approximately $237 million principal amount of our secured term loan due 2021 for $258 million.
On October 30, 2017, the administrative agent under our senior revolving credit facility, in addition to other lenders under the agreement, notified us that the borrowing base had been reaffirmed at $3.8 billion.
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ITEM 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
Financial Data
The following table sets forth certain information regarding our production volumes, oil, natural gas and NGL sales, average sales prices received, and other operating income and expenses for the periods indicated:
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
Net Production: | | | | | | | | |
Oil (mmbbl) | | 8 |
| | 8 |
| | 23 |
| | 25 |
|
Natural gas (bcf) | | 219 |
| | 268 |
| | 639 |
| | 814 |
|
NGL (mmbbl) | | 5 |
| | 6 |
| | 15 |
| | 19 |
|
Oil equivalent (mmboe)(a) | | 50 |
| | 59 |
| | 145 |
| | 180 |
|
Average daily production (mboe) | | 542 |
| | 638 |
| | 532 |
| | 656 |
|
| | | | | | | | |
Oil, Natural Gas and NGL Sales ($ in millions): | | | | | | | | |
Oil sales | | $ | 379 |
| | $ | 342 |
| | $ | 1,140 |
| | $ | 952 |
|
Oil derivatives – realized gains (losses)(b) | | 35 |
| | 18 |
| | 79 |
| | 102 |
|
Oil derivatives – unrealized gains (losses)(b) | | (96 | ) | | 23 |
| | 45 |
| | (217 | ) |
Total oil sales | | 318 |
| | 383 |
| | 1,264 |
| | 837 |
|
Natural gas sales | | 553 |
| | 622 |
| | 1,807 |
| | 1,545 |
|
Natural gas derivatives – realized gains (losses)(b) | | (1 | ) | | (50 | ) | | (53 | ) | | 192 |
|
Natural gas derivatives – unrealized gains (losses)(b) | | (3 | ) | | 131 |
| | 384 |
| | (204 | ) |
Total natural gas sales | | 549 |
| | 703 |
| | 2,138 |
| | 1,533 |
|
NGL sales | | 117 |
| | 84 |
| | 328 |
| | 247 |
|
NGL derivatives – realized gains (losses)(b) | | (3 | ) | | (2 | ) | | (1 | ) | | (5 | ) |
NGL derivatives – unrealized gains (losses)(b) | | (2 | ) | | 9 |
| | (2 | ) | | (2 | ) |
Total NGL sales | | 112 |
| | 91 |
| | 325 |
| | 240 |
|
Total oil, natural gas and NGL sales | | $ | 979 |
| | $ | 1,177 |
| | $ | 3,727 |
| | $ | 2,610 |
|
| | | | | | | | |
Average Sales Price (excluding gains (losses) on derivatives): | | | | | | | | |
Oil ($ per bbl) | | $ | 47.94 |
| | $ | 42.94 |
| | $ | 48.53 |
| | $ | 38.21 |
|
Natural gas ($ per mcf) | | $ | 2.52 |
| | $ | 2.32 |
| | $ | 2.83 |
| | $ | 1.90 |
|
NGL ($ per bbl) | | $ | 21.83 |
| | $ | 13.93 |
| | $ | 21.28 |
| | $ | 12.90 |
|
Oil equivalent ($ per boe) | | $ | 21.06 |
| | $ | 17.86 |
| | $ | 22.53 |
| | $ | 15.27 |
|
| | | | | | | | |
Average Sales Price (including realized gains (losses) on derivatives): | | | | | | | | |
Oil ($ per bbl) | | $ | 52.33 |
| | $ | 45.24 |
| | $ | 51.90 |
| | $ | 42.31 |
|
Natural gas ($ per mcf) | | $ | 2.52 |
| | $ | 2.13 |
| | $ | 2.75 |
| | $ | 2.13 |
|
NGL ($ per bbl) | | $ | 21.26 |
| | $ | 13.70 |
| | $ | 21.21 |
| | $ | 12.66 |
|
Oil equivalent ($ per boe) | | $ | 21.67 |
| | $ | 17.30 |
| | $ | 22.70 |
| | $ | 16.88 |
|
| | | | | | | | |
Other Operating Income ($ in millions): | | | | | | | | |
Marketing, gathering and compression net margin(c)(d) | | $ | (14 | ) | | $ | (162 | ) | | $ | (83 | ) | | $ | (169 | ) |
| | | | | | | | |
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
Expenses ($ per boe): | | | | | | | | |
Oil, natural gas and NGL production | | $ | 3.03 |
| | $ | 2.80 |
| | $ | 2.93 |
| | $ | 3.07 |
|
Oil, natural gas and NGL gathering, processing and transportation | | $ | 7.40 |
| | $ | 8.07 |
| | $ | 7.43 |
| | $ | 7.99 |
|
Production taxes | | $ | 0.43 |
| | $ | 0.29 |
| | $ | 0.44 |
| | $ | 0.30 |
|
General and administrative | | $ | 1.08 |
| | $ | 1.08 |
| | $ | 1.30 |
| | $ | 0.96 |
|
Oil, natural gas and NGL depreciation, depletion and amortization | | $ | 4.57 |
| | $ | 4.26 |
| | $ | 4.31 |
| | $ | 4.40 |
|
Depreciation and amortization of other assets | | $ | 0.41 |
| | $ | 0.42 |
| | $ | 0.43 |
| | $ | 0.46 |
|
Interest expense(e) | | $ | 2.26 |
| | $ | 1.20 |
| | $ | 2.05 |
| | $ | 1.06 |
|
| | | | | | | | |
Interest Expense ($ in millions): | | | | | | | | |
Interest expense | | $ | 115 |
| | $ | 74 |
| | $ | 302 |
| | $ | 199 |
|
Interest rate derivatives – realized (gains) losses(f) | | (1 | ) | | (3 | ) | | (3 | ) | | (9 | ) |
Interest rate derivatives – unrealized (gains) losses(f) | | — |
| | 2 |
| | 3 |
| | 7 |
|
Total interest expense | | $ | 114 |
| | $ | 73 |
| | $ | 302 |
| | $ | 197 |
|
| | |
(a) | Oil equivalent is based on six mcf of natural gas to one barrel of oil or one barrel of NGL. This ratio reflects an energy content equivalency and not a price or revenue equivalency.Introduction |
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(b) | Realized gains (losses) include the following items: (i) settlements and accruals for settlements of undesignated derivatives related to current period production revenues, (ii) prior period settlements for option premiums and for early-terminated derivatives originally scheduled to settle against current period production revenues, and (iii) gains (losses) related to de-designated cash flow hedges originally designated to settle against current period production revenues. Unrealized gains (losses) include the change in fair value of open derivatives scheduled to settle against future period production revenues (including current period settlements for option premiums and early terminated derivatives) offset by amounts reclassified as realized gains (losses) during the period. |
| |
(c) | Includes revenue and operating costs. See Depreciation and Amortization of Other Assets under Results of Operations for details of the depreciation and amortization associated with our marketing, gathering and compression segment.
|
| |
(d) | In the Prior Quarter and the Prior Period, we recorded unrealized losses of $280 million and $297 million, respectively, on the fair value of our supply contract derivative. Additionally, in the Prior Quarter, we sold the supply contract to a third party for cash proceeds of $146 million. See Note 8 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for discussion related to this instrument. |
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(e) | Includes the effects of realized (gains) losses from interest rate derivatives, excludes the effects of unrealized (gains) losses from interest rate derivatives and is shown net of amounts capitalized. |
| |
(f) | Realized (gains) losses include interest rate derivative settlements related to current period interest and the effect of (gains) losses on early-terminated trades. Settlements of early-terminated trades are reflected in realized (gains) losses over the original life of the hedged item. Unrealized (gains) losses include changes in the fair value of open interest rate derivatives offset by amounts reclassified to realized (gains) losses during the period. |
OverviewThis Management’s Discussion and Analysis of Financial Condition and Results of Operations is intended to provide a reader of our financial statements with management’s perspective on our financial condition, liquidity, results of operations and certain other factors that may affect our future results. The following discussion should be read together with the condensed consolidated financial statements included in Item 1 of Part I of this report and the consolidated financial statements included in Item 8 of our 2022 Form 10-K.We own interestsare an independent exploration and production company engaged in approximately 17,100the acquisition, exploration and development of properties to produce natural gas, oil and natural gas wells and produced an average of approximately 542 mboe per day in the Current Quarter, net to our interest.NGL from underground reservoirs. We haveown a large and geographically diverse resource baseportfolio of onshore U.S. unconventional natural gas and liquids assets. We have leading positionsassets, including interests in the liquids-rich resource playsapproximately 7,200 natural gas and oil wells as of the Eagle Ford Shale in South Texas, the Anadarko Basin in northwestern Oklahoma and the stacked pay in the Powder River Basin in Wyoming.March 31, 2023. Our natural gas resource plays are the Haynesville/Bossier Shales in northwestern Louisiana and East Texas, the Utica Shale in Ohio and the Marcellus Shale in the northern Appalachian Basin in Pennsylvania. We also own oilPennsylvania (“Marcellus”) and natural gas marketingthe Haynesville/Bossier Shales in northwestern Louisiana (“Haynesville”). Our liquids-rich resource play is in the Eagle Ford Shale in South Texas (“Eagle Ford”). In August 2022, we announced that we viewed the assets in Eagle Ford as non-core to our future capital allocation strategy. In January 2023, we entered into an agreement to sell a portion of our Eagle Ford assets to WildFire Energy I LLC for $1.425 billion and natural gas compression businesses.closed the transaction on March 20, 2023. Additionally, in February 2023, we entered into an agreement to sell a portion of our remaining Eagle Ford assets to INEOS Energy for $1.4 billion and closed the transaction on April 28, 2023.
Our Strategy
Chesapeake’s strategy is to create shareholder value through the responsible development of our significant positions in premier U.S. onshore resource plays. In addition, weplays while continuing to be a leading provider of affordable, reliable, low carbon energy to the United States. We continue to focus ouron improving margins through operating efficiencies and financial strategy on reducing debtdiscipline and improving marginsour ESG performance. To accomplish these goals, we intend to allocate our human resources and returns on capital. We apply financial discipline to all aspects of our business with goals of increasing financial and operational flexibility. Our capital program is focused on investments that can improve our cash flow generating ability regardless of the commodity price environment. Our forecasted capital expenditures are higher in 2017 compared to 2016 asprojects we focusbelieve offer the highest cash return on capturing high rate-of-returncapital invested, to deploy leading drilling and completion technology throughout our portfolio, and to take advantage of acquisition and divestiture opportunities into strengthen our oil and natural gas portfolio. These opportunities are primarily the result of improved capital and operating efficiencies, including improved well performance. We expect our anticipated production increases in the 2017 fourth quarter, combined with our cost leadership and discipline, will position us with the ability to balance capital expenditures and operating cash flow in 2018.
Our substantial inventory of hydrocarbon resources, including our significant undeveloped acreage position in each of our key basins, provides a strong foundation to create future value. Concentrated blocks of undeveloped acreage give us the opportunity to apply best in class well spacing analysis, completion techniques and lateral lengths to maximize capital efficiency. We have greatly improved our capital and operating efficiency metrics over the last several periods and today have a leading cost structure in each of our major operating basins. We believe our cost structure provides a significant competitive advantage in the current commodity price environment and it is our strategyalso intend to continue to seekdedicate capital and operating efficiencies to grow this advantage. Building on our strong and diverse asset base and further delineating our emerging new development opportunities, we believeprojects that our dedication to financial discipline,reduce the flexibility and efficiencyenvironmental impact of our capital programnatural gas and cost structure and our continued focus on safety and environmental stewardship will provideoil producing activities. We continue to seek opportunities to create valuereduce cash costs (production, gathering, processing and transportation and general and administrative), through operational efficiencies and improving our production volumes from existing wells.
Leading a responsible energy future is foundational to Chesapeake's success. Our core values and culture demand we continuously evaluate the environmental impact of our operations and work diligently to improve our ESG performance across all facets of our Company. Our path to answering the call for usaffordable, reliable, low carbon energy begins with our goal to achieve net zero greenhouse gas emissions (Scope 1 and 2) by 2035. To meet this challenge, we have set meaningful goals including:
•Eliminate routine flaring from all new wells completed from 2021 forward, and enterprise-wide by 2025;
•Reduce our stakeholders.methane intensity to 0.02% by 2025 (achieved approximately 0.05% in 2022); and
Operating Results
Our Current Quarter production of 50 mmboe consisted of 8 mmbbls•Reduce our GHG intensity to 3.0 metric tons CO2 equivalent per thousand barrel of oil (16% on an oil equivalent basis), 219 bcfby 2025 (achieved approximately 3.9 in 2022).
In July 2021, we announced our plan to receive independent certification of our natural gas production under the MiQ methane standard and EO100™ Standard for Responsible Energy Development. By the end of 2022, we had received certifications for all our operated gas assets in Haynesville and Marcellus as responsibly sourced gas. The MiQ certification provides a verified approach to tracking our commitment to reduce our methane intensity, as well as supporting our overall objective of achieving net-zero Scope 1 and 2 greenhouse gas emissions by 2035.
As the majority of our production profile consists of natural gas, (73% on anwe have converted the following results of operations, including prior periods, from a per barrel of oil equivalent, basis), and 5 mmbblsto a per one thousand cubic feet of NGL (11% on an oil equivalent basis). Our daily production for the Current Quarter averaged approximately 542 mboe, a decrease of 15% from the Prior Quarter. Compared to the Prior Quarter, average daily oil production decreased by 1%, or approximately 1 mbbl per day; average daily natural gas production decreased by 18%, or approximately 532 mmcf per day;equivalent, referred to, on such a converted basis, as Mcfe.
Acquisition
On March 9, 2022, we closed our Marcellus Acquisition pursuant to definitive agreements with Chief, Radler and average daily NGL production decreased by 11%, or approximately 7 mbbls per day. Our oil, natural gasTug Hill, Inc. dated January 24, 2022. This transaction strengthened Chesapeake’s competitive position, meaningfully increasing our operating cash flows and NGL production decreased primarily asadding high quality producing assets and a resultdeep inventory of premium drilling locations, while preserving the strength of our balance sheet.
Divestitures
On March 25, 2022, we closed the sale of certain of our Mid-Continent and Barnett ShalePowder River Basin assets in 2016 and the sale of certain of our Haynesville Shale assetsWyoming to Continental Resources, Inc. for $450 million in 2017. Adjusted for asset sales, our total daily production was approximately unchangedcash, subject to post-closing adjustments, which resulted in the Current Quarter compared to the Prior Quarter. Our oil, natural gas and NGL total revenues (excluding gains or losses on oil and natural gas derivatives) were approximately unchanged in the Current Quarter compared to the Prior Quarter, due to increases in the prices received for oil, natural gas and NGL sold, offset by the production decreases described above. See Resultsrecognition of Operations below for additional details.
Our Current Period production of 145 mmboe consisted of 23 mmbbls of oil (16% on an oil equivalent basis), 639 bcf of natural gas (73% on an oil equivalent basis), and 15 mmbbls of NGL (11% on an oil equivalent basis). Our daily production for the Current Period averaged approximately 532 mboe, a decrease of 19% from the Prior Period. Compared to the Prior Period, average daily oil production decreased by 5%, or approximately 5 mbbls per day; average daily natural gas production decreased by 21%, or approximately 630 mmcf per day; and average daily NGL production decreased by 19%, or approximately 13 mbbls per day. Our oil, natural gas and NGL production decreased primarily as a result of the sale of certain of our Mid-Continent and all of our Barnett Shale assets in 2016 and the sale of certain of our Haynesville Shale assets in 2017. Adjusted for asset sales, our total daily production decreased 2% in the Current Period compared to the Prior Period. Our oil, natural gas and NGL total revenues (excluding gains or losses on oil and natural gas derivatives) increased approximately $531 million to $3.275 billion in the Current Period compared to $2.744 billion in the Prior Period, due to increases in the prices received for oil, natural gas and NGL sold, partially offset by the production decreases described above. See Results of Operations below for additional details.
Capital Expenditures
Our drilling and completion capital expenditures during the Current Quarter were approximately $626 million and capital expenditures for the acquisition of unproved properties, geological and geophysical costs and other property and equipment were approximately $17 million, for a totalgain of approximately $643$293 million. In the Current Quarter, we operated an average of 17 rigs, an increase of six rigs, or 55%, compared to the Prior Quarter. As a result of higher drilling and completion activity as well as higher service and supply costs, drilling and completion expenditures increased approximately $294 million in the Current Quarter compared to the Prior Quarter. Capital expenditures for the acquisition of unproved properties, geological and geophysical costs and other property and equipment decreased approximately $4 million compared to the Prior Quarter.
