The volumes remaining to be delivered on behalf |
| | | | | | | | | | | | | | |
| | | | | Volume Remaining as of September 30, 2017 |
| VPP # | | Term Remaining | | Oil | | Natural Gas | | NGL | | Total |
| | | (in months) | | (mmbbl) | | (bcf) | | (mmbbl) | | (bcfe) |
| 9 | | 41 | | 0.4 |
| | 36.8 |
| | 1.0 |
| | 45.1 |
|
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)SUPPLEMENTARY INFORMATION
| | | | | |
10. | Variable Interest Entities |
We consolidate the activities of VIEs for which we are the primary beneficiary. To determine whether we own a variable interest in a VIE, we perform a qualitative analysis of the entity’s design, organizational structure, primary decision makers and relevant agreements.
Chesapeake Granite Wash Trust (the “Trust”) is considered a VIE due to the lack of voting or similar decision-making rights by its equity holders regarding activities that have a significant effect on the economic success of the Trust and because the royalty interest owners, other than Chesapeake, do not have the ability to exercise substantial liquidation rights. Our ownership in the Trust and our previous obligations under the development agreement constitute variable interests. On June 30, 2017, the Trust’s subordinated units, all of which were held by Chesapeake, converted to common units. We continue to consolidate the activities of the Trust as we are the primary beneficiary of the Trust because (i) we have the power to direct the activities that most significantly impact the economic performance of the Trust via our operation of the majority of the producing wells and the completed development wells, and (ii) we have the obligation to absorb losses that potentially could be significant to the Trust. As a result, we consolidate the Trust in our financial statements, and the common units of the Trust owned by third parties are reflected as a noncontrolling interest. As of September 30, 2017 and December 31, 2016, we had $253 million and $257 million, respectively, of noncontrolling interests on our condensed consolidated balance sheets attributable to the Trust. In the Current Quarter, the Prior Quarter, the Current Period and the Prior Period, we had $1 million, $1 million, $3 million and $1 million, respectively, of net income attributable to the Trust’s noncontrolling interests recorded in our condensed consolidated statements of operations.
The Trust is a consolidated entity whose legal existence is separate from Chesapeake and our other consolidated subsidiaries, and the Trust is not a guarantor of any of Chesapeake’s debt. The creditors or beneficial holders of the Trust have no recourse to the general credit of Chesapeake. In consolidation, as of September 30, 2017, $1 million of cash and cash equivalents, $488 million of proved oil and natural gas properties, $460 million of accumulated depreciation, depletion and amortization and $4 million of other current liabilities were attributable to the Trust. We have presented parenthetically on the face of the condensed consolidated balance sheets the assets of the Trust that can be used only to settle obligations of the Trust and the liabilities of the Trust for which creditors do not have recourse to the general credit of Chesapeake.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
Impairments of Oil and Natural Gas Properties
Our proved 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 an 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. Estimated future net revenues for the quarterly ceiling limit are calculated using the average of commodity prices on the first day of the month over the trailing 12-month period. In the Prior Quarter and the Prior Period, capitalized costs of oil and natural gas properties exceeded the ceiling, resulting in an impairment in the carrying value of our oil and natural gas properties of $497 million and $2.564 billion, respectively.
Impairments of Fixed Assets and Other
We review our long-lived assets, other than oil and natural gas properties, for recoverability whenever events or changes in circumstances indicate that carrying amounts may not be recoverable. We recognize an impairment if the carrying amount of a long-lived asset is not recoverable and exceeds its fair value. A summary of our impairments of fixed assets by asset class and other charges for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period is as follows:
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| | | 2017 | | 2016 | | 2017 | | 2016 |
| | | ($ in millions) |
| Barnett Shale exit costs | | $ | — |
| | $ | 616 |
| | $ | — |
| | $ | 616 |
|
| Gathering systems | | — |
| | 96 |
| | — |
| | 96 |
|
| Natural gas compressors | | — |
| | 32 |
| | — |
| | 52 |
|
| Buildings and land | | 1 |
| | 7 |
| | 3 |
| | 14 |
|
| Other | | 8 |
| | — |
| | 423 |
| | 17 |
|
| Total impairments of fixed assets and other | | $ | 9 |
| | $ | 751 |
| | $ | 426 |
| | $ | 795 |
|
Barnett Shale Exit Costs. In October 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. As a result of this transaction, we accrued $334 million of charges in the Prior Quarter related to the termination of a natural gas gathering agreement associated with the Barnett Shale assets. 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.
Gathering Systems, Natural Gas Compressors, Buildings and Land. 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.
Other. 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.
Nonrecurring Fair Value Measurements. Fair value measurements for certain of the impairments were based on recent sales information for comparable assets. As the fair value was estimated using the market approach based on recent prices from orderly sales transactions for comparable assets between market participants, these values were classified as Level 2 in the fair value hierarchy. Other inputs used were not observable in the market; these values were classified as Level 3 in the fair value hierarchy.
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
A valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized. To assess that likelihood, we use estimates and judgment regarding our future taxable income, and we consider the tax consequences in the jurisdiction where taxable income is generated, to determine whether a valuation allowance is required. The evidence can include our current financial position, our results of operations (both actual and forecasted), the expected reversal of our deferred tax liabilities, and various tax planning strategies as well as the current and forecasted business economics of our industry.
Based on our estimated operating results for the subsequent quarter, we project being in a net deferred tax asset position as of December 31, 2017. We believe it is more likely than not that these deferred tax assets will not be realized. Management assesses the available positive and negative evidence to estimate whether sufficient future taxable income will be generated to permit the use of deferred tax assets. A significant piece of objective negative evidence evaluated is the projected cumulative loss incurred over the three-year period ending December 31, 2017. The objective negative evidence limits our ability to consider other subjective positive evidence, such as our projections for future growth. The amount of the deferred tax asset considered realizable, however, could be adjusted if objective negative evidence in the form of cumulative losses is no longer present or if estimates of future taxable income are increased and additional weight is given to subjective evidence, such as future expected growth. A valuation allowance was recorded against our net deferred tax asset as of both December 31, 2016 and September 30, 2017.
| |
13. | Fair Value Measurements |
Recurring Fair Value Measurements
Other Current Assets. Assets related to Chesapeake’s deferred compensation plan are included in other current assets. The fair value of these assets is determined using quoted market prices as they consist of exchange-traded securities.
Other Current Liabilities. Liabilities related to Chesapeake’s deferred compensation plan are included in other current liabilities. The fair values of these liabilities are determined using quoted market prices as the plan consists of exchange-traded mutual funds.
Financial Assets (Liabilities). The following table provides fair value measurement information for the above-noted financial assets (liabilities) measured at fair value on a recurring basis as of September 30, 2017 and December 31, 2016:
|
| | | | | | | | | | | | | | | | |
| | | Quoted Prices in Active Markets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Total Fair Value |
| | | ($ in millions) |
| As of September 30, 2017 | | | | | | | | |
| Financial Assets (Liabilities): | | | | | | | | |
| Other current assets | | $ | 57 |
| | $ | — |
| | $ | — |
| | $ | 57 |
|
| Other current liabilities | | (58 | ) | | — |
| | — |
| | (58 | ) |
| Total | | $ | (1 | ) | | $ | — |
| | $ | — |
| | $ | (1 | ) |
| | | | | | | | | |
| As of December 31, 2016 | | | | | | | | |
| Financial Assets (Liabilities): | | | | | | | | |
| Other current assets | | $ | 49 |
| | $ | — |
| | $ | — |
| | $ | 49 |
|
| Other current liabilities | | (51 | ) | | — |
| | — |
| | (51 | ) |
| Total | | $ | (2 | ) | | $ | — |
| | $ | — |
| | $ | (2 | ) |
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
See Note 3 for information regarding fair value measurement of our debt instruments. See Note 8 for information regarding fair value measurement of our derivatives.
Nonrecurring Fair Value Measurements
See Note 11 regarding nonrecurring fair value measurements.
As of September 30, 2017, we have two reportable operating segments. Our exploration and production operating segment is responsible for finding and producing oil, natural gas and NGL, while our marketing, gathering and compression operating segment is responsible for marketing, gathering and compression of oil, natural gas and NGL.
Revenues from the sale of oil, natural gas and NGL related to Chesapeake’s ownership interests by our marketing, gathering and compression operating segment are reflected as revenues within our exploration and production operating segment. These amounts totaled $1.030 billion, $1.025 billion, $3.200 billion and $2.656 billion for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period, respectively.
The following table presents selected financial information for Chesapeake’s operating segments:
|
| | | | | | | | | | | | | | | | | | | | |
| | | Exploration and Production | | Marketing, Gathering and Compression | | Other | | Intercompany Eliminations | | Consolidated Total |
| | | ($ in millions) |
Three Months Ended September 30, 2017 | | | | | | | | | | |
| Revenues | | $ | 979 |
| | $ | 1,994 |
| | $ | — |
| | $ | (1,030 | ) | | $ | 1,943 |
|
| Intersegment revenues | | — |
| | (1,030 | ) | | — |
| | 1,030 |
| | — |
|
| Total Revenues | | $ | 979 |
| | $ | 964 |
| | $ | — |
| | $ | — |
| | $ | 1,943 |
|
Income (Loss) Before Income Taxes | | $ | (14 | ) | | $ | 7 |
| | $ | (10 | ) | | $ | — |
| | $ | (17 | ) |
| | | | | | | | | | | |
Three Months Ended September 30, 2016 | | | | | | | | | | |
| Revenues | | $ | 1,177 |
| | $ | 2,124 |
| | $ | — |
| | $ | (1,025 | ) | | $ | 2,276 |
|
| Intersegment revenues | | — |
| | (1,025 | ) | | — |
| | 1,025 |
| | — |
|
| Total Revenues | | $ | 1,177 |
| | $ | 1,099 |
| | $ | — |
| | $ | — |
| | $ | 2,276 |
|
Income (Loss) Before
Income Taxes (as previously reported) | | $ | (710 | ) | | $ | (211 | ) | | $ | (231 | ) | | $ | (2 | ) | | $ | (1,154 | ) |
Income (Loss) Before Income Taxes (as revised)(a) | | $ | (642 | ) | | $ | (339 | ) | | $ | (231 | ) | | $ | (2 | ) | | $ | (1,214 | ) |
| | | | | | | | | | | |
Nine Months Ended September 30, 2017 | | | | | | | | | | |
| Revenues | | $ | 3,727 |
| | $ | 6,450 |
| | $ | — |
| | $ | (3,200 | ) | | $ | 6,977 |
|
| Intersegment revenues | | — |
| | (3,200 | ) | | — |
| | 3,200 |
| | — |
|
| Total Revenues | | $ | 3,727 |
| | $ | 3,250 |
| | $ | — |
| | $ | — |
| | $ | 6,977 |
|
Income (Loss) Before Income Taxes | | $ | 1,094 |
| | $ | (440 | ) | | $ | (32 | ) | | $ | (1 | ) | | $ | 621 |
|
| | | | | | | | | | | |
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
|
| | | | | | | | | | | | | | | | | | | | |
| | | Exploration and Production | | Marketing, Gathering and Compression | | Other | | Intercompany Eliminations | | Consolidated Total |
| | | ($ in millions) |
Nine Months Ended September 30, 2016 | | | | | | | | | | |
| Revenues | | $ | 2,610 |
| | $ | 5,897 |
| | $ | — |
| | $ | (2,656 | ) | | $ | 5,851 |
|
| Intersegment revenues | | — |
| | (2,656 | ) | | — |
| | 2,656 |
| | — |
|
| Total Revenues | | $ | 2,610 |
| | $ | 3,241 |
| | $ | — |
| | $ | — |
| | $ | 5,851 |
|
Income (Loss) Before
Income Taxes (as previously reported) | | $ | (3,360 | ) | | $ | (215 | ) | | $ | (248 | ) | | $ | (2 | ) | | $ | (3,825 | ) |
Income (Loss) Before Income Taxes (as revised)(a) | | $ | (3,465 | ) | | $ | (343 | ) | | $ | (248 | ) | | $ | (2 | ) | | $ | (4,058 | ) |
| | | | | | | | | | | |
As of September 30, 2017 | | | | | | | | | | |
| Total Assets | | $ | 10,451 |
| | $ | 923 |
| | $ | 994 |
| | $ | (387 | ) | | $ | 11,981 |
|
As of December 31, 2016 | | | | | | | | | | |
| Total Assets | | $ | 11,249 |
| | $ | 1,118 |
| | $ | 1,059 |
| | $ | (398 | ) | | $ | 13,028 |
|
| |
(a) | We have revised the amounts presented in the Prior Quarter and the Prior Period. The impact of the errors was not material to any previously issued financial statements. |
CHESAPEAKE ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)
(Unaudited)
| |
15. | Recently Issued Accounting Standards |
In May 2014, the Financial Accounting Standards Board (FASB) issued updated revenue recognition guidance to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. GAAP and international financial reporting standards. The new standard requires the recognition of revenue to depict the transfer of promised goods to customers in an amount reflecting the consideration the Company expects to receive in the exchange. In March 2016, the FASB issued an update clarifying the implementation guidance on principal versus agent considerations. In April 2016, the FASB issued an update clarifying the identification of performance obligations and licensing implementations guidance. In May 2016, the FASB issued an update clarifying guidance in a few narrow areas and added some practical expedients to the guidance. In September 2017, the FASB issued an update clarifying the definition of a public business entity for the application of the new revenue recognition standards. The accounting standards update is effective for fiscal years, and interim periods within those years, beginning after December 15, 2017, with early application permitted after December 31, 2016. The standard is required to be adopted using either the full retrospective approach or the modified retrospective approach. While early adoption is permitted, we plan to adopt this new standard in the first quarter of 2018 using the modified retrospective approach. Through September 30, 2017, we have made progress on contract reviews, drafting accounting policies and evaluating the additional information required to be accumulated and analyzed to complete new disclosure requirements. We expect that enhanced disclosures will be required under the new standard. Further analysis is planned in the fourth quarter of 2017 to complete our evaluation of the impact of the new standard.
In February 2016, the FASB issued updated lease accounting guidance requiring companies to recognize the assets and liabilities for the rights and obligations created by long-term leases of assets on the balance sheet. The accounting standards update is effective for fiscal years, and interim periods within those years, beginning after December 15, 2018. In September 2017, the FASB issued an update clarifying the definition of a public business entity for the application of the new leasing standards. The standard will not apply to our leases of mineral rights. We are continuing to further evaluate the impact of this guidance on our consolidated financial statements and related disclosures.
In August 2017, the FASB issued derivatives and hedging guidance which makes significant changes to the current hedge accounting rules. The new guidance impacts the designation of hedging relationships, measurement of hedging relationships, presentation of the effects of hedging relationships, assessment of hedge effectiveness and disclosures. The accounting standards update is effective for annual interim periods beginning after December 15, 2018, including interim periods within those annual periods. We are evaluating the impact of this guidance on our consolidated financial statements.
CHESAPEAKE 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 $3.8 billion.
| |
ITEM 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
Financial Data
The following table sets forth certain information regardingdiscussion should be read together with the condensed consolidated financial statements included in Item 1 of Part I of this report and the consolidated financial statements included in Item 8 of our 2020 Form 10-K. We are an independent exploration and production volumes,company engaged in the acquisition, exploration and development of properties to produce oil, natural gas and NGL sales, average sales prices received, and other operating income and expenses for the periods indicated:
|
| | | | | | | | | | | | | | | | |
| | | Three Months Ended
September 30, | | Nine Months Ended
September 30, |
| | | 2017 | | 2016 | | 2017 | | 2016 |
| Net Production: | | | | | | | | |
| Oil (mmbbl) | | 8 |
| | 8 |
| | 23 |
| | 25 |
|
| Natural gas (bcf) | | 219 |
| | 268 |
| | 639 |
| | 814 |
|
| NGL (mmbbl) | | 5 |
| | 6 |
| | 15 |
| | 19 |
|
Oil equivalent (mmboe)(a) | | 50 |
| | 59 |
| | 145 |
| | 180 |
|
| Average daily production (mboe) | | 542 |
| | 638 |
| | 532 |
| | 656 |
|
| | | | | | | | | |
| Oil, Natural Gas and NGL Sales ($ 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. |
| |
(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. |
| |
(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. |
Overview
from underground reservoirs. We own interests in approximately 17,100 oil and natural gas wells and produced an average of approximately 542 mboe per day in the Current Quarter, net to our interest. We have a large and geographically diverse resource baseportfolio of onshore U.S. unconventional natural gas and liquids assets. We have leading positionsassets, including interests in approximately 7,500 gross oil and natural gas wells at September 30, 2021. Our natural gas resource plays are the Marcellus Shale in the northern Appalachian Basin in Pennsylvania (“Appalachia”) and the Haynesville/Bossier Shales in northwestern Louisiana (“Gulf Coast”). Our liquids-rich resource plays ofare the Eagle Ford Shale in South Texas the Anadarko Basin in northwestern Oklahoma(“South Texas” and “Brazos Valley”) and the stacked pay in the Powder River Basin in Wyoming. 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 oil and natural gas marketing and natural gas compression businesses.Wyoming (“Powder River Basin”).
Our Strategy
Chesapeake’s strategy is to create shareholder value through the development of our significant positions in premier U.S. onshore resource plays. In addition, we continue to focus our financial strategy on reducing debt and improving margins 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 ourby generating sustainable free cash flow generating ability regardless of the commodity price environment. Our forecasted capital expenditures are higher in 2017 compared to 2016 as we focus on capturing high rate-of-return opportunities infrom our oil and natural gas portfolio. These opportunities are primarily the result of improved capitaldevelopment and production activities. We continue to focus on improving margins through operating efficiencies including improved welland financial discipline and improving our Environmental, Social, and Governance (ESG) performance. We expectTo accomplish these goals, we intend to allocate our anticipated production increases in the 2017 fourth quarter, combined with our cost leadershiphuman resources and discipline, will position us with the ability to balance capital expenditures to projects we believe offer the highest cash return on capital invested, to deploy leading drilling and operating cash flow in 2018.
Our substantial inventorycompletion technology throughout our portfolio, and to take advantage of hydrocarbon resources, includingacquisition and divestiture opportunities to strengthen 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.portfolio. 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 programoil and cost structure and our continued focus on safety and environmental stewardship will providenatural gas producing activities. We continue to seek opportunities to create value for usreduce cash costs (production, gathering, processing and our stakeholders.