Our capitalized interest was approximately $49 million and $59 million in the Current Quarter and the Prior Quarter, respectively. The decrease in capitalized interest resulted from a lower average balance of our unproved oil and natural gas properties, the primary asset on which interest is capitalized. Including capitalized interest, total capital investments were approximately $692 million in the Current Quarter compared to $412 million for the Prior Quarter, an increase of 68%.
Our drilling and completion capital expenditures during the Current Period were approximately $1.728 billion and capital expenditures for the acquisition of unproved properties, geological and geophysical costs and other property and equipment were approximately $60 million, for a total of approximately $1.788 billion. In the Current Period, we operated an average of 18 rigs, an increase of eight rigs, or 80%, compared to the Prior Period. As a result of higher drilling and completion activity as well as higher service and supply costs, drilling and completion expenditures increased approximately $777 million in the Current Period compared to the Prior Period. Capital expenditures for the acquisition of unproved properties, geological and geophysical costs and other property and equipment decreased approximately $31 million compared to the Prior Period.
Our capitalized interest was approximately $147 million and $191 million in the Current Period and the Prior Period, respectively. The decrease in capitalized interest resulted from a lower average balance of our unproved oil and natural gas properties, the primary asset on which interest is capitalized. Including capitalized interest, total capital investments were approximately $1.935 billion in the Current Period compared to $1.233 billion for the Prior Period, an increase of 57%.
Based on planned activity levels for the remainder of 2017, we project that 2017 capital expenditures for drilling and completions, leasehold, geological and geophysical and other property and equipment will be $2.3 – $2.5 billion, inclusive of capitalized interest, as compared to $1.7 billion of capital expenditures in 2016. See Liquidity and Capital Resources for additional information on how we plan to fund our capital budget.
Strategic Developments
Debt Offerings
On October 12, 2017,January 17, 2023, we issued in a private placement $300 million aggregate principal amount of 8.00% Senior Notes due 2025 (New 2025 Notes) at 101.25% of par, plus accrued interest from July 15, 2017, and $550 million aggregate principal amount of 8.00% Senior Notes due 2027 (New 2027 Notes) at 99.75% of par, plus accrued interest from June 6, 2017. Aggregate net proceeds from the issuance of the New 2025 Notes and New 2027 Notes, excluding the accrued interest received, were approximately $842 million. See Note 16 of the notesentered into an agreement to our condensed consolidated financial statements included in Item 1 of Part I of this report for further discussion.
In the Current Period, we issued $750 million aggregate principal amount of unsecured 8.00% Senior Notes due 2027 in a private placement for net proceeds of $742 million.
Debt Retirements
On October 13, 2017, we used a portion of the net proceeds from the offering discussed above to finance $550 million in tender offers for certain of our senior notes. We repurchased approximately $320 million principal amount of our 8.00% Senior Secured Second Lien Notes due 2022 for $350 million plus accrued and unpaid interest, and approximately $193 million principal amount of various series of our senior notes due 2020 and 2021 for $200 million plus accrued and unpaid interest. See Note 16 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for further discussion.
In addition, we used additional proceeds from the October issuances described above to repurchase approximately $237 million principal amount of our secured term loan due 2021 for $258 million.
In the Current Period, we retired $1.609 billion principal amount of our outstanding senior notes, senior secured second lien notes and contingent convertible notes through purchases in the open market, tender offers or repayment upon maturity for $1.751 billion. Retirements included (i) the maturity of our 6.25% Euro-denominated Senior Notes due 2017 and corresponding cross currency swap, (ii) our tender offer for our 2.5% Contingent Convertible Senior Notes due 2037 at the option of the holders of the notes pursuant to the terms of the notes, (iii) our tender offer forsell a portion of our senior secured second lien notes, (iv)Eagle Ford assets to WildFire Energy I LLC for $1.425 billion, subject to post-closing adjustments. This transaction closed on March 20, 2023 and resulted in the repurchaserecognition of our 6.5% Senior Notes due 2017, and (v) the repurchasesa gain of approximately $335 million.
On February 17, 2023, we entered into an agreement to sell a portion of our remaining 2.75% Contingent Convertible Senior Notes due 2035Eagle Ford assets to INEOS Energy for $1.4 billion, subject to post-closing adjustments. This transaction closed on April 28, 2023, and 2.5% Contingent Convertible Senior Notes due 2037.we received proceeds of approximately $1.055 billion. As of March 31, 2023, the assets and liabilities associated with this transaction were classified as held for sale.
Preferred Stock ExchangesInvestments - Momentum Sustainable Ventures LLC
During the fourth quarter of 2022, we entered into an agreement with Momentum Sustainable Ventures LLC to build a new natural gas gathering pipeline and carbon capture and sequestration project, which will gather natural gas produced in the Haynesville Shale for re-delivery to Gulf Coast markets, including LNG export. The pipeline is expected to have an initial capacity of 1.7 Bcf/d expandable to 2.2 Bcf/d. The carbon capture portion of the project anticipates capturing and permanently sequestering up to 2.0 million tons per annum of CO2. The natural gas gathering pipeline in-service is projected for the fourth quarter of 2024, and the carbon sequestration portion of the project is subject to regulatory approvals. Through the end of the first quarter of 2023, we have made total capital contributions of $56 million to the project.
Repurchases of Equity Securities and Dividends
In June 2022, our Board of Directors authorized an increase in the Current Period,size of our share repurchase program from $1.0 billion to up to $2.0 billion in aggregate value of our common stock and/or warrants. During the three months ended March 31, 2023, we completed private exchanges of an aggregate ofrepurchased approximately 10.00.8 million shares of our common stock for (i) 72,600 sharespursuant to the share repurchase program and had $867 million available under the share repurchase program, as of 5.75% Cumulative Convertible Preferred Stock, (ii) 12,500 sharesMarch 31, 2023. In addition, we paid dividends of 5.75% Cumulative Convertible Preferred Stock (Series A)approximately $175 million, in aggregate, on our common stock during the three months ended March 31, 2023.
Russia’s Invasion of Ukraine; Volatility in Natural Gas, Oil and (iii) 150,948 shares of 5.00% Cumulative Convertible Preferred Stock (Series 2005B). The preferred stock exchanged represents approximately $100 million of liquidation value. These exchanges eliminated approximately $6 million of annual dividend obligations.NGL Prices; Inflationary Cost Pressures and Potential Economic Downturns
Divestitures
In late February 2022, Russia launched a military invasion against Ukraine. The Russian invasion has caused, and could intensify, volatility in natural gas, oil and NGL prices, and may have an impact on global growth prospects, which could in turn affect demand for natural gas and oil. This overall uncertainty resulted in stronger commodity prices during much of 2022. Toward the Current Period, we sold portionsend of 2022, markets began to stabilize, and this, coupled with a milder winter, has resulted in an observed decline in pricing in early 2023. Our 2023 estimated cash flow is partially protected from commodity price volatility due to our current hedge positions that cover approximately 55% to 65% of our acreageprojected natural gas volumes for the remainder of 2023.
In addition to the recent weakening in commodity prices, the industry is experiencing inflationary pressure, including increased demand for oilfield service equipment, rising fuel costs, and producing propertieslabor shortages, which could result in increases to our operating and capital costs that are not fixed. Uncertainty regarding a potential economic
downturn or recession in certain regions, or globally, may introduce new pressures or accelerate or intensify the pressures currently facing the industry. We continue to monitor these situations and assess their impact on our business, including our business partners and customers. For additional discussion regarding risks associated with price volatility and economic deterioration, see Part I, Item 1A “Risk Factors” in our Haynesville Shale operating area2022 Form 10-K. COVID-19 Pandemic and Impact on Global Demand for Natural Gas and Oil
The global spread of COVID-19 created significant volatility, uncertainty, and economic disruption commencing in northern Louisiana for approximately $915 million, subject2020, and threatens to certain customary closing adjustments. Includedcontinue to do so in 2023. While we cannot predict the full impact that COVID-19 and its variants, or the related disruption and volatility in the sales were approximately 119,500 net acresnatural gas and interests in 576 wells that were producing approximately 80 mmcfoil markets may have on our business, cash flows, liquidity, financial condition and results of gas per day atoperations, we believe our cost structure and liquidity position us well to address continued price and demand volatility. For additional discussion regarding risks and impacts associated with the time of closing.
Also in the Current Period, we have signed or closed approximately $360 million of additional asset divestitures, primarilyCOVID-19 pandemic, see Part I, Item 1A “Risk Factors” in our
Mid-Continent area.2022 Form 10-K.Gathering, Processing and Transportation Agreements
In the Current Period, we terminated future natural gas transportation commitments related to divested assets for cash payments of $126 million. In the Current Period, we also paid $290 million to assign an oil transportation agreement to a third party.
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Liquidity and Capital Resources |
Liquidity Overview
Our ability to grow, makeprimary sources of capital expendituresresources and serviceliquidity are internally generated cash flows from operations and borrowings under our debt depends primarily upon the prices we receivecredit agreements, and our primary uses of cash are for the oil,development of our natural gas and NGL we sell. Substantial expenditures are required to replace reserves, sustain production and fund our business plans. Historically, oil andproperties, acquisitions of additional natural gas prices have been very volatile,properties and may be subjectreturn of value to wide fluctuations instockholders through dividends and equity repurchases. We believe our cash flow from operations, proceeds from our recent Eagle Ford divestitures, cash on hand and borrowing capacity under the New Credit Facility, as discussed below, will provide sufficient liquidity during the next 12 months and the foreseeable future. The substantial decline in oil, natural gas and NGL prices from 2014 levels has negatively affected the amountAs of March 31, 2023, we had $2.1 billion of liquidity available, including $130 million of cash we generateon hand and have available for capital expenditures and debt service. A substantial or extended decline in oil, natural gas and NGL prices could have a material impact on our financial position, results$2.0 billion of operations, cash flows and on the quantities of reserves that we may economically produce. Other risks and uncertainties that could affect our liquidity include, but are not limited to, counterparty credit risk for our receivables, access to capital markets, regulatory risks and our ability to meet financial ratios and covenants in our financing agreements and the size of lenders’ commitments as a result of regulatory pressures in the lending market.
As of September 30, 2017, we had a cash balance of $5 million compared to $882 million as of December 31, 2016, and we had a net working capital deficit of $1.040 billion, compared to a net working capital deficit of $1.506 billion as of December 31, 2016. As of September 30, 2017, we had $3.043 billion ofaggregate unused borrowing capacity available under
our revolving credit facility, withthe New Credit Facility. As of March 31, 2023, we had no outstanding borrowings
of $645 million and $97 million utilized for various letters of credit. Based on our cash balance, forecasted cash flows from operating activities and availability under our
revolving credit facility, we expect to be able to fund our planned capital expenditures, meet our debt service requirements and fund our other commitments and obligations for the next 12 months.New Credit Facility. See
Note 34 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for further discussion of our debt obligations, including principalthe carrying and carrying amounts of our notes.Through November 1, 2017, we have taken the following measures to improve our near-term liquidity:
issued $300 million aggregate principal amount of 8.00% Senior Notes due 2025 and $1.3 billion aggregate principal amount of 8.00% Senior Notes due 2027 and used the proceeds to repurchase a portionfair value of our senior secured second lien notes, a portionnotes.
Dividends
We paid dividends of our senior notes due in 2020 and 2021 and a portion of our term loan due 2021;
reaffirmed the borrowing base$175 million on our revolving credit facility at $3.8 billion;
exchanged approximately 10.0 million shares of common stock for approximately $100 million of liquidation value of our preferred stock, eliminating approximately $6 million of annual dividend obligations;
completed approximately $1.3 billion of asset divestitures that did not fit our strategic priorities; and
protected a significant amount of 2018 cash flow through hedging activities discussed below.
Even though we have taken measures, as outlined above, to mitigate the liquidity concerns facing us for the next 12 months, there can be no assurance that these measures will satisfy our needs. We may continue to access the capital markets or otherwise incur debt to refinance a portion of our outstanding indebtedness and improve our liquidity.
As operator of a substantial portion of our oil and natural gas properties under development, we have significant control and flexibility over the timing and execution of our development plan, enabling us to reduce our capital spending as needed. Our forecasted 2017 capital expenditures, inclusive of capitalized interest, are $2.3 – $2.5 billion compared to our 2016 capital spending level of $1.7 billion. We had liquidity (calculated as cash on hand and availability under our revolving credit facility), of approximately $3.1 billion as of October 31, 2017. We expect to generate additional liquidity with proceeds from future sales of assets that do not fit our strategic priorities. Management continues to review operational plans for the remainder of 2017 and beyond, which could result in changes to projected capital expenditures and projected revenues from sales of oil, natural gas and NGL. We closely monitor the amounts and timing of our sources and uses of funds, particularly as they affect our ability to maintain compliance with the financial covenants of our revolving credit facility.
Some of our counterparties have requested or required us to post collateral as financial assurance of our performance under certain contractual arrangements, such as gathering, processing, transportation and hedging agreements. As of October 31, 2017, we have received requests and posted approximately $130 million of collateral related to certain of our marketing and other contracts and $1 million of collateral related to certain of our derivative contracts. We may be requested or required by other counterparties to post additional collateral in an aggregate amount of approximately $487 million, which may be in the form of additional letters of credit, cash or other acceptable collateral. However, we have substantial long-term business relationships with each of these counterparties, and we may be able to mitigate any collateral requests through ongoing business arrangements and by offsetting amounts that the counterparty owes us. Any posting of collateral consisting of cash or letters of credit reduces availability under our revolving credit facility and negatively impacts our liquidity.
In the Current Period, we completed several debt and equity transactions, as described above, to improve our balance sheet. We may continue to use a combination of cash, borrowings and issuances of our common stock or other securities to retire our outstanding debt and preferred stock through privately negotiated transactions, open market repurchases, redemptions, tender offers or otherwise, but we are under no obligation to do so.
To add more certainty to our future estimated cash flows by mitigating our downside exposure to lower commodity prices, asduring the first three months of October 31, 2017, we have downside price protection, through open swaps, on approximately 62% of our remaining projected 2017 oil production at an average price of $50.36 per bbl. We also have downside price protection, through open swaps and collars, on approximately 83% of our remaining projected 2017 natural gas production at an average price of $3.17 per mcf, of which 11% is hedged under two-way collar arrangements based on an average bought put NYMEX price of $3.25 per mcf. We also have downside price protection, through open swaps, on a portion of our projected propane revenue at an average price of $0.76 per gallon, representing approximately 8% of our remaining projected 2017 NGL production. In addition, we have downside price protection, through open swaps on 19 mmbbls of our 2018 oil production at an average price of $51.74 per bbl and under three-way collar arrangements on 2 mmbbls based on an average bought put NYMEX price of $47 per bbl and exposure below an average sold put NYMEX price of $39.15 per bbl. We also have downside price protection, through open swaps and collars on 579 bcf of our 2018 natural gas production at an average price of $3.10 per mcf, of which 47 bcf is hedged under two-way collar arrangements based on an average bought put NYMEX price of $3.00 per mcf. We also have downside price protection, through open swaps, on approximately 0.6 mmbbls of projected 2018 NGL production at an average price of $0.73 per gallon. We also have hedged a portion of oil production sold under LLS contracts at the Gulf Coast and northeast natural gas production sold in-basin through the use of basis swaps.
As highlighted above, we have taken measures to mitigate the liquidity concerns facing us for the remainder of 2017 and beyond, but there can be no assurance that such measures will satisfy our needs. Further, our ability to generate operating cash flow in the current commodity price environment, sell assets, access capital markets or take any other action to improve our liquidity and manage our debt is subject to the risks discussed above and the other risks and uncertainties that exist in our industry, some of which we may not be able to anticipate at this time or control.
Sources of Funds
The following table presents the sources of our cash and cash equivalents for the Current Period and the Prior Period.2023. See
Note 9 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for further discussiondiscussion.On May 2, 2023, we declared a quarterly dividend payable of divestitures$1.18 per share, which will be paid on June 6, 2023 to stockholders of record at the close of business on May 18, 2023. The dividend consists of a base quarterly dividend in the amount of $0.55 per share and a variable quarterly dividend in the amount of $0.63 per share.