Operating Results
Our Current Quarter production of 50 mmboe consisted of 8 mmbblstransportation and general and administrative) per barrel of oil (16% on an oil equivalent basis), 219 bcfproduction through operational efficiencies by, among other things, 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 naturalour operations and work diligently to improve our ESG performance across all facets of our Company. Our path to leading a responsible energy future begins with our initiative to achieve net-zero direct greenhouse gas (73% on an oil equivalent basis),emissions by 2035, which we announced in February 2021. To meet this challenge, we have set meaningful initial goals including:
•Eliminate routine flaring from all new wells completed from 2021 forward, and 5 mmbblsenterprise-wide by 2025;
•Reduce our methane intensity to 0.09% by 2025; and
•Reduce our GHG intensity to 5.5 by 2025.
In July 2021, we announced our plan to receive independent certification 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 dailyour natural gas production decreased by 18%, or approximately 532 mmcf per day;under the MiQ methane standard and average daily NGL production decreased by 11%, or approximately 7 mbbls per day. Our oil,EO100 Standard for Responsible Energy Development. We anticipate that certified natural gas will be available in our Gulf Coast basin by the end of 2021 and NGL production decreased primarilyin our Appalachia basin by the end of the second quarter of 2022. The MiQ certification will provide a verified approach to tracking our commitment to reduce our methane intensity to 0.09% by 2025, as well as support our overall objective of achieving net-zero direct greenhouse gas emissions by 2035.
Our results of operations as reported in our condensed consolidated financial statements for the 2021 Successor Quarter, 2021 Successor Period, 2021 Predecessor Period, 2020 Predecessor Quarter and 2020 Predecessor Period are in accordance with GAAP. Although GAAP requires that we report on our results for the periods January 1, 2021 through February 9, 2021 and February 10, 2021 through September 30, 2021 separately, management views our operating results for the nine months ended September 30, 2021 by combining the results of the 2021 Predecessor Period and the 2021 Successor Period because management believes such presentation provides the most meaningful comparison of our results to prior periods. We are not able to compare the 40 days from January 1, 2021 through February 9, 2021 operating results to any of the previous periods reported in the condensed consolidated financial statements and do not believe reviewing this period in isolation would be useful in identifying any trends in, or reaching any conclusions regarding, our overall operating performance. We believe the key performance indicators such as operating revenues and expenses for the 2021 Successor Period combined with the 2021 Predecessor Period provide more meaningful comparisons to other periods and are useful in understanding operational trends. Additionally, there were no changes in policies between the periods, and any
material impacts as a result of fresh start accounting were included within the salediscussion of certainthese changes. These combined results do not comply with GAAP and have not been prepared as pro forma results under applicable regulations, but are presented because we believe they provide the most meaningful comparison of our Mid-Continentresults to prior periods.
Emergence from Bankruptcy
On the Petition Date the Debtors filed the Chapter 11 Cases under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. On June 29, 2020, the Bankruptcy Court entered an order authorizing the joint administration of the Chapter 11 Cases under the caption In re Chesapeake Energy Corporation, Case No. 20-33233. Subsidiaries with noncontrolling interests, consolidated variable interest entities and Barnett Shale assetscertain de minimis subsidiaries (collectively, the “Non-Filing Entities”) were not part of the Bankruptcy Filing. The Non-Filing Entities have continued to operate in 2016the ordinary course of business.
The Bankruptcy Court confirmed the Plan and the sale of certainDebtors entered the Confirmation Order on January 16, 2021. The Debtors emerged from bankruptcy on the Effective Date. In connection with our exit from bankruptcy, we filed a registration statement with the SEC to facilitate future sales of our Haynesville Shale assets in 2017. Adjusted for asset sales, our total daily production was approximately unchanged 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, offsetequity by the production decreases described above. See Results 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 holders of our Mid-ContinentNew Common Stock and allwarrants. Sales 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 total of approximately $643 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, 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 issuancesubstantial number of the New
2025 NotesCommon Stock in the public markets, or the perception that these sales might occur, could reduce the value of our equity and
New 2027 Notes, excluding the accrued interest received, were approximately $842 million.impair our ability to raise capital through a future sale of, or pay for acquisitions using, our equity. See
Note 162 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for further discussion.a complete discussion of the Chapter 11 Cases.InChief Executive Officer
On April 27, 2021, we announced the Current Period, we issued $750 million aggregate principal amountdeparture of unsecured 8.00% Senior Notes due 2027Doug Lawler from his positions as Chief Executive Officer and Director of Chesapeake, effective April 30, 2021. Michael Wichterich, the Chairman of our Board of Directors, served as Interim Chief Executive Officer while the Board of Directors conducted a search for a new Chief Executive Officer.
Mr. Wichterich intends to continue in a private placement for net proceedshis role as Chair of $742 million.
Debt Retirementsthe Board of Directors following the appointment of Chesapeake's new Chief Executive Officer. During the period that Mr. Wichterich was both the Chair of the Board of Directors and Interim Chief Executive Officer, Matt Gallagher, the Chair of the Nominating and Governance Committee of the Board of Directors, served as Lead Independent Director.
On October 13, 2017,11, 2021, we used a portionannounced that the Board of Directors appointed Domenic “Nick” Dell’Osso as President and Chief Executive Officer and as member of the net proceeds fromBoard, effective October 11, 2021. Additionally, Mr. Dell’Osso will remain in his role as Chief Financial Officer until his replacement has been announced. On October 11, 2021, the offering discussed aboveBoard of Directors of the Company appointed Michael Wichterich, who resigned as Interim Chief Executive Officer upon the appointment of Mr. Dell’Osso, as Executive Chairman of the Company.
Vine Acquisition
On November 1, 2021, we completed our acquisition of Vine pursuant to finance $550 million in tender offers for certaina definitive agreement with Vine dated August 10, 2021. The transaction strengthens Chesapeake’s competitive position, meaningfully increasing our free cash flow outlook and deepening our inventory of premium natural gas locations, while preserving the strength of our senior notes. We repurchased approximately $320 million principal amountbalance sheet.
COVID-19 Pandemic and Impact on Global Demand for Oil and Natural Gas
The global spread of our 8.00% Senior Secured Second Lien Notes due 2022 for $350 million plus accruedCOVID-19 created significant volatility, uncertainty, and unpaid interest, and approximately $193 million principal amount of various series of our senior notes dueeconomic disruption during 2020 and into 2021 for $200 million plus accrued. The pandemic has reached more than 200 countries and unpaid interest. See Note 16territories and has resulted in widespread adverse impacts on the global economy and on our customers and other parties with whom we have business relations. To date, we have experienced limited operational impacts as a result of COVID-19 or related governmental restrictions. While we cannot predict 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 fromfull impact that COVID-19 or 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 notescurrent significant disruption and contingent convertible notes through purchasesvolatility in the open market, tender offers or repayment upon maturity for $1.751 billion. Retirements included (i)oil and natural gas markets will have on our business, cash flows, liquidity, financial condition and results of operations, we believe demand is recovering and prices will continue to be positively impacted. For additional discussion regarding risks associated with the maturityCOVID-19 pandemic, see Part II, Item 7. Management’s
Discussion and corresponding cross currency swap, (ii) our tender offer for our 2.5% Contingent Convertible Senior Notes due 2037 at the optionAnalysis of the holdersFinancial Condition and Results of the notes pursuant to the terms of the notes, (iii) our tender offer for a portion of our senior secured second lien notes, (iv) the repurchase of our 6.5% Senior Notes due 2017, and (v) the repurchases of our remaining 2.75% Contingent Convertible Senior Notes due 2035 and 2.5% Contingent Convertible Senior Notes due 2037.
Preferred Stock Exchanges
In the Current Period, we completed private exchanges of an aggregate of approximately 10.0 million shares of our common stock for (i) 72,600 shares of 5.75% Cumulative Convertible Preferred Stock, (ii) 12,500 shares of 5.75% Cumulative Convertible Preferred Stock (Series A) 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.
Divestitures
In the Current Period, we sold portions of our acreage and producing propertiesOperations in our Haynesville Shale operating area in northern Louisiana for approximately $915 million, subject to certain customary closing adjustments. Included in the sales were approximately 119,500 net acres2020 Form 10-K and interests in 576 wells that were producing approximately 80 mmcf of gas per day at the time of closing.
Also in the Current Period, we have signed or closed approximately $360 million of additional asset divestitures, primarilyItem 1A “Risk Factors” in our Mid-Continent area.2020 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. | | |
| Liquidity and Capital Resources |
Liquidity and Capital Resources
Liquidity Overview
For the 2021 Successor Period, our primary sources of capital resources and liquidity have consisted of internally generated cash flows from operations, and our primary uses of cash have been for the development of our oil and gas properties and return of value to shareholders through dividends. Historically, our primary sources of capital resources and liquidity have consisted of internally generated cash flows from operations, borrowings under certain credit agreements and dispositions of non-core assets. Our ability to grow, makeissue additional indebtedness, dispose of assets or access the capital expendituresmarkets was substantially limited during the Chapter 11 Cases and servicerequired court approval in most instances. Accordingly, our debt depends primarily upon the prices we receive for the oil, natural gas and NGL we sell. Substantial expenditures are required to replace reserves, sustain production and fund our business plans. Historically, oil and natural gas prices have been very volatile, and may be subject to wide fluctuationsliquidity in the future. The substantial declinePredecessor Periods depended mainly on cash generated from operations and available funds under certain credit agreements including the DIP Facility in oil, natural gasthe 2021 Predecessor Period and NGL pricesrevolving credit facility in the 2020 Predecessor Period.