The declaration and payment of any future dividend, whether fixed or variable, will remain at the full discretion of the Board and will depend on the Company’s financial results, cash requirements, future prospects and other relevant factors. The Company’s ability to pay dividends to its stockholders is restricted by (i) Oklahoma corporate law, (ii) its Certificate of Incorporation, (iii) the terms and provisions of the credit agreement governing its New Credit Facility and (iv) the terms and provisions of the indentures governing its 5.50% Senior Notes due 2026, 5.875% Senior Notes due 2029 and 6.75% Senior Notes due 2029.
Derivative and Hedging Activities
Our results of operations and cash flows are impacted by changes in market prices for natural gas, oil and NGL. We enter into various derivative instruments to mitigate a portion of our exposure to commodity price declines, but these transactions may also limit our cash flows in periods of rising commodity prices. Our natural gas, oil and NGL derivative activities, when combined with our sales of natural gas, oil and NGL, allow us to better predict the total revenue we expect to receive. See Item 3. Quantitative and Qualitative Disclosures About Market Risk included in Part I of this report for further discussion on the impact of commodity price risk on our financial position.
Contractual Obligations and Off-Balance Sheet Arrangements
As of March 31, 2023, our material contractual obligations include repayment of senior notes, derivative obligations, asset retirement obligations, lease obligations, capital commitments relating to our investments,
undrawn letters of credit and various other commitments we enter into in the ordinary course of business that could result in future cash obligations. In addition, we have contractual commitments with midstream companies and pipeline carriers for future gathering, processing and transportation of natural gas, oil and NGL to move certain of our production to market. The estimated gross undiscounted future commitments under these agreements were approximately $4.2 billion as of March 31, 2023. As discussed above, we believe our existing sources of liquidity will be sufficient to fund our near and long-term contractual obligations. See Notes 4, 5, 11 and 12 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for further discussion. New Credit Facility
On December 9, 2022, the Company, as borrower, entered into a senior secured reserve-based credit agreement providing for the New Credit Facility which features an initial borrowing base of $3.5 billion and aggregate commitments of $2.0 billion. Subject to certain exceptions, the borrowing base will be redetermined semi-annually in or around April and October of each year. The New Credit Facility provides for a $200 million sublimit available for the issuance of letters of credit and a $50 million sublimit available for swingline loans. Borrowings under the credit agreement may be alternate base rate loans or term SOFR loans, at the Company’s election. The New Credit Facility contains certain features that, upon receipt and maintenance of investment grade ratings from S&P, Moody’s and/or Fitch and the satisfaction of certain other conditions, result in the removal or relaxation of specified negative and financial covenants, among other favorable adjustments. See Note 4 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for further discussion. Capital Expenditures
For the year ending December 31, 2023, we currently expect to bring or have online approximately 145 to 165 gross wells across 10 to 12 rigs and plan to invest between approximately $1.765 – $1.835 billion in capital expenditures. We expect that approximately 85% of our 2023 capital expenditures will be directed toward our natural gas assets. We currently plan to fund our 2023 capital program through cash on hand, expected cash flow from our operations and borrowings under our New Credit Facility. We may alter or change our plans with respect to our capital program and expected capital expenditures based on developments in our business, our financial position, our industry, or any of the markets in which we operate.
|
| | | | | | | | |
| | Nine Months Ended September 30, |
| | 2017 | | 2016 |
| | ($ in millions) |
Cash provided by operating activities | | $ | 273 |
| | $ | 50 |
|
Proceeds from credit facility borrowings, net | | 645 |
| | 240 |
|
Proceeds from issuance of term loan | | — |
| | 1,500 |
|
Proceeds from issuance of senior notes, net | | 742 |
| | — |
|
Divestitures of proved and unproved properties | | 1,193 |
| | 988 |
|
Sales of other property and equipment | | 40 |
| | 70 |
|
Total sources of cash and cash equivalents | | $ | 2,893 |
| | $ | 2,848 |
|
Sources and (Uses) of Cash and Cash EquivalentsThe following table presents the sources and uses of our cash and cash equivalents for the periods presented: | | | | | | | | | | | | | | |
| | Three Months Ended March 31, 2023 | | Three Months Ended March 31, 2022 |
Cash provided by operating activities | | $ | 889 | | | $ | 853 | |
Proceeds from divestitures of property and equipment | | 931 | | | 403 | |
| | | | |
Proceeds from Exit Credit Facility, net | | — | | | 500 | |
| | | | |
Proceeds from warrant exercise | | — | | | 1 | |
Capital expenditures | | (497) | | | (344) | |
Business combination, net | | — | | | (2,006) | |
Contributions to investments | | (39) | | | — | |
Payments on New Credit Facility, net | | (1,050) | | | — | |
| | | | |
| | | | |
Cash paid to repurchase and retire common stock | | (54) | | | (83) | |
Cash paid for common stock dividends | | (175) | | | (210) | |
Net increase (decrease) in cash, cash equivalents and restricted cash | | $ | 5 | | | $ | (886) | |
Cash Flow from Operating Activities
Cash provided by operating activities was $273$889 million inand $853 million during the Current Period compared to $50 million in the Prior Period.first three months of 2023 and 2022, respectively. The increase during the first three months of 2023 is primarily due to increased sales volumes in Marcellus primarily due to the resultMarcellus Acquisition and timing of higher realized prices for the oil, natural gas and NGL we sold,cash receipts, partially offset by lower volumes of oil,prices for the natural gas, oil and NGL sold, the payment related to the litigation on our 6.775% Senior Notes due 2019 and payments for terminations of transportation contracts. Changes in cash flowwe sold. Cash flows from operations are largely due toaffected by the same factors that affect our net income, excluding various non-cash items, such as depreciation, depletion and amortization, certain impairments, gains or losses on sales of fixed assets, deferred income taxes and mark-to-market changes in our open derivative instruments. See further discussion below under Results of Operations.
We currently plan to use cash flowProceeds from operations, cash on handDivestitures of Property and our revolving credit facility to fund our capital expenditures forEquipment
During the remainderfirst three months of 2017. We expect to generate additional liquidity with proceeds from future sales of assets that do not fit our strategic priorities. Under our revolving credit facilities,2023, we borrowed $4.775 billion and repaid $4.130 billion in the Current Period, and we borrowed $5.097 billion and repaid $4.857 billion in the Prior Period.
Uses of Funds
The following table presents the usessold a portion of our cash and cash equivalents for the Current Period and the Prior Period:
|
| | | | | | | | |
| | Nine Months Ended September 30, |
| | 2017 | | 2016 |
| | ($ in millions) |
Oil and Natural Gas Expenditures: | | | | |
Drilling and completion costs | | $ | 1,597 |
| | $ | 946 |
|
Acquisitions of proved and unproved properties | | 87 |
| | 406 |
|
Interest capitalized on unproved leasehold | | 139 |
| | 179 |
|
Total oil and natural gas expenditures | | 1,823 |
| | 1,531 |
|
Other Uses of Cash and Cash Equivalents: | | | | |
Cash paid to repurchase debt | | 1,751 |
| | 1,979 |
|
Cash paid for title defects | | — |
| | 69 |
|
Additions to other property and equipment | | 12 |
| | 32 |
|
Dividends paid | | 160 |
| | — |
|
Other | | 24 |
| | 58 |
|
Total other uses of cash and cash equivalents | | 1,947 |
| | 2,138 |
|
Total uses of cash and cash equivalents | | $ | 3,770 |
| | $ | 3,669 |
|
Our drilling and completion costs increased in the Current Period comparedEagle Ford assets to the Prior Period primarily as a result of increased activity as well as higher service and supply costs.WildFire Energy I LLC. During the Current Period,first three months of 2022, we sold our average operated rig count was 18 rigs comparedPowder River Basin assets to an average operated rig count of ten rigs in the Prior Period and we completed 326 operated wells in the Current Period compared to 280 in the Prior Period.
In the Current Period, we used $1.751 billion of cash to repurchase $1.609 billion principal amount of debt. In the Prior Period, we used $1.979 billion of cash to repurchase $2.192 billion principal amount of debt.
We paid dividends of $160 million on our preferred stock during the Current Period, including $92 million of dividends in arrears that had been suspended throughout 2016. We did not pay dividends on our preferred stock in the Prior Period.
Term Loan Facility
We have a secured five-year term loan facility in an aggregate principal amount of $1.5 billion as of September 30, 2017. As discussed in Note 16 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report, in October 2017, we repurchased $237 million principal amount of the outstanding balance. Our obligations under the facility are unconditionally guaranteed on a joint and several basis by the same subsidiaries that guarantee our revolving credit facility, second lien notes and senior notes, and are secured by first-priority liens on the same collateral securing our revolving credit facility (with a position in the collateral proceeds waterfall junior to the revolving credit facility). The term loan bears interest at a rate of London Interbank Offered Rate (LIBOR) plus 7.50% per annum, subject to a 1.00% LIBOR floor, or the Alternative Base Rate (ABR) plus 6.50% per annum, subject to a 2.00% ABR floor, at our option. The term loan matures in August 2021 and voluntary prepayments are subject to a make-whole premium prior to the second anniversary of the closing of the term loan, a premium to par of 4.25% from the second anniversary until but excluding the third anniversary, a premium to par of 2.125% from the third anniversary until but excluding the fourth anniversary and at par beginning on the fourth anniversary. The term loan may be subject to mandatory prepayments and offers to purchase with net cash proceeds of certain issuances of debt, certain asset sales and other dispositions of collateral and upon a change of control. See Note 32 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for further discussiondiscussion.
Proceeds from Exit Credit Facility, net
During the first three months of 2022, we borrowed a net $500 million on the Exit Credit Facility to fund a portion of the term loan facility.Marcellus Acquisition.
Revolving Credit FacilityCapital Expenditures
We haveOur capital expenditures increased during the first three months of 2023 compared to the first three months of 2022, primarily as a senior secured revolving credit facility currently subject to a $3.8result of increased drilling and completion activity across all operating areas, as well as inflation-related cost increases for goods and services.
Business Combination
During the first three months of 2022, we closed the Marcellus Acquisition for approximately $2 billion borrowing base that matures in December 2019. As of September 30, 2017, we had outstanding borrowings of $645 and 9.4 million under the revolving credit facility and had used $97 million of the revolving credit facility for various letters of credit. See Liquidity Overview above for additional information on our collateral postings. Borrowings under the facility bear interest at a variable rate. We are required to secure our obligations under the facility with liens on certain shares of our oil and natural gas properties, with the liens to be released upon the satisfaction of specific conditions. The applicable interest rates under the facility fluctuate based on the percentage of the borrowing base used. On October 30, 2017, our borrowing base was reaffirmed at $3.8 billion. Our next borrowing base redetermination is scheduled for the second quarter of 2018.common stock. See Note 32 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for further discussiondiscussion. Contributions to Investments
During the first three months of the terms of the revolving credit facility, as amended. As of September 30, 2017, our first lien secured leverage ratio was approximately 0.722023, contributions to 1.00 and our interest coverage ratio was approximately 1.50 to 1.00, and we were in compliance with all applicable financial covenants under the credit agreement.
Hedging Arrangements
Certain of our hedging arrangements are with counterparties that are also lenders (or affiliates of lenders) under our revolving credit facility. The contracts entered into with these counterparties are secured by the same collateral that secures our revolving credit facility which allows us to reduce any letters of credit posted as security with those counterparties. In addition, we enter into bilateral hedging agreements with other counterparties. The counterparties’ and our obligations under the bilateral hedging agreements must be secured by cash or letters of credit to the extent that any mark-to-market amounts owed to us or by us exceed defined thresholds.
Senior Note Obligations
Our senior note obligationsinvestments primarily consisted of the following as of September 30, 2017:
|
| | | | | | | | |
| | September 30, 2017 |
| | Principal Amount | | Carrying Amount |
| | ($ in millions) |
7.25% senior notes due 2018 | | $ | 44 |
| | $ | 44 |
|
Floating rate senior notes due 2019 | | 380 |
| | 380 |
|
6.625% senior notes due 2020 | | 572 |
| | 572 |
|
6.875% senior notes due 2020 | | 279 |
| | 278 |
|
6.125% senior notes due 2021 | | 550 |
| | 550 |
|
5.375% senior notes due 2021 | | 270 |
| | 270 |
|
4.875% senior notes due 2022 | | 451 |
| | 451 |
|
8.00% senior secured second lien notes due 2022(a) | | 1,737 |
| | 2,355 |
|
5.75% senior notes due 2023 | | 338 |
| | 338 |
|
8.00% senior notes due 2025 | | 1,000 |
| | 987 |
|
5.5% convertible senior notes due 2026(b)(c) | | 1,250 |
| | 831 |
|
8.00% senior notes due 2027 | | 750 |
| | 750 |
|
2.25% contingent convertible senior notes due 2038(c)(d) | | 9 |
| | 8 |
|
Debt issuance costs | | — |
| | (42 | ) |
Interest rate derivatives(e) | | — |
| | 2 |
|
Total long-term senior notes, net(f) | | $ | 7,630 |
| | $ | 7,774 |
|
| |
(a) | The carrying amount as of September 30, 2017, includes a premium of $618 million associated with a troubled debt restructuring. The premium is being amortized based on an effective yield method. |
| |
(b) | The notes are convertible, at the holder’s option, prior to maturity under certain circumstances into cash, common stock or a combination of cash and common stock, at our election. The holders of our convertible senior notes may require us to repurchase the principal amount of the notes upon certain fundamental changes. |
| |
(c) | The carrying amount as of September 30, 2017, is reflected net of a discount associated with the equity component of our convertible and contingent convertible senior notes of $420 million. |
| |
(d) | The notes are convertible, at the holder’s option, prior to maturity under certain circumstances into cash and, if applicable, shares of our common stock using a net share settlement process. The holders of our contingent convertible senior notes may require us to repurchase, in cash, all or a portion of their notes at 100% of the principal amount of the notes on any of four dates that are five, ten, fifteen and twenty years before the maturity date and upon certain fundamental changes. |
| |
(e) | See Note 8 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for discussion related to these instruments. |
| |
(f) | See Note 16 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for information regarding debt transactions subsequent to September 30, 2017. |
For further discussion and details regarding our senior notes and convertible senior notes, see Note 3 of the notes$39 million, which we contributed to our condensed consolidated financial statements included in Item 1 of Part I of this report.
Credit Risk
Derivative instruments that enable usinvestment with Momentum Sustainable Ventures LLC to manage our exposure to oil,build a new natural gas gathering pipeline and NGL prices expose us to credit risk from our counterparties. To mitigate this risk, we enter into derivative contracts only with counterparties that are highly rated or deemed by the Company to have acceptable credit strength and deemed by management to be competent and competitive market makers, and we attempt to limit our exposure to non-performance by any single counterparty. As of September 30, 2017, our oil, natural gas and NGL derivative instruments were spread among 10 counterparties. Additionally, the counterparties under our commodity hedging arrangements are required to secure their obligations in excess of defined thresholds.
Our accounts receivable are primarily from purchasers of oil, natural gas and NGL ($721 million as of September 30, 2017) and exploration and production companies that own interests in properties we operate ($200 million as of September 30, 2017). This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers and joint working interest owners may be similarly affected by changes in economic, industry or other conditions. We generally require letters of credit or parent guarantees for receivables from parties that are judged to have sub-standard credit, unless the credit risk can otherwise be mitigated. During the Current Quarter, the Prior Quarter, the Current Period and the Prior Period, we recognized $1 million, $1 million, $7 million and $5 million, respectively, of bad debt expense related to potentially uncollectible receivables.
Contractual Obligations and Off-Balance Sheet Arrangements
From time to time, we enter into arrangements and transactions that can give rise to contractual obligations and off-balance sheet commitments. As of September 30, 2017, these arrangements and transactions included (i) operating lease agreements, (ii) a volumetric production payment (VPP) (to purchase production and pay related production expenses and taxes in the future), (iii) open purchase commitments, (iv) open delivery commitments, (v) open drilling commitments, (vi) undrawn letters of credit, (vii) open gathering and transportation commitments, and (viii) various other commitments we enter into in the ordinary course of business that could result in a future cash obligation.carbon capture project. See
Notes 4 and 9Note 12 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for further discussiondiscussion.