We believe we have emerged from 2014 levels has negatively affected the amount ofChapter 11 Cases as a fundamentally stronger company, built to generate sustainable free cash we generateflow with a strengthened balance sheet, geographically diverse asset base 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 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 ascontinuously improving ESG performance. As a result of regulatory pressuresthe Chapter 11 Cases, we reduced our total indebtedness by $9.4 billion by issuing equity in a reorganized entity to the lending market.holders of our FLLO Term Loan, Second Lien Notes, unsecured notes and allowed general unsecured claimants.
We believe our cash flow from operations, cash on hand and borrowing capacity under the Exit Credit Facility, as discussed below, will provide sufficient liquidity during the next 12 months and the foreseeable future. As of September 30, 2017,2021, we had a$2.577 billion of liquidity available, including $849 million of cash balanceon hand and $1.728 billion 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.aggregate unused borrowing capacity available under the Exit Credit Facility. As of September 30, 2017,2021, we had $3.043 billion of borrowing capacity availableno outstanding borrowings under our revolving credit facility, with outstandingExit Credit Facility – Tranche A Loans and $221 million in 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.Exit Credit Facility – Tranche B Loans. See Note 35 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 principalcarrying and carrying amountsfair value of our senior notes. ThroughDividend
With our strong liquidity position, we initiated a new dividend strategy. We expect the annual dividend on our common shares will be paid quarterly. We made the first dividend payment of $0.34375 per share on June 10, 2021 to stockholders of record at the close of business on May 24, 2021, and we made the second dividend payment of $0.34375 per share on September 9, 2021 to stockholders of record at the close of business on August 24, 2021. On November 1, 2017,2, 2021, Chesapeake's Board of Directors increased the quarterly dividend on its common shares to $0.4375 per share, or 27% higher compared to the previous amount. The third dividend payment will be payable on December 9, 2021 to stockholders of record at the close of business on November 24, 2021. On August 10, 2021, we have takenannounced a variable return program that will result in the following measurespayment of an additional dividend, payable beginning in March 2022, equal to improve our near-term liquidity:the sum of free cash flow from the prior quarter less the base dividend, multiplied by 50%.
issued $300 million aggregate principal amountDerivative and Hedging Activities
Our results of 8.00% Senior Notes due 2025operations and $1.3 billion aggregate principal amount of 8.00% Senior Notes due 2027cash flows are impacted by changes in market prices for oil and used the proceedsnatural gas. We enter into various derivative instruments to repurchasemitigate a portion of our senior secured second lien notes, a portion of our senior notes due in 2020 and 2021 and a portion of our term loan due 2021;
reaffirmed the borrowing base 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,exposure 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 controlprice declines, but these transactions may also limit our cash flows in periods of rising oil and flexibility over the timingnatural gas prices. Our oil, natural gas and execution ofNGL derivative activities, when combined with 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 requiredNGL, allow us to
post collateral asbetter 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 assurance of our performance under certain contractual arrangements, such as gathering, processing, transportationposition.Contractual Obligations and hedging agreements. Off-Balance Sheet Arrangements
As of October 31, 2017, we have received requestsSeptember 30, 2021, our material contractual obligations included repayment of senior notes, outstanding borrowings 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 ininterest payment obligations under the form of additionalExit Credit Facility, asset retirement obligations, lease obligations, undrawn letters of credit and various other commitments we enter into in the ordinary course of business that could result in future 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, as 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.obligations. In addition, we have downside price protection, through open swaps on 19 mmbblscontractual commitments with midstream
companies and pipeline carriers for future gathering, processing and transportation of oil, natural gas and NGL to move certain of our 2018 oil production to market. The estimated gross undiscounted future commitments under these agreements were approximately $3.4 billion as of September 30, 2021. As discussed above, we estimate the sources of our capital will continue to be adequate to fund our near and long-term contractual obligations.
Post-Emergence Debt
On the Effective Date, pursuant to the terms of the Plan, the Company, as borrower, entered into a reserve-based credit agreement (the “Credit Agreement”) providing for the Exit Credit Facility which features an initial borrowing base of $2.5 billion. The borrowing base will be redetermined semiannually on or around May 1 and November 1 of each year. Our borrowing base was reaffirmed in October 2021, and the next scheduled redetermination will be on or about May 1, 2022. The aggregate initial elected commitments of the lenders under the Exit Credit Facility will be $1.75 billion of revolving Tranche A Loans and $221 million of fully funded Tranche B Loans.
The Exit Credit Facility provides for a $200 million sublimit of the aggregate commitments that are available for the issuance of letters of credit. The Exit Credit Facility bears interest at the ABR (alternate base rate) or LIBOR, at our election, plus an average priceapplicable margin (ranging from 2.25–3.25% per annum for ABR loans and 3.25–4.25% per annum for LIBOR loans, subject to a 1.00% LIBOR floor), depending on the percentage of $51.74 per bblthe borrowing base then being utilized. The Tranche A Loans mature 3 years after the Effective Date and the Tranche B Loans mature 4 years after the Effective Date. The Tranche B Loans can be repaid if no Tranche A Loans are outstanding.
On February 2, 2021, the Company issued $500 million aggregate principal amount of its 2026 Notes and $500 million aggregate principal amount of its 2029 Notes. The offering of the Notes was part of a series of exit financing transactions undertaken in connection with the Debtors’ Chapter 11 Cases and meant to provide the exit financing originally intended to be provided by the Exit Term Loan Facility pursuant to the Commitment Letter.
Based upon the business plan approved by the Court and our hedging activities we expect to generate adequate cash flows from operating activities to fully fund all investing activities without incremental borrowings under three-way collar arrangementsour Exit Credit Facility.
Assumption and Repayment of Vine Debt
In conjunction with the Vine Acquisition, Vine’s Second Lien Term Loan was repaid and terminated for $163 million inclusive of a $13 million make whole premium with cash on 2 mmbblshand due to the agreement containing a change in control provision making the term loan callable upon closing. Vine’s reserve based loan facility, which had no borrowings as of November 1, 2021, was terminated at the time of the acquisition. Additionally, Vine’s 6.75% Senior Notes with a principal amount of $950 million were assumed by the Company.
Capital Expenditures
For the year ending December 31, 2021, we currently expect to bring or have online approximately 125 to 140 gross wells by investing approximately $740 – $810 million in capital expenditures while operating approximately eight rigs inclusive of the Vine Acquisition. We expect that approximately 80% of our 2021 capital expenditures will be directed toward our natural gas assets. For the year ending December 31, 2022, we currently expect to invest approximately $1.3 – $1.6 billion in capital expenditures while operating approximately 10 to 12 rigs. We currently plan to fund our capital program through cash on hand and expected cash flow from our operations. We may alter or change our plans with respect to our capital program and expected capital expenditures 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 existdevelopments in our business, our financial position, our industry someor any of the markets in which we may not be able to anticipate at this time or control.operate.
Sources of Funds
The following table presents the sources of our cash and cash equivalents for the Current PeriodSuccessor and the Prior Period. See Note 9 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for further discussion of divestitures of oil and natural gas assets.Predecessor periods.
| | | | | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | Period from February 10, 2021 through September 30, 2021 | | | Period from January 1, 2021 through February 9, 2021 | | Nine Months Ended
September 30, 2020 |
| Cash provided by (used in) operating activities | | $ | 1,246 | | | | $ | (21) | | | $ | 1,155 | |
| Proceeds from issuance of senior notes | | — | | | | 1,000 | | | — | |
| Proceeds from issuance of common stock | | — | | | | 600 | | | — | |
| Proceeds from warrant exercise | | 2 | | | | — | | | — | |
| Proceeds from divestitures of property and equipment | | 9 | | | | — | | | 15 | |
| Proceeds from revolving pre-petition credit facility borrowings, net | | — | | | | — | | | 339 | |
| Total sources of cash and cash equivalents | | $ | 1,257 | | | | $ | 1,579 | | | $ | 1,509 | |
|
| | | | | | | | |
| | | 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 |
|
Cash provided by operating activities was $273$1.246 billion in the 2021 Successor Period, cash used in operating activities was $21 million in the Current2021 Predecessor Period, compared to $50 millionand cash provided by operating activities was $1.155 billion in the Prior2020 Predecessor Period. The increase in the 2021 Successor Period is primarily the result ofdue to higher realized prices for the oil, natural gas and NGL we sold partially offset by lower volumes of oil natural gas and NGL sold,sold. The cash used in the 2021 Predecessor Period was primarily due to the payment of professional fees related to the litigation on our 6.775% Senior Notes due 2019 and payments for terminations of transportation contracts. Changes in cash flowChapter 11 Cases. 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 useProceeds from Issuance of Common Stock and Senior Notes
In the 2021 Predecessor Period, we issued $500 million aggregate principal amount of 5.5% 2026 Notes and $500 million aggregate principal amount of 5.875% 2029 Notes for total proceeds of $1.0 billion. Additionally, upon emergence from Chapter 11, we issued 62,927,320 shares of New Common Stock in exchange for $600 million of cash flow from operations, cash on hand and our revolving credit facility to fund our capital expenditures for the remainder 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, we borrowed $4.775 billion and repaid $4.130 billionas agreed upon in the Current Period, and we borrowed $5.097 billion and repaid $4.857 billion in the Prior Period.Plan.
UsesContractual Obligations and Off-Balance Sheet Arrangements
As of September 30, 2021, our material contractual obligations included repayment of senior notes, outstanding borrowings and interest payment obligations under the Exit Credit Facility, asset retirement obligations, lease obligations, 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 oil, natural gas and NGL to move certain of our production to market. The estimated gross undiscounted future commitments under these agreements were approximately $3.4 billion as of September 30, 2021. As discussed above, we estimate the sources of our capital will continue to be adequate to fund our near and long-term contractual obligations.