Payments on New Credit Facility, net
During the first three months of 2023, we made net repayments of $1,050 million on the New Credit Facility, utilizing a portion of the divestiture proceeds from the sale of a portion of our Eagle Ford assets and VPPs,also from internally generated cash provided by operating activities.
Cash Paid to Repurchase and Retire Common Stock
In March 2022, we commenced our share repurchase program. During the first three months of 2023, we repurchased 0.8 million shares for an aggregate price of $60 million, which is inclusive of shares for which cash settlement occurred in early April 2023. During the first three months of 2022, we repurchased 1 million shares of common stock for an aggregate price of $83 million. The repurchased shares of common stock were retired and recorded as a reduction to common stock and retained earnings.
Cash Paid for Common Stock Dividends
As part of our dividend program, we paid common stock base dividends of $75 million and common stock variable dividends of $100 million during the first three months of 2023.
Natural Gas, Oil and NGL Production and Average Sales Prices | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended March 31, 2023 |
| | Natural Gas | | Oil | | NGL | | Total |
| | MMcf per day | | $/Mcf | | MBbl per day | | $/Bbl | | MBbl per day | | $/Bbl | | MMcfe per day | | $/Mcfe |
Marcellus | | 1,974 | | | 3.47 | | | — | | | — | | | — | | | — | | | 1,974 | | | 3.47 | |
Haynesville | | 1,549 | | | 2.88 | | | — | | | — | | | — | | | — | | | 1,549 | | | 2.88 | |
Eagle Ford | | 128 | | | 1.97 | | | 54 | | | 76.82 | | | 16 | | | 26.71 | | | 546 | | | 8.82 | |
Total | | 3,651 | | | 3.17 | | | 54 | | | 76.82 | | | 16 | | | 26.71 | | | 4,069 | | | 3.97 | |
| | | | | | | | | | | | | | | | |
Average NYMEX Price | | | | 3.42 | | | | | 76.13 | | | | | | | | | |
Average Realized Price (including realized derivatives) | | | | 2.74 | | | | | 66.79 | | | | | 26.71 | | | | | 3.45 | |
| | | | | | | | | | | | | | | | |
| | Three Months Ended March 31, 2022 |
| | Natural Gas | | Oil | | NGL | | Total |
| | MMcf per day | | $/Mcf | | MBbl per day | | $/Bbl | | MBbl per day | | $/Bbl | | MMcfe per day | | $/Mcfe |
Marcellus | | 1,452 | | | 4.66 | | | — | | | — | | | — | | | — | | | 1,452 | | | 4.66 | |
Haynesville | | 1,625 | | | 4.46 | | | — | | | — | | | — | | | — | | | 1,625 | | | 4.46 | |
Eagle Ford | | 129 | | | 4.04 | | | 52 | | | 95.00 | | | 16 | | | 41.09 | | | 540 | | | 11.44 | |
Powder River Basin | | 41 | | | 5.45 | | | 8 | | | 95.18 | | | 3 | | | 53.96 | | | 102 | | | 10.66 | |
Total | | 3,247 | | | 4.54 | | | 60 | | | 95.02 | | | 19 | | | 43.05 | | | 3,719 | | | 5.72 | |
| | | | | | | | | | | | | | | | |
Average NYMEX Price | | | | 4.95 | | | | | 94.29 | | | | | | | | | |
Average Realized Price (including realized derivatives) | | | | 3.08 | | | | | 65.64 | | | | | 43.05 | | | | | 3.96 | |
| | | | | | | | | | | | | | | | |
Natural Gas, Oil and NGL Sales
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended March 31, 2023 |
| | Natural Gas | | Oil | | NGL | | Total |
Marcellus | | $ | 617 | | | $ | — | | | $ | — | | | $ | 617 | |
Haynesville | | 402 | | | — | | | — | | | 402 | |
Eagle Ford | | 23 | | | 373 | | | 38 | | | 434 | |
| | | | | | | | |
Total natural gas, oil and NGL sales | | $ | 1,042 | | | $ | 373 | | | $ | 38 | | | $ | 1,453 | |
| | | | | | | | |
| | Three Months Ended March 31, 2022 |
| | Natural Gas | | Oil | | NGL | | Total |
Marcellus | | $ | 609 | | | $ | — | | | $ | — | | | $ | 609 | |
Haynesville | | 652 | | | — | | | — | | | 652 | |
Eagle Ford | | 47 | | | 450 | | | 57 | | | 554 | |
Powder River Basin | | 20 | | | 66 | | | 13 | | | 99 | |
Total natural gas, oil and NGL sales | | $ | 1,328 | | | $ | 516 | | | $ | 70 | | | $ | 1,914 | |
| | | | | | | | |
Natural gas, oil and NGL sales during the first three months of 2023 decreased $461 million compared to the first three months of 2022. Lower average prices, which were consistent with the downward trend in index prices for all products, drove a $512 million decrease during the first three months of 2023. Additionally, the Powder River Basin divestiture and lower sales volumes in Haynesville resulted in decreases of $99 million and $19 million, respectively. Partially offsetting these decreases was an increase of $162 million due to increased sales volumes in
ResultsMarcellus, primarily due to the Marcellus Acquisition in March 2022, and an increase of Operations – Three Months Ended September 30, 2017 vs September 30, 2016$7 million due to increased Eagle Ford sales volumes.
General. ForProduction Expenses
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended March 31, 2023 | | Three Months Ended March 31, 2022 |
| | | | $/Mcfe | | | | $/Mcfe |
Marcellus | | $ | 24 | | | 0.13 | | | $ | 13 | | | 0.10 | |
Haynesville | | 47 | | | 0.34 | | | 32 | | | 0.22 | |
Eagle Ford | | 60 | | | 1.23 | | | 55 | | | 1.15 | |
Powder River Basin | | — | | | — | | | 10 | | | 0.94 | |
Total production expenses | | $ | 131 | | | 0.36 | | | $ | 110 | | | 0.33 | |
Production expenses during the Current Quarter, Chesapeake had a net lossfirst three months of $172023 increased $21 million or $0.05 per diluted common share, on total revenuesas compared to the first three months of $1.943 billion. This compares to a net loss of $1.214 billion, or $1.62 per diluted common share, on total revenues of $2.276 billion for the Prior Quarter.2022. The net loss in the Current Quarterincrease was primarily due to non-cash unrealized hedging losses. The net lossan increase in saltwater disposal expenses, workovers and other preventative maintenance in Eagle Ford and Haynesville, as well as the Marcellus Acquisition in March 2022. These increases were partially offset by the divestiture of the Powder River Basin assets in March 2022.
Gathering, Processing and Transportation Expenses
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended March 31, 2023 | | Three Months Ended March 31, 2022 |
| | | | $/Mcfe | | | | $/Mcfe |
Marcellus | | $ | 111 | | | 0.62 | | | $ | 71 | | | 0.54 | |
Haynesville | | 68 | | | 0.49 | | | 65 | | | 0.45 | |
Eagle Ford | | 85 | | | 1.73 | | | 84 | | | 1.73 | |
Powder River Basin | | — | | | — | | | 22 | | | 2.32 | |
Total GP&T | | $ | 264 | | | 0.72 | | | $ | 242 | | | 0.72 | |
Gathering, processing and transportation expenses during the first three months of 2023 increased $22 million as compared to the first three months of 2022. Marcellus increased $40 million, primarily due to the Marcellus Acquisition in March 2022, while the divestiture of the Powder River Basin assets in March 2022 resulted in a decrease of $22 million.
Severance and Ad Valorem Taxes
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended March 31, 2023 | | Three Months Ended March 31, 2022 |
| | | | $/Mcfe | | | | $/Mcfe |
Marcellus | | $ | 5 | | | 0.03 | | | $ | 4 | | | 0.03 | |
Haynesville | | 34 | | | 0.24 | | | 12 | | | 0.09 | |
Eagle Ford | | 30 | | | 0.60 | | | 36 | | | 0.75 | |
Powder River Basin | | — | | | — | | | 11 | | | 1.09 | |
Total severance and ad valorem taxes | | $ | 69 | | | 0.19 | | | $ | 63 | | | 0.19 | |
Severance and ad valorem taxes during the first three months of 2023 increased $6 million as compared to the first three months of 2022. Legislative action led to changes in the Prior Quarter was primarily drivenHaynesville severance and ad valorem tax rates, which resulted in an increase of $20 million during the first three months of 2023. These increases were partially offset by non-cash impairmentsan $11 million decrease attributable to the divestiture of fixed assets and other and impairmentsthe Powder River Basin assets.
Adjusted Gross Margin by Operating Area
The tables below present the adjusted gross margin for each of our operating areas. Adjusted gross margin is defined as natural gas, oil and natural gas properties. See ImpairmentNGL sales less production expenses, gathering, processing and transportation expenses, and severance and ad valorem taxes. Adjusted gross margin is a non-GAAP measure, and a reconciliation of Oil and Natural Gas Properties and Impairmentsgross margin to adjusted gross margin is presented within the “Non-GAAP Measures” section of Fixed Assets and Other below.this Item 2.
Oil, | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended March 31, 2023 | | Three Months Ended March 31, 2022 |
| | | | $/Mcfe | | | | $/Mcfe |
Marcellus | | $ | 477 | | | 2.69 | | | $ | 521 | | | 3.99 | |
Haynesville | | 253 | | | 1.81 | | | 543 | | | 3.70 | |
Eagle Ford | | 259 | | | 5.26 | | | 379 | | | 7.81 | |
Powder River Basin | | — | | | — | | | 56 | | | 6.31 | |
Adjusted gross margin | | $ | 989 | | | 2.70 | | | $ | 1,499 | | | 4.48 | |
Natural Gas and NGL Sales. During the Current Quarter, oil, natural gas and NGL sales were $979 million compared to $1.177 billion in the Prior Quarter. In the Current Quarter, Chesapeake sold 50 mmboe for $1.049 billion at a weighted average price of $21.06 per boe (excluding the effect of derivatives), compared to 59 mmboe sold in the Prior Quarter for $1.048 billion at a weighted average price of $17.86 per boe (excluding the effect of derivatives). The increase in the price received per boe in the Current Quarter compared to the Prior Quarter resulted in a $159 million increase in revenues, and decreased sales volumes resulted in a $158 million decrease in revenues, for a total net increase in revenues of $1 million (excluding the effect of derivatives).Oil Derivatives
For the Current Quarter, our average price received per barrel of oil (excluding the effect of derivatives) was $47.94, compared to $42.94 in the Prior Quarter. Natural gas prices received per mcf (excluding the effect of derivatives) were $2.52 and $2.32 in the Current Quarter and the Prior Quarter, respectively. NGL prices received per barrel (excluding the price of derivatives) were $21.83 in the Current Quarter and $13.93 in the Prior Quarter. | | | | | | | | | | | | | | |
| | Three Months Ended March 31, 2023 | | Three Months Ended March 31, 2022 |
Natural gas derivatives - realized losses | | $ | (140) | | | $ | (428) | |
Natural gas derivatives - unrealized gains (losses) | | 1,021 | | | (1,372) | |
Total gains (losses) on natural gas derivatives | | $ | 881 | | | $ | (1,800) | |
| | | | |
Oil derivatives - realized losses | | $ | (49) | | | $ | (159) | |
Oil derivatives - unrealized gains (losses) | | 98 | | | (166) | |
Total gains (losses) on oil derivatives | | 49 | | | (325) | |
Total gains (losses) on natural gas and oil derivatives | | $ | 930 | | | $ | (2,125) | |
Gains (losses) from our oil, natural gas and NGL derivatives resulted in a net decrease in oil, natural gas and NGL revenues of $70 million in the Current Quarter and a net increase of $129 million in the Prior Quarter, respectively. See Item 3. Quantitative and Qualitative Disclosures About Market Risk in Part Iof this report for a listing of all of our derivative instruments as of September 30, 2017.
A change in oil, natural gas and NGL prices has a significant impact on our revenues and cash flows. Assuming our Current Quarter production levels and without considering the effect of derivatives, an increase or decrease of $1.00 per barrel of oil sold would result in an increase or decrease in Current Quarter revenues and cash flows of approximately $8 million, an increase or decrease of $0.10 per mcf of natural gas sold would result in an increase or decrease in Current Quarter revenues and cash flows of approximately $22 million, and an increase or decrease of $1.00 per barrel of NGL sold would result in an increase or decrease in Current Quarter revenues and cash flows of approximately $5 million.
The following tables show average daily production and average sales prices received by our operating divisions for the Current Quarter and the Prior Quarter:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, 2017 |
| | Oil | | Natural Gas | | NGL | | Total |
| | mbbl per day | | $/bbl(a) | | mmcf per day | | $/mcf(a) | | mbbl per day | | $/bbl(a) | | mboe per day | | % | | $/boe(a) |
Marcellus | | — |
| | — |
| | 757 |
| | 1.95 |
| | — |
| | — |
| | 126 |
| | 24 |
| | 11.70 |
|
Haynesville | | — |
| | — |
| | 805 |
| | 2.76 |
| | — |
| | — |
| | 134 |
| | 25 |
| | 16.59 |
|
Eagle Ford | | 52 |
| | 49.08 |
| | 136 |
| | 3.25 |
| | 18 |
| | 23.07 |
| | 93 |
| | 17 |
| | 36.91 |
|
Utica | | 12 |
| | 44.18 |
| | 475 |
| | 2.76 |
| | 28 |
| | 20.31 |
| | 120 |
| | 22 |
| | 20.21 |
|
Mid-Continent | | 16 |
| | 47.28 |
| | 174 |
| | 2.58 |
| | 11 |
| | 22.78 |
| | 56 |
| | 10 |
| | 26.10 |
|
Powder River Basin | | 6 |
| | 47.12 |
| | 35 |
| | 2.91 |
| | 2 |
| | 26.77 |
| | 13 |
| | 2 |
| | 31.01 |
|
Other(b) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Total | | 86 |
| | 47.94 |
| | 2,382 |
| | 2.52 |
| | 59 |
| | 21.83 |
| | 542 |
| | 100 | % | | 21.06 |
|
| | | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, 2016 |
| | Oil | | Natural Gas | | NGL | | Total |
| | mbbl per day | | $/bbl(a) | | mmcf per day | | $/mcf(a) | | mbbl per day | | $/bbl(a) | | mboe per day | | % | | $/boe(a) |
Marcellus | | — |
| | — |
| | 806 |
| | 1.62 |
| | — |
| | — |
| | 134 |
| | 22 |
| | 9.72 |
|
Haynesville | | — |
| | — |
| | 835 |
| | 2.59 |
| | — |
| | — |
| | 139 |
| | 22 |
| | 15.55 |
|
Eagle Ford | | 59 |
| | 43.80 |
| | 145 |
| | 3.00 |
| | 18 |
| | 14.97 |
| | 101 |
| | 15 |
| | 32.35 |
|
Utica | | 11 |
| | 37.77 |
| | 498 |
| | 2.60 |
| | 33 |
| | 12.79 |
| | 127 |
| | 20 |
| | 16.80 |
|
Mid-Continent | | 12 |
| | 43.87 |
| | 203 |
| | 2.48 |
| | 9 |
| | 16.37 |
| | 55 |
| | 9 |
| | 21.53 |
|
Powder River Basin | | 5 |
| | 42.16 |
| | 37 |
| | 2.64 |
| | 3 |
| | 15.80 |
| | 14 |
| | 2 |
| | 25.68 |
|
Other(b) | | — |
| | — |
| | 390 |
| | 2.46 |
| | 3 |
| | 10.68 |
| | 68 |
| | 10 |
| | 14.63 |
|
Total | | 87 |
| | 42.94 |
| | 2,914 |
| | 2.32 |
| | 66 |
| | 13.93 |
| | 638 |
| | 100 | % | | 17.86 |
|
| |
(a) | Average sales prices exclude gains and/or losses on derivatives. |
| |
(b) | Includes Central Texas and the Devonian Shale which were divested in the 2016 fourth quarter. |
Our average daily production of 542 mboe for the Current Quarter consisted of approximately 86 mbbls of oil (16% on an oil equivalent basis), approximately 2,382 mmcf of natural gas (73% on an oil equivalent basis) and approximately 59 mbbls of NGL (11% on an oil equivalent basis). Oil production decreased by 1%, natural gas production decreased by 18% and NGL production decreased by 11% year over year primarily as a result of the sale of certain of our Barnett, Mid-Continent and Devonian assets in 2016 and the sale of certain of our Haynesville Shale assets in 2017.