Post-Emergence Debt
On the Effective Date, pursuant to the terms of the Plan, the Company, as borrower, entered into a reserve-based credit agreement (the “Credit Agreement”) providing for the Exit Credit Facility which features an initial borrowing base of $2.5 billion. The borrowing base will be redetermined semiannually on or around May 1 and November 1 of each year. Our borrowing base was reaffirmed in October 2021, and the next scheduled redetermination will be on or about May 1, 2022. The aggregate initial elected commitments of the lenders under the Exit Credit Facility will be $1.75 billion of revolving Tranche A Loans and $221 million of fully funded Tranche B Loans.
The Exit Credit Facility provides for a $200 million sublimit of the aggregate commitments that are available for the issuance of letters of credit. The Exit Credit Facility bears interest at the ABR (alternate base rate) or LIBOR, at our election, plus an applicable margin (ranging from 2.25–3.25% per annum for ABR loans and 3.25–4.25% per annum for LIBOR loans, subject to a 1.00% LIBOR floor), depending on the percentage of the borrowing base then being utilized. The Tranche A Loans mature 3 years after the Effective Date and the Tranche B Loans mature 4 years after the Effective Date. The Tranche B Loans can be repaid if no Tranche A Loans are outstanding.
On February 2, 2021, the Company issued $500 million aggregate principal amount of its 2026 Notes and $500 million aggregate principal amount of its 2029 Notes. The offering of the Notes was part of a series of exit financing transactions undertaken in connection with the Debtors’ Chapter 11 Cases and meant to provide the exit financing originally intended to be provided by the Exit Term Loan Facility pursuant to the Commitment Letter.
Based upon the business plan approved by the Court and our hedging activities we expect to generate adequate cash flows from operating activities to fully fund all investing activities without incremental borrowings under our Exit Credit Facility.
Assumption and Repayment of Vine Debt
In conjunction with the Vine Acquisition, Vine’s Second Lien Term Loan was repaid and terminated for $163 million inclusive of a $13 million make whole premium with cash on hand due to the agreement containing a change in control provision making the term loan callable upon closing. Vine’s reserve based loan facility, which had no borrowings as of November 1, 2021, was terminated at the time of the acquisition. Additionally, Vine’s 6.75% Senior Notes with a principal amount of $950 million were assumed by the Company.
Capital Expenditures
For the year ending December 31, 2021, we currently expect to bring or have online approximately 125 to 140 gross wells by investing approximately $740 – $810 million in capital expenditures while operating approximately eight rigs inclusive of the Vine Acquisition. We expect that approximately 80% of our 2021 capital expenditures will be directed toward our natural gas assets. For the year ending December 31, 2022, we currently expect to invest approximately $1.3 – $1.6 billion in capital expenditures while operating approximately 10 to 12 rigs. We currently plan to fund our capital program through cash on hand and expected cash flow from our operations. 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.
Sources of Funds
The following table presents the usessources of our cash and cash equivalents for the CurrentSuccessor and Predecessor periods.
| | | | | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | Period from February 10, 2021 through September 30, 2021 | | | Period from January 1, 2021 through February 9, 2021 | | Nine Months Ended
September 30, 2020 |
| Cash provided by (used in) operating activities | | $ | 1,246 | | | | $ | (21) | | | $ | 1,155 | |
| Proceeds from issuance of senior notes | | — | | | | 1,000 | | | — | |
| Proceeds from issuance of common stock | | — | | | | 600 | | | — | |
| Proceeds from warrant exercise | | 2 | | | | — | | | — | |
| Proceeds from divestitures of property and equipment | | 9 | | | | — | | | 15 | |
| Proceeds from revolving pre-petition credit facility borrowings, net | | — | | | | — | | | 339 | |
| Total sources of cash and cash equivalents | | $ | 1,257 | | | | $ | 1,579 | | | $ | 1,509 | |
Cash Flows from Operating Activities
Cash provided by operating activities was $1.246 billion in the 2021 Successor Period, cash used in operating activities was $21 million in the 2021 Predecessor Period, and the Prior Period:
|
| | | | | | | | |
| | | Nine Months Ended
September 30, |
| | | 2017 | | 2016 |
| | | ($ 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 increasedcash provided by operating activities was $1.155 billion in the Current Period compared to the Prior Period primarily as a result of increased activity as well as higher service and supply costs. During the Current Period, our average operated rig count was 18 rigs compared to an average operated rig count of ten rigs2020 Predecessor Period. The increase in the Prior2021 Successor Period and we completed 326 operated wells in the Current Period comparedis primarily due 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 3 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for further discussion of the term loan facility.
Revolving Credit Facility
We have a senior secured revolving credit facility currently subject to a $3.8 billion borrowing base that matures in December 2019. As of September 30, 2017, we had outstanding borrowings of $645 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 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 $3.8 billion. Our next borrowing base redetermination is scheduledhigher prices for the second quarter of 2018. See Note 3 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for further discussion of the terms of the revolving credit facility, as amended. As of September 30, 2017, our first lien secured leverage ratio was approximately 0.72 to 1.00 and our interest coverage ratio was approximately 1.50 to 1.00, and we were in compliance with all applicable financial covenants under the credit agreement.
Hedging Arrangements
Certain of our hedging arrangements are with counterparties that are also lenders (or affiliates of lenders) under our revolving credit facility. The contracts entered into with these counterparties are secured by the same collateral that secures our revolving credit facility which allows us to reduce any letters of credit posted as security with those counterparties. In addition, we enter into bilateral hedging agreements with other counterparties. The counterparties’ and our obligations under the bilateral hedging agreements must be secured by cash or letters of credit to the extent that any mark-to-market amounts owed to us or by us exceed defined thresholds.
Senior Note Obligations
Our senior note obligations consisted of the following as of September 30, 2017:
|
| | | | | | | | |
| | | September 30, 2017 |
| | | Principal
Amount | | Carrying
Amount |
| | | ($ 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 to our condensed consolidated financial statements included in Item 1 of Part I of this report.
Credit Risk
Derivative instruments that enable us to manage our exposure to oil, natural gas and NGL prices expose uswe sold partially offset by lower volumes of oil and NGL sold. The cash used in the 2021 Predecessor Period was primarily due to credit riskthe payment of professional fees related to the Chapter 11 Cases. Cash flows from our counterparties. To mitigate this risk, we enter into derivative contracts only with counterparties thatoperations are highly rated or deemedlargely affected by the Company to have acceptable credit strengthsame factors that affect our net income, excluding various non-cash items, such as depreciation, depletion and deemed by management to be competentamortization, certain impairments, gains or losses on sales of assets, deferred income taxes 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 bymark-to-market changes in economic, industry or other conditions. We generally require lettersour open derivative instruments. See further discussion below under Results of credit or parent guarantees for receivablesOperations.
Proceeds from parties that are judged to have sub-standard credit, unlessIssuance of Common Stock and Senior Notes
In the credit risk can otherwise be mitigated. During the Current Quarter, the Prior Quarter, the Current Period and the Prior2021 Predecessor Period, we recognized $1issued $500 million $1aggregate principal amount of 5.5% 2026 Notes and $500 million $7aggregate principal amount of 5.875% 2029 Notes for total proceeds of $1.0 billion. Additionally, upon emergence from Chapter 11, we issued 62,927,320 shares of New Common Stock in exchange for $600 million and $5 million, respectively, of bad debt expense related to potentially uncollectible receivables.cash as agreed upon in the Plan.
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 arrangements2021, our material contractual obligations included repayment of senior notes, outstanding borrowings and transactions included (i) operatinginterest payment obligations under the Exit Credit Facility, asset retirement obligations, 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)obligations, 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. See Notes 4obligations. In addition, we have contractual commitments with midstream
companies and 9pipeline carriers for future gathering, processing and transportation of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for further discussion of commitments and VPPs, respectively.
Results of Operations – Three Months Ended September 30, 2017 vs September 30, 2016
General. For the Current Quarter, Chesapeake had a net loss of $17 million, or $0.05 per diluted common share, on total revenues 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. The net loss in the Current Quarter was primarily due to non-cash unrealized hedging losses. The net loss in the Prior Quarter was primarily driven by non-cash impairments of fixed assets and other and impairments of oil and natural gas properties. 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 Quarter, oil, natural gas and NGL salesto move certain of our production to market. The estimated gross undiscounted future commitments under these agreements were $979approximately $3.4 billion as of September 30, 2021. As discussed above, we estimate the sources of our capital will continue to be adequate to fund our near and long-term contractual obligations.
Post-Emergence Debt
On the Effective Date, pursuant to the terms of the Plan, the Company, as borrower, entered into a reserve-based credit agreement (the “Credit Agreement”) providing for the Exit Credit Facility which features an initial borrowing base of $2.5 billion. The borrowing base will be redetermined semiannually on or around May 1 and November 1 of each year. Our borrowing base was reaffirmed in October 2021, and the next scheduled redetermination will be on or about May 1, 2022. The aggregate initial elected commitments of the lenders under the Exit Credit Facility will be $1.75 billion of revolving Tranche A Loans and $221 million comparedof fully funded Tranche B Loans.
The Exit Credit Facility provides for a $200 million sublimit of the aggregate commitments that are available for the issuance of letters of credit. The Exit Credit Facility bears interest at the ABR (alternate base rate) or LIBOR, at our election, plus an applicable margin (ranging from 2.25–3.25% per annum for ABR loans and 3.25–4.25% per annum for LIBOR loans, subject to $1.177a 1.00% LIBOR floor), depending on the percentage of the borrowing base then being utilized. The Tranche A Loans mature 3 years after the Effective Date and the Tranche B Loans mature 4 years after the Effective Date. The Tranche B Loans can be repaid if no Tranche A Loans are outstanding.
On February 2, 2021, the Company issued $500 million aggregate principal amount of its 2026 Notes and $500 million aggregate principal amount of its 2029 Notes. The offering of the Notes was part of a series of exit financing transactions undertaken in connection with the Debtors’ Chapter 11 Cases and meant to provide the exit financing originally intended to be provided by the Exit Term Loan Facility pursuant to the Commitment Letter.
Based upon the business plan approved by the Court and our hedging activities we expect to generate adequate cash flows from operating activities to fully fund all investing activities without incremental borrowings under our Exit Credit Facility.
Assumption and Repayment of Vine Debt
In conjunction with the Vine Acquisition, Vine’s Second Lien Term Loan was repaid and terminated for $163 million inclusive of a $13 million make whole premium with cash on hand due to the agreement containing a change in control provision making the term loan callable upon closing. Vine’s reserve based loan facility, which had no borrowings as of November 1, 2021, was terminated at the time of the acquisition. Additionally, Vine’s 6.75% Senior Notes with a principal amount of $950 million were assumed by the Company.
Capital Expenditures
For the year ending December 31, 2021, we currently expect to bring or have online approximately 125 to 140 gross wells by investing approximately $740 – $810 million in capital expenditures while operating approximately eight rigs inclusive of the Vine Acquisition. We expect that approximately 80% of our 2021 capital expenditures will be directed toward our natural gas assets. For the year ending December 31, 2022, we currently expect to invest approximately $1.3 – $1.6 billion in capital expenditures while operating approximately 10 to 12 rigs. We currently plan to fund our capital program through cash on hand and expected cash flow from our operations. 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.
Sources of Funds
The following table presents the sources of our cash and cash equivalents for the Successor and Predecessor periods.
| | | | | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | Period from February 10, 2021 through September 30, 2021 | | | Period from January 1, 2021 through February 9, 2021 | | Nine Months Ended
September 30, 2020 |
| Cash provided by (used in) operating activities | | $ | 1,246 | | | | $ | (21) | | | $ | 1,155 | |
| Proceeds from issuance of senior notes | | — | | | | 1,000 | | | — | |
| Proceeds from issuance of common stock | | — | | | | 600 | | | — | |
| Proceeds from warrant exercise | | 2 | | | | — | | | — | |
| Proceeds from divestitures of property and equipment | | 9 | | | | — | | | 15 | |
| Proceeds from revolving pre-petition credit facility borrowings, net | | — | | | | — | | | 339 | |
| Total sources of cash and cash equivalents | | $ | 1,257 | | | | $ | 1,579 | | | $ | 1,509 | |
Cash Flows from Operating Activities
Cash provided by operating activities was $1.246 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 sold2021 Successor Period, cash used in operating activities was $21 million in the Prior Quarter for $1.0482021 Predecessor Period, and cash provided by operating activities was $1.155 billion at a weighted average price of $17.86 per boe (excludingin the effect of derivatives).2020 Predecessor Period. The increase in the price received per boe in2021 Successor Period is primarily due to higher prices for 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).
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.
Gains (losses) from our oil, natural gas and NGL derivatives resulted in a net decrease inwe sold partially offset by lower volumes of oil natural gas and NGL revenues of $70 millionsold. The cash used in the Current Quarter2021 Predecessor Period was primarily due to the payment of professional fees related to the Chapter 11 Cases. Cash flows from operations are largely affected by the same factors that affect our net income, excluding various non-cash items, such as depreciation, depletion and a net increaseamortization, certain impairments, gains or losses on sales of $129assets, deferred income taxes and mark-to-market changes in our open derivative instruments. See further discussion below under Results of Operations.
Proceeds from Issuance of Common Stock and Senior Notes
In the 2021 Predecessor Period, we issued $500 million aggregate principal amount of 5.5% 2026 Notes and $500 million aggregate principal amount of 5.875% 2029 Notes for total proceeds of $1.0 billion. Additionally, upon emergence from Chapter 11, we issued 62,927,320 shares of New Common Stock in exchange for $600 million of cash as agreed upon 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.Plan.
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 effectUses 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.Funds
The following tables show average daily productiontable presents the uses of our cash and average sales prices received by our operating divisionscash equivalents for the Current QuarterSuccessor and the Prior Quarter:Predecessor periods:
| | | | | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | Period from February 10, 2021 through September 30, 2021 | | | Period from January 1, 2021 through February 9, 2021 | | Nine Months Ended
September 30, 2020 |
| Oil and Natural Gas Expenditures: | | | | | | | |
| Capital expenditures | | $ | 404 | | | | $ | 66 | | | $ | 973 | |
| Other Uses of Cash and Cash Equivalents: | | | | | | | |
| Payments on Exit Credit Facility - Tranche A Loans, net | | 50 | | | | 479 | | | — | |
| Payments on DIP Facility borrowings | | — | | | | 1,179 | | | — | |
| | | | | | | |
| Cash paid to purchase debt | | — | | | | — | | | 95 | |
| Debt issuance and other financing costs | | 3 | | | | 8 | | | 109 | |
| Common stock dividends paid | | 67 | | | | — | | | — | |
| Preferred stock dividends paid | | — | | | | — | | | 22 | |
| Other | | 1 | | | | — | | | 10 | |
| Total other uses of cash and cash equivalents | | 121 | | | | 1,666 | | | 236 | |
| Total uses of cash and cash equivalents | | $ | 525 | | | | $ | 1,732 | | | $ | 1,209 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 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 |
|
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(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 forcapital expenditures significantly decreased in 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)combined 2021 Successor 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 yearPredecessor Periods primarily as a result of decreased drilling and completion activity mainly in our liquids-rich plays.
Payments on DIP Facility Borrowings
On the saleEffective Date, the DIP Facility was terminated, and the holders of certainobligations under the DIP Facility received payment in full in cash; provided that to the extent such lender under the DIP Facility was also a lender under the Exit Credit Facility, such lender’s allowed DIP claims were first reduced dollar-for-dollar and satisfied by the amount of its Exit RBL Loans provided as of the Effective Date.
Cash Paid to Purchase Debt
In the 2020 Predecessor Period, we repurchased approximately $160 million aggregate principal amount of our Barnett, Mid-Continent and Devonian assets in 2016 and the sale of certainsenior notes for $95 million.
Common Stock Dividends
As part of our Haynesville Shale assets in 2017.
Excluding the impactdividend program, we paid dividends of derivatives,$67 million on our percentage of revenues from oil, natural gas and NGL is showncommon stock in the following table:2021 Successor Period.
Preferred Stock Dividends |
| | | | | | |
| | | 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 consistWe paid dividends of third-party revenues, and historically, the fair value adjustments$22 million on our supply contract derivatives (see preferred stock in the 2020 Predecessor Period. On April 17, 2020, we announced that we were suspending payment of dividends on each series of our outstanding convertible preferred stock. On the Effective Date of the Chapter 11 Cases, each holder of an equity interest in Chesapeake had their interest canceled, released, and extinguished without any distribution. See Note 82 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 consistabout the Chapter 11 Cases.