Excluding the impact of derivatives, our percentage of revenues from oil, natural gas and NGL is shown in the following table:
|
| | | | | | |
| | Three Months Ended September 30, |
| | 2017 | | 2016 |
Oil | | 36 |
| | 33 |
|
Natural gas | | 53 |
| | 59 |
|
NGL | | 11 |
| | 8 |
|
Total | | 100 | % | | 100 | % |
Marketing, Gathering and Compression Revenues and Expenses. Marketing, gathering and compression revenues consist of third-party revenues, and historically, the fair value adjustments on our supply contract derivatives (see Note 811 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for additional information ona discussion of our supply contract derivatives).derivative activity.
General and Administrative Expenses related to our marketing, gathering and compression operations consist of third-party expenses and exclude depreciation and amortization,
| | | | | | | | | | | | | | |
| | Three Months Ended March 31, 2023 | | Three Months Ended March 31, 2022 |
| | |
Total G&A, net | | $ | 35 | | | $ | 26 | |
G&A, net per Mcfe | | $ | 0.09 | | | $ | 0.08 | |
Total general and administrative expenses, impairmentsnet during the first three months of fixed assets and other, net gains or losses on sales of fixed assets and interest expense. See Depreciation and Amortization of Other Assets below for the depreciation and amortization recorded on our marketing, gathering and compression assets. We recognized $9642023 increased $9 million in marketing, gathering and compression revenues in the Current Quarter with corresponding expenses of $978 million, for a net loss of $14 million. This compares to revenues of $1.099 billion, of which $146 million related to cash proceeds from the sale of our long-term natural gas supply contract to a third party offset by the reversal of the cumulative unrealized gains of $280 million, with corresponding expenses of $1.261 billion, for a net loss of $162 million in the Prior Quarter. Although higher oil, natural gas and NGL prices were paid and received in our marketing operations, revenues and expenses decreased in the Current Quarter compared to the Prior Quarterfirst three months of 2022, primarily due to adjustments in employee benefits and compensation as a resultwell as increases in other corporate expenses.
Depreciation, Depletion and terminations.Amortization
Oil, Natural Gas and NGL Production Expenses. Production expenses, which include lifting costs and ad valorem taxes, were $151 million in the Current Quarter, compared to $164 million in the Prior Quarter. The decrease in the Current Quarter was primarily a result of the sale of certain oil and natural gas properties in 2016 and 2017. On a unit-of-production basis, production expenses were $3.03 per boe in the Current Quarter compared to $2.80 per boe in the Prior Quarter. The per unit increase in the Current Quarter was the result of higher workover and repair and maintenance expenses. Production expenses in the Current Quarter and the Prior Quarter included approximately $5 million and $10 million, or $0.10 and $0.17 per boe, respectively, associated with VPP production volumes. In connection with certain 2016 divestitures, we purchased the remaining oil and natural gas interests previously sold in connection with five of our VPPs, and a majority of these repurchased oil and natural gas interests were subsequently sold. We anticipate a continued decrease in production expenses associated with VPP production volumes as the contractually scheduled volumes under our remaining VPP agreement decrease and operating efficiencies generally improve. | | | | | | | | | | | | | | |
| | Three Months Ended March 31, 2023 | | Three Months Ended March 31, 2022 |
DD&A | | $ | 390 | | | $ | 409 | |
DD&A per Mcfe | | $ | 1.06 | | | $ | 1.22 | |
Oil, Natural Gas, and NGL Gathering, Processing and Transportation Expenses. Oil, natural gas and NGL gathering, processing and transportation expenses were $369 million in the Current Quarter compared to $473 million in the Prior Quarter. On a unit-of-production basis, gathering, processing and transportation expenses were $7.40 per boe in the Current Quarter compared to $8.07 per boe in the Prior Quarter. The absolute and per unit decreasedecreases in depreciation, depletion and amortization for the first three months of 2023 compared to the first three months of 2022, are primarily related to our Eagle Ford divestitures, partially offset by an increase related to the Marcellus Acquisition in 2016March 2022. We cease recording depreciation on assets that are classified as held for sale.
Other Operating Expense, Net
| | | | | | | | | | | | | | |
| | Three Months Ended March 31, 2023 | | Three Months Ended March 31, 2022 |
Other operating expense, net | | $ | 3 | | | $ | 23 | |
During the first three months of 2022, we recognized approximately $23 million of costs related to our Marcellus Acquisition, which included consulting fees, financial advisory fees, legal fees and 2017. A summarychange in control expense in accordance with Chief’s existing employment agreements.
Interest Expense
| | | | | | | | | | | | | | |
| | Three Months Ended March 31, 2023 | | Three Months Ended March 31, 2022 |
| | |
Interest expense on debt | | $ | 46 | | | $ | 38 | |
| | | | |
Amortization of premium, issuance costs and other | | (2) | | | (1) | |
Capitalized interest | | (7) | | | (5) | |
Total interest expense | | $ | 37 | | | $ | 32 | |
The increase in total interest expense during the first three months of oil, natural gas and NGL gathering, processing and transportation expenses by product is shown below.
|
| | | | | | | | |
| | Three Months Ended September 30, |
| | 2017 | | 2016 |
Oil ($ per bbl) | | $ | 4.33 |
| | $ | 3.67 |
|
Natural gas ($ per mcf) | | $ | 1.34 |
| | $ | 1.47 |
|
NGL ($ per bbl) | | $ | 7.40 |
| | $ | 8.13 |
|
Production Taxes. Production taxes were $21 million in the Current Quarter2023 compared to $17 million in the Prior Quarter. On a unit-of-production basis, production taxes were $0.43 per boe in the Current Quarter compared to $0.29 per boe in the Prior Quarter. In general, production taxes are calculated using value-based formulas that produce higher per unit costs when oil, natural gas and NGL prices are higher. The absolute and per unit increase in production taxes in the Current Quarterfirst three months of 2022 was primarily due to higher prices receivedaverage debt outstanding between periods.
Income Taxes
Income tax expense was $404 million for our oil, natural gas and NGL production. Production taxes in both the Current Quarter and the Prior Quarter included $1first three months of 2023. Of this amount, $26 million or $0.01 and $0.02 per boe, respectively, associated with VPP production volumes.
General and Administrative Expenses. General and administrative expenses were $54 million in the Current Quarter and $63 million in the Prior Quarter, or $1.08 per boe in both the Current Quarter and the Prior Quarter. Chesapeake follows the full cost method of accounting under which all costs associated with oil and natural gas property acquisition, drilling and completion activities are capitalized. We capitalize internal costs that can be directly identified with the acquisition of leasehold, as well as drilling and completion activities, and we do not include any costs related to production, general corporate overhead or similar activities. We capitalized $37 million and $38 million of internal costs in the Current Quarter and the Prior Quarter, respectively, directly related to our leasehold acquisition and drilling and completion efforts.
Provision for Legal Contingencies. In the Current Quarter and the Prior Quarter, we recorded expense of $20 million and $8 million, respectively, for legal contingencies. Both the Current Quarter and the Prior Quarter provisions consist of adjustments for loss contingencies primarily related to royalty claims. See Note 4 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for further discussion of royalty claims.
Oil, Natural Gas and NGL Depreciation, Depletion and Amortization. Depreciation, depletion and amortization (DD&A) of oil, natural gas and NGL properties was $228 million and $251 million in the Current Quarter and the Prior Quarter, respectively. The decrease in the Current Quarter was primarily the result of decreased productionprojecting current federal and state income taxes, predominately as a result of the sale of certain of our Barnett and Mid-Continent assets in 2016taxable gains on closed divestitures, and the sale of certain of our Haynesville Shale assets in 2017. The average DD&A rate per boe, whichremainder is a function of capitalized costs, future development costs and the related underlying reserves in the periods presented, was $4.57 and $4.26 in the Current Quarter and the Prior Quarter, respectively.
Depreciation and Amortization of Other Assets. Depreciation and amortization of other assets was $20 million in the Current Quarter compared to $25 million in the Prior Quarter. On a unit-of-production basis, depreciation and amortization of other assets was $0.41 per boe in the Current Quarter compared to $0.42 per boe in the Prior Quarter. Property and equipment costs are depreciated on a straight-line basis over the estimated useful lives of the assets. The following table shows depreciation expense by asset class for the Current Quarter and the Prior Quarter and the estimated useful lives of these assets.
|
| | | | | | | | | | |
| | Three Months Ended September 30, | | Estimated Useful Life |
| | 2017 | | 2016 | |
| | ($ in millions) | | (in years) |
Buildings and improvements | | $ | 9 |
| | $ | 9 |
| | 10 – 39 |
Computers and office equipment | | 5 |
| | 5 |
| | 5 – 7 |
Natural gas compressors(a) | | 4 |
| | 6 |
| | 3 – 20 |
Vehicles | | — |
| | 1 |
| | 5 |
Natural gas gathering systems and treating plants(a) | | — |
| | 2 |
| | 20 |
Other | | 2 |
| | 2 |
| | 5 – 12 |
Total depreciation and amortization of other assets | | $ | 20 |
| | $ | 25 |
| | |
| |
(a) | Included in our marketing, gathering and compression operating segment. |
Impairment of Oil and Natural Gas Properties. Our oil and natural gas properties are subject to quarterly full cost ceiling tests. Under the ceiling test, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed a ceiling amount equal to the sum of the present value of estimated future net revenues (adjusted for cash flow hedges) less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. In the Current Quarter, capitalized costs of oil and natural gas properties did not exceed the ceiling. For the Prior Quarter, capitalized costs of oil and natural gas properties exceeded the ceiling, resulting in an impairment of the carrying value of our oil and natural gas properties of $497 million.
Impairments of Fixed Assets and Other. In the Current Quarter and the Prior Quarter, we recognized $9 million and $751 million, respectively, of fixed asset impairment losses and other charges. On October 31, 2016, we conveyed our interests in the Barnett Shale operating area located in north central Texas and simultaneously terminated most of our future commitments associated with this asset. In connection with this transaction, we accrued $334 million of charges in the Prior Quarter related to terminationprojections of a natural gas gathering agreement associated with the Barnett Shale Assets. Additionally, certain of our other propertydeferred federal and equipment, including buildings, surface land, compressors and office equipment, qualified as held for sale as of September 30, 2016. We recognized an impairment charge of $282 million in the Prior Quarter related to these assets representing the difference between the carrying amount and the fair value of the assets, less the anticipated costs to sell. Also in the Prior Quarter, we entered into a purchase and sale agreement to sell the majority of our upstream and midstream assets in the Devonian shale located in West Virginia and Kentucky. We recognized an impairment charge of $134 million in the Prior Quarter for these assets for the difference between the carrying amount and the fair value of the assets, less the anticipated costs to sell.
Net Gains on Sales of Fixed Assets. Net gains on sales of fixed assets were $1 million in the Current Quarter. The Current Quarter amounts primarily related to the sale of other property and equipment.
Interest Expense. Interest expense was $114 million in the Current Quarter compared to $73 million in the Prior Quarter as follows:
|
| | | | | | | | |
| | Three Months Ended September 30, |
| | 2017 | | 2016 |
| | ($ in millions) |
Interest expense on senior notes | | $ | 135 |
| | $ | 141 |
|
Interest expense on term loan | | 34 |
| | 14 |
|
Amortization of loan discount, issuance costs and other | | 13 |
| | 9 |
|
Amortization of premium associated with troubled debt restructuring | | (29 | ) | | (41 | ) |
Interest expense on revolving credit facility | | 11 |
| | 10 |
|
Realized gains on interest rate derivatives(a) | | (1 | ) | | (3 | ) |
Unrealized losses on interest rate derivatives(b) | | — |
| | 2 |
|
Capitalized interest | | (49 | ) | | (59 | ) |
Total interest expense | | $ | 114 |
| | $ | 73 |
|
| | | | |
Average senior notes borrowings | | $ | 7,632 |
| | $ | 8,348 |
|
Average credit facilities borrowings | | $ | 631 |
| | $ | 245 |
|
Average term loan borrowings | | $ | 1,500 |
| | $ | 636 |
|
| |
(a) | Includes settlements related to the interest accrual for the period and the effect of (gains) losses on early-terminated trades. Settlements of early-terminated trades are reflected in realized (gains) losses over the original life of the hedged item. |
| |
(b) | Includes changes in the fair value of interest rate derivatives offset by amounts reclassified to realized (gains) losses during the period. |
The increase in interest expense is primarily due to an increase in term loan interest expense and a decrease in capitalized interest as a result of lower average balances of unproved oil and natural gas properties, the primary asset on which interest is capitalized. Interest expense, excluding unrealized gains or losses on interest rate derivatives and net of amounts capitalized, was $2.26 per boe in the Current Quarter compared to $1.20 per boe in the Prior Quarter.
Losses on Investments. Losses on investments of $1 million in the Prior Quarter were related to our equity investment in Sundrop Fuels, Inc.
Gains (Losses) on Purchases or Exchanges of Debt. In the Current Quarter, we repurchased $5 million principal amount of our outstanding senior notes and contingent convertible senior notes for $6 million. We recorded an aggregate loss of approximately $1 million associated with the transaction.
In the Prior Quarter, we used the proceeds from our $1.5 billion term loan facility to purchase and retire $898 million principal amount of our senior notes and $708 million principal amount of our contingent convertible senior notes for an aggregate $1.5 billion pursuant to tender offers. We recognized an aggregate gain of $87 million associated with these transactions.
Income Tax Expense (Benefit). Chesapeake recorded a nominal amount ofstate income taxes. An income tax benefit inof $46 million was recorded during the Current Quarter.first three months of 2022. A tax benefit was recorded during the first three months of 2022 due to the application of our estimated annual effective tax rate to the book net loss before income taxes recorded during the first three months of 2022. Our effective income tax rates were 0.0%was 22.5% and 5.7% during the first three months of 2023 and 2022, respectively. The fluctuation in both the Current Quarter and the Prior Quarter. The resulting effective income tax rates for the Current Quarter and the Prior Quarter are primarily due to the offsetting impact of the change in the valuation allowance. Further, our effective tax rate is mainly because we are no longer maintaining a full valuation allowance against our deferred tax assets during the first three months of 2023 as we were during the first three months of 2022. Our effective tax rate can also fluctuate as a result of the impact of discrete items, state income taxes and permanent differences. See Note 128 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for a discussion of income tax expense (benefit).taxes.
Management uses adjusted gross margin to Noncontrolling Interests. Chesapeake recorded net income attributable to noncontrolling interests of $1 million in the Current Quarterassess our operating results and the Prior Quarter. In both quarters, activity was attributable to the Chesapeake Granite Wash Trust.
Results of Operations – Nine Months Ended September 30, 2017 vs September 30, 2016
General. For the Current Period, Chesapeake had net income of $619 million, or $0.56 per diluted common share, on total revenues of $6.977 billion. This compares to a net loss of $4.058 billion, or $5.80 per diluted common share, on total revenues of $5.851 billion for the Prior Period. The increase in net income in the Current Period is attributable to an increase in the average realized prices we received for oil,financial performance across assets and periods. We define adjusted gross margin as natural gas, and NGL production, partially offset by charges for terminating certain natural gas and oil transportation commitments. The net loss in the Prior Period was primarily driven by non-cash impairments of oil and natural gas properties and impairments of fixed assets and other. See Impairment of Oil and Natural Gas Properties and Impairments of Fixed Assets and Other below.
Oil, Natural Gas and NGL Sales. During the Current Period, oil, natural gas and NGL sales were $3.727 billion compared to $2.610 billion in the Prior Period. In the Current Period, Chesapeake sold 145 mmboe for $3.275 billion at a weighted average price of $22.53 per boe (excluding the effect of derivatives), compared to 180 mmboe sold in the Prior Period for $2.744 billion at a weighted average price of $15.27 per boe (excluding the effect of derivatives). The increase in the price received per boe in the Current Period compared to the Prior Period resulted in a $1.055 billion increase in revenues, and decreased sales volumes resulted in a $524 million decrease in revenues, for a total net increase in revenues of $531 million (excluding the effect of derivatives).
For the Current Period, our average price received per barrel of oil (excluding the effect of derivatives) was $48.53, compared to $38.21 in the Prior Period. Natural gas prices received per mcf (excluding the effect of derivatives) were $2.83 and $1.90 in the Current Period and the Prior Period, respectively. NGL prices received per barrel (excluding the effect of derivatives) were $21.28 and $12.90 in the Current Period and the Prior Period, respectively.