Table 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 $964 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 Quarter primarily as a result of contract assignments and terminations.Contents 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 resultAverage Sales Prices | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Successor |
| | Three Months Ended September 30, 2021 |
| | | Oil | | Natural Gas | | NGL | | Total |
| | | MBbl
per day | | $/Bbl | | MMcf
per day | | $/Mcf | | MBbl
per day | | $/Bbl | | MBoe
per day | | $/Boe |
| Appalachia | | — | | | — | | | 1,302 | | | 3.20 | | | — | | | — | | | 217 | | | 19.21 | |
| Gulf Coast | | — | | | — | | | 589 | | | 3.81 | | | — | | | — | | | 98 | | | 22.84 | |
| South Texas | | 34 | | | 70.96 | | | 107 | | | 4.46 | | | 15 | | | 34.60 | | | 66 | | | 51.02 | |
| Brazos Valley | | 25 | | | 69.54 | | | 33 | | | 2.82 | | | 3 | | | 27.41 | | | 34 | | | 56.88 | |
| Powder River Basin | | 9 | | | 69.31 | | | 53 | | | 4.33 | | | 3 | | | 44.53 | | | 21 | | | 47.48 | |
| Total | | 68 | | | 70.22 | | | 2,084 | | | 3.46 | | | 21 | | | 35.14 | | | 436 | | | 29.14 | |
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| | Predecessor |
| | Three Months Ended September 30, 2020 |
| | | Oil | | Natural Gas | | NGL | | Total |
| | | MBbl
per day | | $/Bbl | | MMcf
per day | | $/Mcf | | MBbl
per day | | $/Bbl | | MBoe
per day | | $/Boe |
| Appalachia | | — | | | — | | | 1,070 | | | 1.40 | | | — | | | — | | | 178 | | | 8.37 | |
| Gulf Coast | | — | | | — | | | 550 | | | 1.81 | | | — | | | — | | | 91 | | | 10.86 | |
| South Texas | | 51 | | | 39.79 | | | 132 | | | 2.08 | | | 22 | | | 12.81 | | | 95 | | | 27.31 | |
| Brazos Valley | | 36 | | | 38.45 | | | 43 | | | 0.80 | | | 5 | | | 6.69 | | | 49 | | | 29.82 | |
| Powder River Basin | | 10 | | | 38.69 | | | 41 | | | 1.79 | | | 3 | | | 15.94 | | | 20 | | | 25.98 | |
| Mid-Continent | | 4 | | | 40.12 | | | 31 | | | 1.63 | | | 3 | | | 11.58 | | | 12 | | | 20.15 | |
| Total | | 101 | | | 39.31 | | | 1,867 | | | 1.57 | | | 33 | | | 11.94 | | | 445 | | | 16.40 | |
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| | Successor |
| | Period from February 10, 2021 through September 30, 2021 |
| | | Oil | | Natural Gas | | NGL | | Total |
| | | MBbl
per day | | $/Bbl | | MMcf
per day | | $/Mcf | | MBbl
per day | | $/Bbl | | MBoe
per day | | $/Boe |
| Appalachia | | — | | | — | | | 1,289 | | | 2.57 | | | — | | | — | | | 215 | | | 15.43 | |
| Gulf Coast | | — | | | — | | | 552 | | | 3.11 | | | — | | | — | | | 92 | | | 18.67 | |
| South Texas | | 36 | | | 67.02 | | | 108 | | | 3.85 | | | 15 | | | 28.88 | | | 69 | | | 47.25 | |
| Brazos Valley | | 27 | | | 65.60 | | | 34 | | | 3.74 | | | 4 | | | 20.91 | | | 36 | | | 54.37 | |
| Powder River Basin | | 10 | | | 65.02 | | | 55 | | | 3.94 | | | 3 | | | 36.91 | | | 22 | | | 43.45 | |
| Total | | 73 | | | 66.23 | | | 2,038 | | | 2.84 | | | 22 | | | 28.85 | | | 434 | | | 25.85 | |
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| | Predecessor |
| | Period from January 1, 2021 through February 9, 2021 |
| | Oil | | Natural Gas | | NGL | | Total |
| | MBbl
per day | | $/Bbl | | MMcf
per day | | $/Mcf | | MBbl
per day | | $/Bbl | | MBoe
per day | | $/Boe |
| Appalachia | | — | | | — | | | 1,233 | | | 2.42 | | | — | | | — | | | 206 | | | 14.49 | |
| Gulf Coast | | — | | | — | | | 543 | | | 2.44 | | | — | | | — | | | 90 | | | 14.62 | |
| South Texas | | 42 | | | 54.12 | | | 127 | | | 3.00 | | | 14 | | | 26.04 | | | 78 | | | 39.20 | |
| Brazos Valley | | 32 | | | 52.37 | | | 38 | | | 1.14 | | | 4 | | | 16.09 | | | 42 | | | 42.23 | |
| Powder River Basin | | 10 | | | 51.96 | | | 61 | | | 2.92 | | | 4 | | | 34.31 | | | 24 | | | 34.25 | |
| Total | | 84 | | | 53.21 | | | 2,002 | | | 2.45 | | | 22 | | | 25.92 | | | 440 | | | 22.63 | |
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| | Predecessor |
| | Nine Months Ended September 30, 2020 |
| | | Oil | | Natural Gas | | NGL | | Total |
| | | MBbl
per day | | $/Bbl | | MMcf
per day | | $/Mcf | | MBbl
per day | | $/Bbl | | MBoe
per day | | $/Boe |
| Appalachia | | — | | | — | | | 1,032 | | | 1.57 | | | — | | | — | | | 172 | | | 9.43 | |
| Gulf Coast | | — | | | — | | | 536 | | | 1.66 | | | — | | | — | | | 89 | | | 9.95 | |
| South Texas | | 51 | | | 38.27 | | | 136 | | | 2.08 | | | 19 | | | 11.58 | | | 93 | | | 26.56 | |
| Brazos Valley | | 38 | | | 36.52 | | | 54 | | | 0.68 | | | 6 | | | 4.61 | | | 53 | | | 27.00 | |
| Powder River Basin | | 14 | | | 35.71 | | | 60 | | | 1.71 | | | 4 | | | 13.19 | | | 28 | | | 23.25 | |
| Mid-Continent | | 4 | | | 37.49 | | | 39 | | | 1.85 | | | 3 | | | 11.44 | | | 14 | | | 19.43 | |
| Total | | 107 | | | 37.32 | | | 1,857 | | | 1.62 | | | 32 | | | 10.31 | | | 449 | | | 16.32 | |
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Oil, Natural Gas and NGL Gathering, Processing and Transportation Expenses. Sales
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| | Successor |
| | Three Months Ended September 30, 2021 |
| | Oil | | Natural Gas | | NGL | | Total |
| Appalachia | | $ | — | | | $ | 383 | | | $ | — | | | $ | 383 | |
| Gulf Coast | | — | | | 207 | | | — | | | 207 | |
| South Texas | | 221 | | | 44 | | | 47 | | | 312 | |
| Brazos Valley | | 158 | | | 9 | | | 8 | | | 175 | |
| Powder River Basin | | 58 | | | 21 | | | 14 | | | 93 | |
| Oil, natural gas and NGL revenue | | $ | 437 | | | $ | 664 | | | $ | 69 | | | $ | 1,170 | |
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| | Predecessor |
| | Three Months Ended September 30, 2020 |
| | | Oil | | Natural Gas | | NGL | | Total |
| Appalachia | | $ | — | | | $ | 137 | | | $ | — | | | $ | 137 | |
| Gulf Coast | | — | | | 92 | | | — | | | 92 | |
| South Texas | | 189 | | | 26 | | | 26 | | | 241 | |
| Brazos Valley | | 127 | | | 3 | | | 3 | | | 133 | |
| Powder River Basin | | 36 | | | 7 | | | 4 | | | 47 | |
| Mid-Continent | | 14 | | | 5 | | | 3 | | | 22 | |
| Oil, natural gas and NGL revenue | | $ | 366 | | | $ | 270 | | | $ | 36 | | | $ | 672 | |
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| | Successor |
| | Period from February 10, 2021 through September 30, 2021 |
| | Oil | | Natural Gas | | NGL | | Total |
| Appalachia | | $ | — | | | $ | 772 | | | $ | — | | | $ | 772 | |
| Gulf Coast | | — | | | 401 | | | — | | | 401 | |
| South Texas | | 562 | | | 97 | | | 102 | | | 761 | |
| Brazos Valley | | 409 | | | 30 | | | 17 | | | 456 | |
| Powder River Basin | | 144 | | | 51 | | | 30 | | | 225 | |
| Total oil, natural gas and NGL sales | | $ | 1,115 | | | $ | 1,351 | | | $ | 149 | | | $ | 2,615 | |
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| | Predecessor |
| | Period from January 1, 2021 through February 9, 2021 |
| | Oil | | Natural Gas | | NGL | | Total |
| Appalachia | | $ | — | | | $ | 119 | | | $ | — | | | $ | 119 | |
| Gulf Coast | | — | | | 53 | | | — | | | 53 | |
| South Texas | | 92 | | | 15 | | | 15 | | | 122 | |
| Brazos Valley | | 67 | | | 2 | | | 2 | | | 71 | |
| Powder River Basin | | 20 | | | 7 | | | 6 | | | 33 | |
| Total oil, natural gas and NGL sales | | $ | 179 | | | $ | 196 | | | $ | 23 | | | $ | 398 | |
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| | Non-GAAP Combined |
| | Nine Months Ended September 30, 2021 |
| | Oil | | Natural Gas | | NGL | | Total |
| Appalachia | | $ | — | | | $ | 891 | | | $ | — | | | $ | 891 | |
| Gulf Coast | | — | | | 454 | | | — | | | 454 | |
| South Texas | | 654 | | | 112 | | | 117 | | | 883 | |
| Brazos Valley | | 476 | | | 32 | | | 19 | | | 527 | |
| Powder River Basin | | 164 | | | 58 | | | 36 | | | 258 | |
| Total oil, natural gas and NGL sales | | $ | 1,294 | | | $ | 1,547 | | | $ | 172 | | | $ | 3,013 | |
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| | Predecessor |
| | Nine Months Ended September 30, 2020 |
| | | Oil | | Natural Gas | | NGL | | Total |
| Appalachia | | $ | — | | | $ | 445 | | | $ | — | | | $ | 445 | |
| Gulf Coast | | — | | | 245 | | | — | | | 245 | |
| South Texas | | 539 | | | 77 | | | 59 | | | 675 | |
| Brazos Valley | | 375 | | | 10 | | | 9 | | | 394 | |
| Powder River Basin | | 133 | | | 28 | | | 14 | | | 175 | |
| Mid-Continent | | 44 | | | 19 | | | 9 | | | 72 | |
| Total oil, natural gas and NGL sales | | $ | 1,091 | | | $ | 824 | | | $ | 91 | | | $ | 2,006 | |
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Oil, natural gas and NGL sales in the 2021 Successor Quarter increased $498 million compared to the 2020 Predecessor Quarter. The increase is primarily attributable to a $511 million increase in revenues from higher average prices received, partially offset by a $13 million decrease in revenues due to slightly lower sales volumes, which primarily resulted from the sale of Mid-Continent properties in 2020. The higher average prices received are consistent with the upward trend in index prices for all products seen throughout the 2021 Successor Quarter.