Gains from our oil, natural gas and NGL derivatives resulted in a net increase in oil, natural gas and NGL revenues of $452 million in the Current Period and a net decrease of $134 million in the Prior Period, respectively. See Item 3. Quantitative and Qualitative Disclosures About Market Risk in Part Iof this report for a listing of all of our derivative instruments as of September 30, 2017.
A change in oil, natural gas and NGL prices has a significant impact on our revenues and cash flows. Assuming our Current Periodless production levels and without considering the effect of derivatives, an increase or decrease of $1.00 per barrel of oil sold would result in an increase or decrease in Current Period revenues and cash flows of approximately $23 million, an increase or decrease of $0.10 per mcf of natural gas sold would result in an increase or decrease in Current Period revenues and cash flows of approximately $64 million and $63 million, respectively, and an increase or decrease of $1.00 per barrel of NGL sold would result in an increase or decrease in Current Period revenues and cash flows of approximately $15 million.
The following tables show average daily production and average sales prices received by our operating divisions for the Current Period and the Prior Period:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Nine Months Ended September 30, 2017 |
| | Oil | | Natural Gas | | NGL | | Total |
| | mbbl per day | | $/bbl(a) | | mmcf per day\ | | $/mcf(a) | | mbbl per day | | $/bbl(a) | | mboe per day | | % | | $/boe(a) |
Marcellus | | — |
| | — |
| | 815 |
| | 2.51 |
| | — |
| | — |
| | 136 |
| | 25 |
| | 15.05 |
|
Haynesville | | — |
| | — |
| | 751 |
| | 2.90 |
| | — |
| | — |
| | 125 |
| | 24 |
| | 17.44 |
|
Eagle Ford | | 55 |
| | 49.42 |
| | 139 |
| | 3.36 |
| | 18 |
| | 21.27 |
| | 96 |
| | 18 |
| | 37.22 |
|
Utica | | 9 |
| | 44.01 |
| | 411 |
| | 3.12 |
| | 26 |
| | 20.87 |
| | 104 |
| | 19 |
| | 21.52 |
|
Mid-Continent | | 16 |
| | 48.20 |
| | 189 |
| | 2.84 |
| | 10 |
| | 21.59 |
| | 57 |
| | 11 |
| | 26.31 |
|
Powder River Basin | | 6 |
| | 48.12 |
| | 34 |
| | 3.06 |
| | 2 |
| | 24.52 |
| | 14 |
| | 3 |
| | 31.58 |
|
Other(b) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Total | | 86 |
| | 48.53 |
| | 2,339 |
| | 2.83 |
| | 56 |
| | 21.28 |
| | 532 |
| | 100 | % | | 22.53 |
|
| | | | | | | | | | | | | | | | | | |
| | Nine Months Ended September 30, 2016 |
| | Oil | | Natural Gas | | NGL | | Total |
| | mbbl per day | | $/bbl(a) | | mmcf per day | | $/mcf(a) | | mbbl per day | | $/bbl(a) | | mboe per day | | % | | $/boe(a) |
Marcellus | | — |
| | — |
| | 825 |
| | 1.42 |
| | — |
| | — |
| | 138 |
| | 21 |
| | 8.54 |
|
Haynesville | | — |
| | — |
| | 754 |
| | 2.13 |
| | — |
| | — |
| | 126 |
| | 19 |
| | 12.79 |
|
Eagle Ford | | 55 |
| | 39.72 |
| | 138 |
| | 2.40 |
| | 17 |
| | 13.28 |
| | 95 |
| | 14 |
| | 28.78 |
|
Utica | | 14 |
| | 32.44 |
| | 514 |
| | 2.15 |
| | 34 |
| | 12.26 |
| | 134 |
| | 21 |
| | 14.75 |
|
Mid-Continent | | 16 |
| | 38.15 |
| | 279 |
| | 1.87 |
| | 13 |
| | 13.95 |
| | 76 |
| | 12 |
| | 17.44 |
|
Powder River Basin | | 6 |
| | 38.22 |
| | 39 |
| | 2.20 |
| | 3 |
| | 15.60 |
| | 15 |
| | 2 |
| | 23.74 |
|
Other(b) | | — |
| | — |
| | 421 |
| | 1.94 |
| | 3 |
| | 10.82 |
| | 72 |
| | 11 |
| | 11.64 |
|
Total | | 91 |
| | 38.21 |
| | 2,970 |
| | 1.90 |
| | 70 |
| | 12.90 |
| | 656 |
| | 100 | % | | 15.27 |
|
| |
(a) | Average sales prices exclude gains and/or losses on derivatives. |
| |
(b) | Includes Central Texas and the Devonian Shale which were divested in the 2016 fourth quarter. |
Our average daily production of 532 mboe for the Current Period consisted of approximately 86 mbbls of oil (16% on an oil equivalent basis), approximately 2,339 mmcf of natural gas (73% on an oil equivalent basis) and approximately 56 mbbls of NGL (11% on an oil equivalent basis). Oil production decreased by 6%, natural gas production decreased by 22% and NGL production decreased by 19% year over year primarily as a result of the sale of certain of our Barnett, Mid-Continent and Devonian assets in 2016 and the sale of certain of our Haynesville Shale assets in 2017.
Excluding the impact of derivatives, our percentage of revenues from oil, natural gas and NGL is shown in the following table:
|
| | | | | | |
| | Nine Months Ended September 30, |
| | 2017 | | 2016 |
Oil | | 35 |
| | 35 |
|
Natural gas | | 55 |
| | 56 |
|
NGL | | 10 |
| | 9 |
|
Total | | 100 | % | | 100 | % |
Marketing, Gathering and Compression Revenues and Expenses. Marketing, gathering and compression revenues consist of third-party revenues, and historically, the fair value adjustments on our supply contract derivatives (see Note 8 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for additional information on our supply contract derivatives). Expenses related to our marketing, gathering and compression operations consist of third-party expenses, and exclude depreciation and amortization, general and administrative expenses, impairments of fixed assets and other, net gains or losses on sales of fixed assets and interest expense. See Depreciation and Amortization of Other Assets below for the depreciation and amortization recorded on our marketing, gathering and compression assets. We recognized $3.250 billion in marketing, gathering and compression revenues in the Current Period with corresponding expenses of $3.333 billion, for a net loss of $83 million. This compares to revenues of $3.241 billion, of which $146 million related to cash proceeds from the sale of our long-term natural gas supply contract to a third party offset by the reversal of the cumulative unrealized gains of $297 million, with corresponding expenses of $3.410 billion, for a net loss of $169 million in the Prior Period. Revenues increased in the Current Period compared to the Prior Period primarily as a result of higher oil, natural gas and NGL prices paid and received in our marketing operations. The margin increase in the Current Period as compared to the Prior Period was primarily the result of the sale of a significant portion of our gathering and compression assets, concurrently with the associated upstream assets. Additionally, the Current Period includes losses on certain transportation contracts with third parties associated with assets divested in the fourth quarter of 2016.
Oil, Natural Gas and NGL Production Expenses. Production expenses, which include lifting costs and ad valorem taxes, were $426 million in the Current Period, compared to $552 million in the Prior Period. On a unit-of-production basis, production expenses were $2.93 per boe in the Current Period compared to $3.07 per boe in the Prior Period. The absolute and per unit decrease in the Current Period was the result of operating efficiencies across most of our operating areas, as well as the sale of certain oil and natural gas properties in 2016. Production expenses in the Current Period and the Prior Period included approximately $15 million and $38 million, or $0.11 and $0.21 per boe, respectively, associated with VPP production volumes. In connection with certain 2016 divestitures, we purchased the remaining oil and natural gas interests previously sold in connection with five of our VPPs, and a majority of these repurchased oil and natural gas interests were subsequently sold. We anticipate a continued decrease in production expenses associated with VPP production volumes as the contractually scheduled volumes under our remaining VPP agreement decrease and operating efficiencies generally improve.
Oil, Natural Gas, and NGL Gathering, Processing and Transportation Expenses. Oil, natural gas and NGL gathering, processing and transportation expenses, were $1.081 billionand severance and ad valorem taxes.
Adjusted gross margin is not a measure of financial performance under GAAP and should not be considered in the Current Period compared to $1.436 billion in the Prior Period. Onisolation or as a unit-of-production basis, gathering, processing and transportation expenses were $7.43 per boe in the Current Period compared to $7.99 per boe in the Prior Period. The absolute and per unit decrease primarily related to divestitures in 2016. A summary of oil, natural gas and NGL gathering, processing and transportation expenses by product is shown below.
|
| | | | | | | | |
| | Nine Months Ended September 30, |
| | 2017 | | 2016 |
Oil ($ per bbl) | | $ | 3.96 |
| | $ | 3.53 |
|
Natural gas ($ per mcf) | | $ | 1.36 |
| | $ | 1.47 |
|
NGL ($ per bbl) | | $ | 7.90 |
| | $ | 7.77 |
|
Production Taxes. Production taxes were $64 million in the Current Period compared to $54 million in the Prior Period. On a unit-of-production basis, production taxes were $0.44 per boe in the Current Period compared to $0.30 per boe in the Prior Period. In general, production taxes are calculated using value-based formulas that produce higher per unit costs when oil, natural gas and NGL prices are higher. The absolute and per unit increase in production taxes in the Current Period was primarily due to higher prices receivedsubstitute for our oil, natural gas and NGL production. Production taxes in the Current Period and the Prior Period included $1 million and $3 million, or a nominal amount and $0.02 per boe, respectively, associated with VPP production volumes.
General and Administrative Expenses. General and administrative expenses were $189 million in the Current Period and $172 million in the Prior Period, or $1.30 and $0.96 per boe, respectively. The absolute and per unit expense increase in the Current Period was primarily due to less overhead reflected as oil, natural gas and NGL production expenses, as well as less overhead billed to third party working interest owners, resulting from certain divestitures in 2016 and 2017.
Chesapeake follows the full cost method of accounting under which all costs associated with oil and natural gas property acquisition, drilling and completion activities are capitalized. We capitalize internal costs that can be directly identified with the acquisition of leasehold, as well as drilling and completion activities, and we do not include any costs related to production, general corporate overhead or similar activities. We capitalized $105 million and $110 million of internal costs in the Current Period and the Prior Period, respectively, directly related to our leasehold acquisition and drilling and completion efforts.
Restructuring and Other Termination Costs. We recorded an expense of $3 million in the Prior Period for restructuring and other termination costs primarily related to the reduction in workforce in connection with the restructuringanalysis of our compressor manufacturing subsidiary.
Provision for Legal Contingencies. In the Current Period and the Prior Period, we recorded expense of $35 million and $112 million, respectively, for legal contingencies. Both the Current Period and the Prior Period provisions consist of adjustments for loss contingencies primarily relatedresults reported under GAAP. Additionally, adjusted gross margin may not be comparable to royalty claims. See Note 4 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for further discussion of royalty claims.
Oil, Natural Gas and NGL Depreciation, Depletion and Amortization. Depreciation,similarly titled measures used by other companies. We exclude depreciation, depletion and amortization (DD&A)from the calculation of oil, natural gas and NGL properties was $627 million and $791 million in the Current Period and the Prior Period, respectively. The average DD&A rate per boe, which is a function of capitalized costs, future development costs and the related underlying reserves in the periods presented, was $4.31 and $4.40 in the Current Period and the Prior Period, respectively. The absolute and per unit decrease in the Current Period was primarily the result of the sale of certain of our Barnett and Mid-Continent assets in 2016 and the sale of certain of our Haynesville Shale assets in 2017.
Depreciation and Amortization of Other Assets. Depreciationadjusted gross margin as depreciation, depletion and amortization of other assets was $62 million in the Current Period comparedare non-cash expenses that do not necessarily reflect present-day performance. The table below reconciles gross margin, as defined by GAAP, to $83 million in the Prior Period. On a unit-of-production basis, depreciation and amortization of other assets was $0.43 per boe in the Current Period compared to $0.46 per boe in the Prior Period. Property and equipment costs are depreciated on a straight-line basis over the estimated useful lives of the assets. The following table shows depreciation expense by asset class for the Current Period and the Prior Period and the estimated useful lives of these assets.adjusted gross margin.
| | | | | | | | | | | | | | |
| | Three Months Ended March 31, 2023 | | Three Months Ended March 31, 2022 |
| | |
Gross margin (GAAP) | | | | |
Natural gas, oil and NGL sales | | $ | 1,453 | | | $ | 1,914 | |
Less: | | | | |
Production expenses | | (131) | | | (110) | |
Gathering, processing and transportation expenses | | (264) | | | (242) | |
Severance and ad valorem taxes | | (69) | | | (63) | |
Depreciation, depletion and amortization | | (390) | | | (409) | |
Gross margin (GAAP) | | 599 | | | 1,090 | |
Add back: Depreciation, depletion and amortization | | 390 | | | 409 | |
Adjusted gross margin (Non-GAAP) | | $ | 989 | | | $ | 1,499 | |
|
| | | | | | | | | | |
| | Nine Months Ended September 30, | | Estimated Useful Life |
| | 2017 | | 2016 | |
| | ($ in millions) | | (in years) |
Buildings and improvements | | $ | 27 |
| | $ | 29 |
| | 10 – 39 |
Computers and office equipment | | 16 |
| | 15 |
| | 5 – 7 |
Natural gas compressors(a) | | 12 |
| | 20 |
| | 3 – 20 |
Vehicles | | 1 |
| | 2 |
| | 5 |
Natural gas gathering systems and treating plants(a) | | — |
| | 7 |
| | 20 |
Other | | 6 |
| | 10 |
| | 5 – 12 |
Total depreciation and amortization of other assets | | $ | 62 |
| | $ | 83 |
| | |
| | |
(a) | Included in our marketing, gathering and compression operating segment.Forward-Looking Statements |
Impairment of Oil and Natural Gas Properties. Our oil and natural gas properties are subject to quarterly full cost ceiling tests. Under the ceiling test, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed a ceiling amount equal to the sum of the present value of estimated future net revenues (adjusted for cash flow hedges) less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. In the Current Period, capitalized costs of oil and natural gas properties did not exceed the ceiling. For the Prior Period, capitalized costs of oil and natural gas properties exceeded the ceiling, resulting in an impairment of the carrying value of our oil and natural gas properties of $2.564 billion.
Impairments of Fixed Assets and Other. In the Current Period and the Prior Period, we recognized $426 million and $795 million, respectively, of fixed asset impairment losses and other charges. In the Current Period, we paid $290 million to assign an oil transportation agreement to a third party. In addition, we terminated future natural gas transportation commitments related to divested assets for a cash payment of $126 million. On October 31, 2016, we
conveyed our interests in the Barnett Shale operating area located in north central Texas and simultaneously terminated most of our future commitments associated with this asset. In connection with this transaction, we accrued $334 million of charges in the Prior Period related to termination of a natural gas gathering agreement associated with the Barnett Shale Assets. Additionally, certain of our other property and equipment, including buildings, surface land, compressors and office equipment, qualified as held for sale as of September 30, 2016. We recognized an impairment charge of $282 million in the Prior Period related to these assets representing the difference between the carrying amount and the fair value of the assets, less the anticipated costs to sell. Also in the Prior Period, we entered into a purchase and sale agreement to sale the majority of our upstream and midstream assets in the Devonian shale located in West Virginia and Kentucky. We recognized an impairment charge of $134 million in the Prior Period for these assets for the difference between the carrying amount and the fair value of the assets, less the anticipated costs to sell.
Net Gains on Sales of Fixed Assets. In the Prior Period, net gains on sales of fixed assets were $5 million. The Prior Period amounts primarily related to the sale of buildings, land and other property and equipment.
Interest Expense. Interest expense was $302 million in the Current Period compared to $197 million in the Prior Period as follows:
|
| | | | | | | | |
| | Nine Months Ended September 30, |
| | 2017 | | 2016 |
| | ($ in millions) |
Interest expense on senior notes | | $ | 407 |
| | $ | 446 |
|
Interest expense on term loan | | 98 |
| | 14 |
|
Amortization of loan discount, issuance costs and other | | 28 |
| | 27 |
|
Amortization of premium associated with troubled debt restructuring | | (112 | ) | | (124 | ) |
Interest expense on revolving credit facility | | 28 |
| | 27 |
|
Realized gains on interest rate derivatives(a) | | (3 | ) | | (9 | ) |
Unrealized losses on interest rate derivatives(b) | | 3 |
| | 7 |
|
Capitalized interest | | (147 | ) | | (191 | ) |
Total interest expense | | $ | 302 |
| | $ | 197 |
|
| | | | |
Average senior notes borrowings | | $ | 7,640 |
| | $ | 8,945 |
|
Average credit facilities borrowings | | $ | 330 |
| | $ | 257 |
|
Average term loan borrowings | | $ | 1,500 |
| | $ | 213 |
|
| |
(a) | Includes settlements related to the interest accrual for the period and the effect of (gains) losses on early-terminated trades. Settlements of early-terminated trades are reflected in realized (gains) losses over the original life of the hedged item. |
| |
(b) | Includes changes in the fair value of interest rate derivatives offset by amounts reclassified to realized (gains) losses during the period. |
The increase in interest expense is primarily due to an increase in term loan interest expense and a decrease in capitalized interest as a result of lower average balances of unproved oil and natural gas properties, the primary asset on which interest is capitalized. The overall increase in interest expense is offset in part by a decrease in interest expense on senior notes due to the decrease in the average outstanding principal amount of senior notes. Interest expense, excluding unrealized gains or losses on interest rate derivatives and net of amounts capitalized, was $2.05 per boe in the Current Period compared to $1.06 per boe in the Prior Period.
Losses on Investments. Losses on investments of $3 million in the Prior Period were related to our equity investment in Sundrop Fuels, Inc.
Loss on Sale of Investment. In the Prior Period, we sold certain of our mineral interests and assigned our partnership interest in Mineral Acquisition Company I, L.P. to KKR Royalty Aggregator LLC. As a result of the transaction, we wrote off our equity investment and recognized a $10 million loss.
Gains (Losses) on Purchases or Exchanges of Debt. In the Current Period, we retired $1.609 billion principal amount of our outstanding senior notes, senior secured second lien notes and contingent convertible notes through purchases in the open market, tender offers or repayment upon maturity for $1.751 billion, which included the maturity of our 6.25% Euro-denominated Senior Notes due 2017 and the corresponding cross currency swap. We recorded an aggregate gain of approximately $183 million associated with the repurchases and tender offers.
In the Prior Period, we retired $2.192 billion principal amount of our outstanding senior notes and contingent convertible senior notes through purchases in the open market, tender offers or repayment upon maturity for $1.5 billion. Additionally, we privately negotiated an exchange of approximately $577 million principal amount of our outstanding senior notes and contingent convertible senior notes for 109,351,707 common shares. We recorded an aggregate gain of approximately $255 million associated with the repurchases and exchanges.
Income Tax Expense (Benefit). Chesapeake recorded an income tax expense of $2 million in the Current Period. Our effective income tax rate was 0.3% in the Current Period and 0.0% in the Prior Period. The increase in the effective income tax rate from the Prior Period to the Current Period is primarily due to the accrual of current state income tax expenses in the Current Period. Further, our effective tax rate can fluctuate as a result of the impact of state income taxes and permanent differences. See Note 12 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for a discussion of income tax expense (benefit).
Net Income Attributable to Noncontrolling Interests. Chesapeake recorded net income attributable to noncontrolling interests of $3 million and $1 million in the Current Period and the Prior Period, respectively. In both periods, activity was attributable to the Chesapeake Granite Wash Trust.
Forward-Looking Statements
This report includes “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 (the “Exchange Act”). Forward-looking statements giveinclude our current expectations or forecasts of future events. They include expected oil, natural gasevents, including matters relating to the continuing effects of the impact of inflation and NGL productioncommodity price volatility resulting from Russia’s invasion of Ukraine, COVID-19 and future expenses, estimated operating costs, assumptions regarding future oil, natural gasrelated supply chain constraints, and NGL prices, planned drilling activity, estimatesthe impact of future drillingeach on our business, financial condition, results of operations and completioncash flows, the potential effects of the Plan on our operations, management, and employees, actions by, or disputes among or between, members of OPEC+ and other capital expenditures (including the use of joint venture drilling carries), potential future write-downs offoreign oil-exporting countries, market factors, market prices, our oil and natural gas assets, anticipated sales, and the adequacy of our provisions for legal contingencies, as well as statements concerning anticipated cash flow and liquidity, ability to fund planned capital expenditures andmeet debt service requirements, our ability to continue to pay cash dividends, the amount and comply with financial maintenance covenants, meet contractualtiming of any cash commitments to third parties, debt repurchases, operatingdividends, and capital efficiencies, business strategy, the effect of our remediation plan for a material weakness,ESG initiatives. Forward-looking and other statements in this Form 10-Q regarding our environmental, social and other sustainability plans and objectivesgoals are not an indication that these statements are necessarily material to investors or required to be disclosed in our filings with the SEC. In addition, historical, current, and forward-looking environmental, social and sustainability-related statements may be based on standards for future operations. Disclosures concerning the fair values of derivative contractsmeasuring progress that are still developing, internal controls and their estimated contributionprocesses that continue to our future results of operations are based upon market information as of a specific date. These market pricesevolve, and assumptions that are subject to significant volatility.change in the future. Forward-looking statements often address our expected future business, financial performance and financial condition, and often contain words such as "expect," “could,” “may,” "anticipate," "intend," "plan," “ability,” "believe," "seek," "see," "will," "would," “estimate,” “forecast,” "target," “guidance,” “outlook,” “opportunity” or “strategy.”
Although we believe the expectations and forecasts reflected in our forward-looking statements are reasonable, we can give nothey are inherently subject to numerous risks and uncertainties, most of which are difficult to predict and many of which are beyond our control. No assurance they will prove to have been correct. They can be affected by inaccurategiven that such forward-looking statements will be correct or achieved or that the assumptions are accurate or by known or unknown risks and uncertainties. Factorswill not change over time. Particular uncertainties that could cause our actual results to differbe materially different than those expressed in our forward-looking statements include:
•the impact of inflation and commodity price volatility resulting from expected results are describedRussia’s invasion of Ukraine, COVID-19 and related labor and supply chain constraints, along with the effects of the current global economic environment, including impacts from higher interest rates and recent bank closures and liquidity concerns at certain financial institutions, on our business, financial condition, employees, contractors, vendors and the global demand for natural gas and oil and U.S. and on world financial markets;
•our ability to comply with the covenants under Risk Factors in Item 1A ofthe credit agreement for our annual report on Form 10-K for the year ended December 31, 2016 (2016 Form 10-K)New Credit Facility and include:other indebtedness;
•risks related to acquisitions or dispositions, or potential acquisitions or dispositions;
•our ability to realize anticipated cash cost reductions;
•the volatility of oil, natural gas, oil and NGL prices;prices, which are affected by general economic and business conditions, as well as increased demand for (and availability of) alternative fuels and electric vehicles;
the limitations our level of indebtedness may have on our financial flexibility;•a deterioration in general economic, business or industry conditions;
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;
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, oil and NGL reserves and projecting future rates of production and the amount and timing of development expenditures;
•our ability to replace reserves and sustain production;
•drilling and operating risks and resulting liabilities;
•our ability to generate profits or achieve targeted results in drilling and well operations;
•the limitations our level of indebtedness may have on our financial flexibility;
•our ability to achieve and maintain ESG certifications, goals and commitments;
•our inability to access the capital markets on favorable terms;
•the availability of cash flows from operations and other funds to fund cash dividends and repurchases of equity securities, to finance reserve replacement costs and/or satisfy our debt obligations;
•write-downs of our natural gas and oil asset carrying values due to low commodity prices;
•charges incurred in response to market conditions;
•limited control over properties we do not operate;
•leasehold terms expiring before production can be established;
•commodity derivative activities resulting in lower prices realized on oil, natural gas, oil and NGL sales;
•the need to secure derivative liabilities and the inability of counterparties to satisfy their obligations;
•potential OTC derivatives regulations limiting our ability to hedge against commodity price fluctuations;
•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;
•legislative, regulatory and ESG initiatives, addressing environmental concerns, including initiatives addressing the impact of global climate change or further regulating hydraulic fracturing, methane emissions, flaring or water disposal;
•terrorist activities and/or cyber-attacks adversely impacting our operations;
potential challenges by SSE’s former creditors of our spin-off of in connection with SSE’s recently completed bankruptcy under Chapter 11 of the U.S. Bankruptcy Code;
•an interruption in operations at our headquarters due to a catastrophic event;
•federal and state tax proposals affecting our industry;
•competition in the continuationnatural gas and oil exploration and production industry;
•negative public perceptions of suspended dividend paymentsour industry;
•effects of purchase price adjustments and indemnity obligations;
•the ability to execute on our common stock;business strategy following emergence from bankruptcy; and
the effectiveness•other factors that are described under Risk Factors in Item 1A of our remediation plan for a material weakness;
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.2022 Form 10-K.We caution you not to place undue reliance on the forward-looking statements contained in this report, which speak only as of the filing date, and we undertake no obligation to update this information except as required by applicable law.information. We urge you to carefully review and consider the disclosures in this report and our other filings with the SEC that attempt to advise interested parties of the risks and factors that may affect our business.
Investors should note that we make available, free of charge on our website at chk.com, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. We also post announcements, updates, events, investor information and presentations on our website in addition to copies of all recent news releases. We may use the Investors section of our website to communicate with investors. It is possible that the financial and other information posted on the Investors section of our website could be deemed to be material information. Documents and information on our website are not incorporated by reference herein.
The SEC maintains a website at www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers, including Chesapeake, that file electronically with the SEC.
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ITEM 3. | Quantitative and Qualitative Disclosures About Market Risk |
Oil, Natural GasThe primary objective of the following information is to provide forward-looking quantitative and qualitative information about our exposure to market risk. The term market risk relates to our risk of loss arising from adverse changes in natural gas, oil and NGL Derivativesprices and interest rates. These disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. The forward-looking information provides indicators of how we view and manage our ongoing market risk exposures.
Commodity Price Risk
Our results of operations and cash flows are impacted by changes in market prices for oil, natural gas, oil and NGL.NGL, which have historically been volatile. To mitigate a portion of our exposure to adverse price changes, we have enteredenter into various derivative instruments. These instrumentsOur natural gas, oil and NGL derivative activities, when combined with our sales of natural gas, oil and NGL, allow us to predict with greater certainty the effective prices to be received for our share of production.revenue we will receive. We believe our derivative instruments continue to be highly effective in achieving our risk management objectives.
Our general strategy for protecting short-term cash flow and attempting to mitigate exposure to adverse oil, natural gas and NGL price changes is to hedge into strengthening oil and natural gas futures markets when prices reach levels that management believes are unsustainable for the long term, have material downside risk in the short term or provide reasonable rates of return on our invested capital. Information we consider in forming an opinion about future prices includes general economic conditions, industrial output levels and expectations, producer breakeven cost structures, liquefied natural gas trends, oil and natural gas storage inventory levels, industry decline rates for base production and weather trends.
We use derivative instruments to achieve our risk management objectives, including swaps, collars and options. All of these are described in more detail below. We typically use swaps and collars for a large portion of the oil and natural gas price risk we hedge. We have also sold calls, taking advantage of premiums associated with market price volatility.
We determine the volume potentially subject to derivative contracts by reviewing our overall estimated future production levels, which are derived from extensive examination of existing producing reserve estimates and estimates of likely production from new drilling. Production forecasts are updated at least monthly and adjusted if necessary to actual results and activity levels. We do not enter into derivative contracts for volumes in excess of our share of forecasted production, and if production estimates were lowered for future periods and derivative instruments are already executed for some volume above the new production forecasts, the positions would be reversed. The actual fixed price on our derivative instruments is derived from the reference NYMEX price, as reflected in current NYMEX trading. The pricing dates of our derivative contracts follow NYMEX futures. All of our commodity derivative instruments are net settled based on the difference between the fixed price as stated in the contract and the floating-price, resulting in a net amount due to or from the counterparty.
We review our derivative positions continuously and if future market conditions change and prices are at levels we believe could jeopardize the effectiveness of a position, we will mitigate this risk by either negotiating a cash settlement with our counterparty, restructuring the position or entering into a new trade that effectively reverses the current position. The factors we consider in closing or restructuring a position before the settlement date are identical to those we review when deciding to enter into the original derivative position. Gains or losses related to closed positions will be recognized in the month of related production based on the terms specified in the original contract.
We have determined the fair value of our derivative instruments utilizing established index prices, volatility curves and discount factors. These estimates are compared to counterparty valuations for reasonableness. Derivative transactions are also subject to the risk that counterparties will be unable to meet their obligations. This non-performance risk is considered in the valuation of our derivative instruments, but to date has not had a material impact on the values of our derivatives. Future risk related to counterparties not being able to meet their obligations has been partially mitigated under our commodity hedging arrangements that require counterparties to post collateral if their obligations to
Chesapeakeus are in excess of defined thresholds. The values we report in our financial statements are as of a point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors. See
Note 811 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for further discussion of the fair value measurements associated with our derivatives.Our natural gas, oil and NGL revenues during the first three months of 2023, excluding any effect of our derivative instruments, were $1,042 million, $373 million and $38 million, respectively. Based on production, natural gas, oil and NGL revenue for the first three months of 2023 would have increased or decreased by approximately $104 million, $37 million, and $4 million, respectively, for each 10% increase or decrease in prices. As of September 30, 2017,March 31, 2023, the fair values of our oil, natural gas and NGL derivative instruments consistedoil derivatives were net assets of the following types of instruments:
Swaps: Chesapeake receives a fixed price$508 million and pays a floating market price to the counterparty for the hedged commodity. In exchange for higher fixed prices on certain of our swap trades, we may sell call options and call swaptions.
Options: Chesapeake sells, and occasionally buys, call options$11 million, respectively. A 10% increase in exchange for a premium. At the time of settlement, if the market price exceeds the fixed price of the call option, Chesapeake pays the counterparty the excess on sold call options, and Chesapeake receives the excess on bought call options. If the market price settles below the fixed price of the call option, no payment is due from either party.
Call Swaptions: Chesapeake sells call swaptions to counterparties that allow the counterparty, on a specific date, to extend an existing fixed-price swap for a certain period of time
Collars: These instruments contain a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, Chesapeake receives the fixed price and pays the market price. If the market price is between the put and the call strike prices, no payments are due from either party. Three-way collars include the sale by Chesapeake of an additional put option in exchange for a more favorable strike price on the call option. This eliminates the counterparty’s downside exposure below the second put option strike price.
Basis Protection Swaps: These instruments are arrangements that guarantee a fixed price differential to NYMEX from a specified delivery point. Chesapeake receives the fixed price differential and pays the floating market price differential to the counterparty for the hedged commodity.
As of September 30, 2017, we had the following open oil,forward natural gas and NGL derivative instruments:
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| | | | | | | | | | | | | | | | | | | | | | | |
| | | | Weighted Average Price | | Fair Value |
| | Volume | | Fixed | | Call | | Put | | Differential | | Asset (Liability) |
| | (mmbbl) | | ($ per bbl) | | ($ in millions) |
Oil: | | | | | | | | | | | | |
Swaps: | | | | | | | | | | | | |
Short-term | | 15 |
| | $ | 50.95 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | (16 | ) |
Long-term | | 3 |
| | $ | 50.93 |
| | $ | — |
| | $ | — |
| | $ | — |
| | (1 | ) |
Three Way Collars: | | | | | | | | | | | | |
Short-term | | 1 |
| | $ | — |
| | $ | 55.00 |
| | $39.15 / $47.00 | | $ | — |
| | $ | (1 | ) |
Long-term | | 1 |
| | $ | — |
| | $ | 55.00 |
| | $39.15 / $47.00 | | $ | — |
| | (1 | ) |
Call Options (sold): | | | | | | | | | | | | |
Short-term | | 1 |
| | $ | — |
| | $ | 71.00 |
| | $ | — |
| | $ | — |
| | — |
|
Call Swaptions: | | | | | | | | | | | | |
Short-term | | 1 |
| | $ | 52.87 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | (4 | ) |
Long-term | | 1 |
| | $ | 52.87 |
| | $ | — |
| | $ | — |
| | $ | — |
| | (3 | ) |
Basis Protection Swaps: | | | | | | | | | | | | |
Short-term | | 3 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 2.94 |
| | (1 | ) |
Total Oil | | (27 | ) |
| | (tbtu) | | ($ per mmbtu) | |
|
Natural Gas: | | | | | | | | | | | | |
Swaps(a): | | | | | | | | | | | | |
Short-term | | 576 |
| | $ | 3.15 |
| | $ | — |
| | $ | — |
| | $ | — |
| | 42 |
|
Long-term | | 120 |
| | $ | 3.00 |
| | $ | — |
| | $ | — |
| | $ | — |
| | (4 | ) |
Collars: | | | | | | | | | | | | |
Short-term | | 59 |
| | $ | — |
| | $ | 3.42 |
| | $ | 3.10 |
| | $ | — |
| | 7 |
|
Long-term | | 12 |
| | $ | — |
| | $ | 3.25 |
| | $ | 3.00 |
| | $ | — |
| | 1 |
|
Call Options (sold): | | | | | | | | | | | | |
Short-term | | 61 |
| | $ | — |
| | $ | 6.89 |
| | $ | — |
| | $ | — |
| | (5 | ) |
Long-term | | 60 |
| | $ | — |
| | $ | 10.43 |
| | $ | — |
| | $ | — |
| | (2 | ) |
Basis Protection Swaps: | | | | | | | | | | | | |
Short-term | | 24 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | (0.70 | ) | | (1 | ) |
Long-term | | 2 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | (0.77 | ) | | — |
|
Total Natural Gas | | 38 |
|
| | (mmgal) | | ($ per mgal) | | |
NGL: | | | | | | | | | | | | |
Propane Swaps | | | | | | | | | | | | |
Short-term | | 15 |
| | $ | 0.76 |
| | $ | — |
| | $ | — |
| | $ | — |
| | (2 | ) |
Total NGL | | |
Total Estimated Fair Value | | $ | 9 |
|
| |
(a) | This amount includes a sold option to enhance the swap price at an average priceprices would decrease the valuation of $3.40 / mmbtu covering 44 tbtu, included in the sold call options. |
In addition to the open derivative positions disclosed above, as of September 30, 2017, we had $61 million of net derivative losses related to settled contracts for future production periods that will be recorded within oil, natural gas and NGL sales as realized gains (losses) on derivatives once they are transferred from either accumulated other comprehensive income or unrealized gains (losses) on derivatives in the month of related production, based on the terms specified in the original contract as noted below.
|
| | | | |
| | September 30, 2017 |
| | ($ in millions) |
Short-term | | $ | 2 |
|
Long-term | | (63 | ) |
Total | | $ | (61 | ) |
The table below reconciles the changes in fair value of our oil and natural gas derivatives duringby approximately $256 million. A 10% decrease in forward natural gas prices would increase the Current Period. Ofvaluation of natural gas derivatives by approximately $260 million. A 10% increase in forward oil prices would decrease the valuation of oil derivatives by approximately $8 million. A 10% decrease in forward oil prices would increase the valuation of oil derivatives by approximately $9 million fair value asset asmillion. See Note 11 of September 30, 2017, a $20 million asset relatesthe notes to contracts maturingour condensed consolidated financial statements included in the next 12 months and an $11 million liability relates to contracts maturing after 12 months. AllItem 1 of Part I of this report for further information on our open derivative instruments as of September 30, 2017 are expected to mature by December 31, 2020. |
| | | | |
| | September 30, 2017 |
| | ($ in millions) |
Fair value of contracts outstanding, as of January 1, 2017 | | $ | (504 | ) |
Change in fair value of contracts | | 477 |
|
Contracts realized or otherwise settled | | 36 |
|
Fair value of contracts outstanding, as of September 30, 2017 | | $ | 9 |
|
positions.Interest Rate DerivativesRisk
The table below presents principal cash flows and related weighted average interest rates by expected maturity dates, using the earliest demand repurchase date for contingent convertible senior notes. As of September 30, 2017, we had total debt of $9.775 billion, including $7.250 billion of fixed rate debt at interest rates averaging 6.87% and $2.525 billion of floating rate debt at anOur exposure to interest rate changes relates primarily to borrowings under our New Credit Facility for the first three months of 6.47%.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Years of Maturity | | |
| 2017 | | 2018 | | 2019 | | 2020 | | 2021 | | Thereafter | | Total |
| ($ in millions) |
Liabilities: | | | | | | | | | | | | | |
Debt – fixed rate(a) | $ | — |
| | $ | 52 |
| | $ | — |
| | $ | 852 |
| | $ | 820 |
| | $ | 5,526 |
| | $ | 7,250 |
|
Average interest rate | — | % | | 6.42 | % | | — | % | | 6.71 | % | | 5.88 | % | | 7.04 | % | | 6.87 | % |
Debt – variable rate | $ | — |
| | $ | — |
| | $ | 1,025 |
| | $ | — |
| | $ | 1,500 |
| | $ | — |
| | $ | 2,525 |
|
Average interest rate | — | % | | — | % | | 3.22 | % | | — | % | | 8.69 | % | | — | % | | 6.47 | % |
| |
(a) | This amount excludes the premium, discount and deferred financing costs included in debt of $122 million and interest rate derivatives of $2 million. |
Changes in interest rates affect the amount of interest we earn on our cash, cash equivalents and short-term investments2023 and the interest rate we payExit Credit Facility for the first three months of 2022. Interest is payable on borrowings under our revolvingeach respective credit facility term loan and ourbased on floating rate senior notes. All of our other indebtedness is fixed rate and, therefore, does not expose us to the risk of fluctuations in earnings or cash flow due to changes in market interest rates. However, changes in interest rates do affect the fair value of our fixed-rate debt.
From time to time, we enter into interest rate derivatives, including fixed-to-floating interest rate swaps (we receive a fixed interest rate and pay a floating market rate) to mitigate our exposure to changes in the fair value of our senior notes and floating-to-fixed interest rate swaps (we receive a floating market rate and pay a fixed interest rate) to manage our interest rate exposure related to our revolving credit facility borrowings. As of September 30, 2017, there were no interest rate derivatives outstanding.
As of September 30, 2017, we had $10 million of net gains related to settled derivative contracts that will be recorded within interest expense as realized gains or losses once they are transferred from our senior note liability or within interest expense as unrealized gains or losses over the remaining six year term of our related senior notes.
Realized and unrealized (gains) or losses from interest rate derivative transactions are reflected as adjustments to interest expense on the consolidated statements of operations.
Foreign Currency Derivatives
During the Current Period, both our 6.25% Euro-denominated Senior Notes due 2017 and cross currency swaps for the same principal amount matured. Upon maturity4 of the notes the counterparties paid us €246 million andto our condensed consolidated financial statements included in Item 1 of Part 1 of this report for additional information. As of March 31, 2023, we paid the counterparties $327 million. The terms of the cross currency swaps were based on the dollar/euro exchange rate on the issuance date of $1.3325 to €1.00. The swaps were designated as cash flow hedges and, because they were entirely effective in having eliminated any potential variability in our expected cash flows related to changes in foreign exchange rates, changes in their fair value did not impact earnings. The fair valueshave any outstanding borrowings under our New Credit Facility.
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ITEM 4. | Controls and Procedures |
Evaluation of Disclosure Controls and Procedures
We maintain disclosure controls and procedures designed to ensure that information required to be disclosed in reports we file or submit under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and that such information is accumulated and communicated to management, including our principal executive and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure.
As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of Chesapeake’sour disclosure controls and procedures pursuant to Exchange Act Rule 13a-15(b). Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded as of March 31, 2023 that our disclosure controls and procedures were not effective as of September 30, 2017, because of the material weakness in our internal control over financial reporting described in Management’s Report on Internal Control Over Financial Reporting appearing under Item 8 of Part II of our Annual Report on Form 10-K for the year ended December 31, 2016.
Remediation Plan for the Material Weakness
Our management is actively engaged in remediation efforts to address the material weakness identified. Specifically, our management is in the process of implementing controls related to reviewing the configuration of the basis price differential calculations, including a control activity to verify any subsequent changes are appropriately reviewed and that the interface control is designed to validate the data at an appropriately disaggregated level. Our management believes that these actions will remediate the material weakness in internal control over financial reporting.effective.
Changes in Internal Control Over Financial Reporting
There were no changes in our internal control over financial reporting during the quarter ended September 30, 2017, whichperiod covered by this quarterly report on Form 10-Q that materially affected, or wereare reasonably likely to materially affect, our internal control over financial reporting.
PART II. OTHER INFORMATION
Business Operations and Litigation and Regulatory Proceedings
We are involved in various pre-petition lawsuits and disputes incidental to our business operations, including commercial disputes, personal injury claims, royalty claims, property damage claims and contract actions. The Company ismajority of these prepetition legal proceedings were settled during the Chapter 11 Cases or will be resolved in connection with the claims reconciliation process before the Bankruptcy Court, together with actions seeking to collect pre-petition indebtedness or to exercise control over the property of the Company’s bankruptcy estates. Any allowed claim related to such litigation will be treated in accordance with the Plan. We were involved in a number of litigation and regulatory proceedings including those described below.as of the Petition Date. Many of these proceedings arewere in early stages, and many of them seek or may seeksought damages and penalties, the amount of which is currently indeterminate. See Note 45 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for information regarding our estimation and provision for potential losses related to litigation and regulatory proceedings. Commencement of the Chapter 11 Cases automatically stayed the proceedings and actions against us that are referred to above. The Plan in the Chapter 11 Cases, which became effective on February 9, 2021, provided for the treatment of claims against the Company’s bankruptcy estates, including pre-petition liabilities that had not been satisfied or addressed during the Chapter 11 Cases. RegulatoryEnvironmental Contingencies
The nature of the natural gas and Related Proceedings. The Company has received DOJ, U.S. Postal Serviceoil business carries with it certain environmental risks for us and state subpoenas seeking informationour subsidiaries. We have implemented various policies, programs, procedures, training and audits to reduce and mitigate such environmental risks. We conduct periodic reviews, on a company-wide basis, to assess changes in our environmental risk profile. Environmental reserves are established for environmental liabilities for which economic losses are probable and reasonably estimable. We manage our exposure to environmental liabilities in acquisitions by using an evaluation process that seeks to identify pre-existing contamination or compliance concerns and address the potential liability. Depending on the Company’s royalty payment practices. On September 19, 2017, the DOJ informed Chesapeake that it had concluded its investigation with no action taken on these matters and matters related to the purchase and leaseextent of oil and natural gas rights. Chesapeake has engaged in discussions with the U.S. Postal Service and state agency representatives and continues to respond to related subpoenas and demands.
On July 10, 2017, Chesapeake, its Benefits Committee, its Investment Committee and certain employees were named as defendants in a purported Employee Retirement Income Security Act of 1974 (ERISA) class action filed in the United States District Court for the Western District of Oklahoma (the “ERISA Lawsuit”). The ERISA Lawsuit alleges violations of Sections 404, 405, 409 and 502 of ERISA with respect to the Company’s common stock held in its Savings and Incentive Stock Bonus Plan (the “Plan”). The lawsuit was dismissed on August 8, 2017.
Business Operations. Chesapeake is involved in various other lawsuits and disputes incidental to its business operations, including commercial disputes, personal injury claims, royalty claims, property damage claims and contract actions.
Regarding royalty claims, Chesapeake and other natural gas producers have been named in various lawsuits alleging royalty underpayment. The suits against us allege,an identified environmental concern, we may, among other things, that we used below-market prices, made improper deductions, used improper measurement techniques and/exclude a property from the transaction, require the seller to remediate the property to our satisfaction in an acquisition or entered into arrangements with affiliates that resulted in underpayment of royalties in connection withagree to assume liability for the production and sale of natural gas and NGL. Plaintiffs have varying royalty provisions in their respective leases, oil and gas law varies from state to state, and royalty owners and producers differ in their interpretationremediation of the legal effect of lease provisions governing royalty calculations. The Company has resolved a number of these claims through negotiated settlements of past and future royalties and has prevailed in various other lawsuits. Weproperty.
Other Matters
Based on management’s current assessment, we are currently defending lawsuits seeking damages with respect to underpayment of royalties in various states, including, but not limited to, Texas, Pennsylvania, Ohio, Oklahoma, Kentucky, Louisiana and Arkansas. These lawsuits include cases filed by individual royalty owners and putative class actions, some of which seek to certify a statewide class.
Chesapeake is defending numerous lawsuits filed by individual royalty owners alleging royalty underpayment with respect to properties in Texas. These lawsuits, organized for pre-trial proceedings with respect to the Barnett Shale and Eagle Ford Shale, respectively, generally allege that Chesapeake underpaid royalties by making improper deductions, using incorrect production volumes and similar theories. Chesapeake expects that additional lawsuits will continue to be pursued and that new plaintiffs will file other lawsuits making similar allegations.
On December 9, 2015, the Commonwealth of Pennsylvania, by the Office of Attorney General, filed a lawsuit in the Bradford County Court of Common Pleas related to royalty underpayment and lease acquisition and accounting practices with respect to properties in Pennsylvania. The lawsuit, which primarily relates to the Marcellus Shale and Utica Shale, alleges that Chesapeake violated the Pennsylvania Unfair Trade Practices and Consumer Protection Law (UTPCPL) by making improper deductions and entering into arrangements with affiliates that resulted in underpayment of royalties. The lawsuit includes other UTPCPL claims and antitrust claims, including that a joint exploration agreement to which Chesapeake is a party established unlawful market allocation for the acquisition of leases. The lawsuit seeks statutory restitution, civil penalties and costs, as well as temporary injunction from exploration and drilling activities in Pennsylvania until restitution, penalties and costs have been paid and a permanent injunction from further violations of the UTPCPL.opinion that no pending or threatened lawsuit or dispute relating to our business operations is likely to have a material adverse effect on our future consolidated financial position, results of operations or cash flows. The final resolution of such matters could exceed amounts accrued, however, and actual results could differ materially from management’s estimates.
Putative statewide class actions in Pennsylvania and Ohio and purported class arbitrations in Pennsylvania have been filed on behalf of royalty owners asserting various claims for damages related to alleged underpayment of royalties as a result of the Company’s divestiture of substantially all of its midstream business and most of its gathering assets in 2012 and 2013. These cases include claims for violation of and conspiracy to violate the federal Racketeer Influenced and Corrupt Organizations Act and for an unlawful market allocation agreement for mineral rights. One of the cases includes claims of intentional interference with contractual relations and violations of antitrust laws related to purported markets for gas mineral rights, operating rights and gas gathering sources.
The Company is also defending lawsuits alleging various violations of the Sherman Antitrust Act and state antitrust laws. In 2016, putative class action lawsuits were filed in the U.S. District Court for the Western District of Oklahoma and in Oklahoma state courts, and an individual lawsuit was filed in the U.S. District Court of Kansas, in each case against the Company and other defendants. The lawsuits generally allege that, since 2007 and continuing through April 2013, the defendants conspired to rig bids and depress the market for the purchases of oil and natural gas leasehold interests and properties in the Anadarko Basin containing producing oil and natural gas wells. The lawsuits seek damages, attorney’s fees, costs and interest, as well as enjoinment from adopting practices or plans that would restrain competition in a similar manner as alleged in the lawsuits.
Environmental Proceedings
Our subsidiary Chesapeake Appalachia, LLC (CALLC) is engaged in discussions with the EPA, the U.S. Army Corps of Engineers and the Pennsylvania Department of Environmental Protection (PADEP) regarding potential violations of the permitting requirements of the federal Clean Water Act, the Pennsylvania Clean Streams Law and the Pennsylvania Dam Safety and Encroachments Act in connection with the placement of dredge and fill material during construction of certain sites in Pennsylvania. CALLC identified the potential violations in connection with an internal review of its facilities siting and construction processes and voluntarily reported them to the regulatory agencies. Resolution of the matter may result in monetary sanctions of more than $100,000.
We are also in discussions with PADEP regarding gas migration in the vicinity of certain of our wells in Bradford County, Pennsylvania. We believe we are close to identifying agreed-upon steps to resolve PADEP’s concerns regarding the issue. In addition to these steps, we anticipate making a donation of $300,000 to the PADEP’s well plugging fund.
On December 27, 2016, we received a Finding of Violation from the EPA alleging violations of the Clean Air Act at a number of locations in Ohio. We have exchanged information with the EPA and are engaged in discussions aimed at resolving the allegations. Resolution of the matter may result in monetary sanctions of more than $100,000.
We are named as a defendant in a number of putative class actions and one mass tort action in Oklahoma alleging that we and several other companies have engaged in activities that have caused earthquakes. These actions seek, among other things, compensation for injury to real property, reimbursement of insurance premiums, and punitive damages.