Oil, natural gas and NGL sales in the combined 2021 Successor and Predecessor Periods increased $1,007 million compared to the 2020 Predecessor Period. The increase is primarily attributable to a $1,074 million increase in revenues from higher average prices received, partially offset by a $72 million reduction from the sale of Mid-Continent properties in 2020. Excluding the decrease in volumes related to the sale of Mid-Continent properties in 2020, average daily production is consistent in the combined 2021 Successor and Predecessor Periods and 2020 Predecessor Period due to an increase in new well completions in Appalachia and Gulf Coast offset by a reduction in South Texas, Brazos Valley, and Powder River Basin wells turned-in-line.
Production Expenses
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | Three Months Ended
September 30, 2021 | | | Three Months Ended September 30, 2020 |
| | | | $/Boe | | | | | $/Boe |
| Appalachia | | $ | 9 | | | 0.47 | | | | $ | 8 | | | 0.49 |
| Gulf Coast | | 13 | | 1.42 | | | | 10 | | 1.20 |
| South Texas | | 31 | | 5.04 | | | | 24 | | 2.73 |
| Brazos Valley | | 18 | | 5.96 | | | | 17 | | 3.83 |
| Powder River Basin | | 9 | | 4.38 | | | | 9 | | 4.53 |
| Mid-Continent | | — | | | — | | | | 14 | | 13.11 |
| Total production expenses | | $ | 80 | | | 1.99 | | | | $ | 82 | | | 1.99 |
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| | Successor | | | Predecessor | | Non-GAAP Combined | | Predecessor |
| | Period from February 10, 2021 through
September 30, 2021 | | | Period from
January 1, 2021 through
February 9, 2021 | | Nine Months Ended
September 30, 2021 | | Nine Months Ended
September 30, 2020 |
| | | | $/Boe | | | | | $/Boe | | | | $/Boe | | | | $/Boe |
| Appalachia | | $ | 23 | | | 0.47 | | | | $ | 4 | | | 0.50 | | | $ | 27 | | | 0.47 | | | $ | 24 | | | 0.51 | |
| Gulf Coast | | 30 | | | 1.39 | | | | 4 | | | 1.12 | | | 34 | | | 1.35 | | | 32 | | | 1.30 | |
| South Texas | | 74 | | | 4.60 | | | | 12 | | | 3.90 | | | 86 | | | 4.48 | | | 85 | | | 3.24 | |
| Brazos Valley | | 46 | | | 5.52 | | | | 9 | | | 4.85 | | | 55 | | | 5.41 | | | 67 | | | 4.61 | |
| Powder River Basin | | 21 | | | 4.07 | | | | 3 | | | 3.37 | | | 24 | | | 3.96 | | | 37 | | | 4.74 | |
| Mid-Continent | | — | | | — | | | | — | | | — | | | — | | | — | | | 50 | | | 13.69 | |
| Total production expenses | | $ | 194 | | | 1.92 | | | | $ | 32 | | | 1.80 | | | $ | 226 | | | 1.90 | | | $ | 295 | | | 2.40 | |
Production expenses in the 2021 Successor Quarter decreased $2 million as compared to the 2020 Predecessor Quarter. The decrease was primarily due to a $14 million reduction from the sale of Mid-Continent properties in 2020, partially offset by increased workover expense and repair and maintenance expense in South Texas and Gulf Coast.
Production expenses in the combined 2021 Successor and Predecessor Periods decreased $69 million as compared to the 2020 Predecessor Period. The decrease was primarily due to a $50 million reduction from the sale of Mid-Continent properties in 2020 and a $25 million reduction in our Brazos Valley and Powder River Basin operating areas due to lower production volumes from reduced capital allocation.
Gathering, Processing and Transportation Expenses
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| | Successor | | | Predecessor |
| | Three Months Ended September 30, 2021 | | | Three Months Ended September 30, 2020 |
| | | | $/Boe | | | | | $/Boe |
| Appalachia | | $ | 83 | | | 4.14 | | | | $ | 73 | | | 4.39 | |
| Gulf Coast | | 28 | | | 3.09 | | | | 46 | | | 5.42 | |
| South Texas | | 82 | | | 13.38 | | | | 106 | | | 12.08 | |
| Brazos Valley | | 3 | | | 0.98 | | | | 7 | | | 1.49 | |
| Powder River Basin | | 23 | | | 11.95 | | | | 21 | | | 11.84 | |
| Mid-Continent | | — | | | — | | | | 5 | | | 5.10 | |
| Total gathering, processing and transportation expenses | | $ | 219 | | | 5.45 | | | | $ | 258 | | | 6.28 | |
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| | Successor | | | Predecessor | | Non-GAAP Combined | | Predecessor |
| | Period from February 10, 2021 through
September 30, 2021 | | | Period from
January 1, 2021 through
February 9, 2021 | | Nine Months Ended
September 30, 2021 | | Nine Months Ended
September 30, 2020 |
| | | | $/Boe | | | | | $/Boe | | | | $/Boe | | | | $/Boe |
| Appalachia | | $ | 204 | | | 4.07 | | | | $ | 34 | | | 4.17 | | | $ | 238 | | | 4.08 | | | $ | 217 | | | 4.60 | |
| Gulf Coast | | 64 | | | 2.98 | | | | 11 | | | 2.93 | | | 75 | | | 2.98 | | | 137 | | | 5.59 | |
| South Texas | | 203 | | | 12.56 | | | | 42 | | | 13.35 | | | 245 | | | 12.69 | | | 338 | | | 13.28 | |
| Brazos Valley | | 8 | | | 1.03 | | | | 3 | | | 1.92 | | | 11 | | | 1.18 | | | 21 | | | 1.40 | |
| Powder River Basin | | 62 | | | 12.00 | | | | 12 | | | 12.53 | | | 74 | | | 12.08 | | | 79 | | | 10.46 | |
| Mid-Continent | | — | | | — | | | | — | | | — | | | — | | | — | | | 21 | | | 5.83 | |
| Total gathering, processing and transportation expenses | | $ | 541 | | | 5.45 | | | | $ | 102 | | | 5.78 | | | $ | 643 | | | 5.41 | | | $ | 813 | | | 6.61 | |
Gathering, processing and transportation expenses in the 2021 Successor Quarter decreased $39 million as compared to the 2020 Predecessor Quarter. Gulf Coast decreased $18 million as a result of contract negotiations in the Chapter 11 Cases. South Texas decreased $24 million primarily as a result of reduced production due to fewer wells brought on line in 2021. Additionally, the sale of Mid-Continent properties in 2020 resulted in a $5 million reduction. These decreases were partially offset by a $10 million increase in Appalachia as a result of increased production.
Gathering, processing and transportation expenses in the combined 2021 Successor and Predecessor Periods decreased $170 million as compared to the 2020 Predecessor Period. Gulf Coast decreased $62 million as a result of contract negotiations in the Chapter 11 Cases. South Texas decreased $93 million primarily as a result of reduced production as well as contract negotiations in the Chapter 11 Cases. Additionally, the sale of Mid-Continent properties in 2020 resulted in a $21 million reduction. These decreases were partially offset by a $21 million increase in Appalachia as a result of increased production.
Severance and Ad Valorem Taxes
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| | Successor | | | Predecessor |
| | Three Months Ended September 30, 2021 | | | Three Months Ended September 30, 2020 |
| | | | $/Boe | | | | | $/Boe |
| Appalachia | | $ | 2 | | | 0.13 | | | | $ | 1 | | | 0.09 | |
| Gulf Coast | | 5 | | | 0.55 | | | | 4 | | | 0.52 | |
| South Texas | | 17 | | | 2.72 | | | | 16 | | | 1.79 | |
| Brazos Valley | | 8 | | | 2.63 | | | | 10 | | | 2.05 | |
| Powder River Basin | | 9 | | | 4.59 | | | | 5 | | | 2.65 | |
| Mid-Continent | | — | | | — | | | | 1 | | | 1.13 | |
| Total severance and ad valorem taxes | | $ | 41 | | | 1.03 | | | | $ | 37 | | | 0.90 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor | | Non-GAAP Combined | | Predecessor |
| | Period from February 10, 2021 through
September 30, 2021 | | | Period from
January 1, 2021 through
February 9, 2021 | | Nine Months Ended
September 30, 2021 | | Nine Months Ended
September 30, 2020 |
| | | | $/Boe | | | | | $/Boe | | | | $/Boe | | | | $/Boe |
| Appalachia | | $ | 6 | | | 0.13 | | | | $ | 1 | | | 0.07 | | | $ | 7 | | | 0.12 | | | $ | 4 | | | 0.09 | |
| Gulf Coast | | 12 | | | 0.55 | | | | 2 | | | 0.54 | | | 14 | | | 0.55 | | | 14 | | | 0.60 | |
| South Texas | | 42 | | | 2.56 | | | | 8 | | | 2.53 | | | 50 | | | 2.55 | | | 43 | | | 1.68 | |
| Brazos Valley | | 25 | | | 3.03 | | | | 5 | | | 2.99 | | | 30 | | | 3.03 | | | 33 | | | 2.23 | |
| Powder River Basin | | 21 | | | 4.15 | | | | 2 | | | 2.88 | | | 23 | | | 3.95 | | | 18 | | | 2.37 | |
| Mid-Continent | | — | | | — | | | | — | | | — | | | — | | | — | | | 4 | | | 1.07 | |
| Total severance and ad valorem taxes | | $ | 106 | | | 1.05 | | | | $ | 18 | | | 1.03 | | | $ | 124 | | | 1.05 | | | $ | 116 | | | 0.94 | |
Severance and ad valorem taxes in the 2021 Successor Quarter increased $4 million as compared to the 2020 Predecessor Quarter. The severance tax increase of $4 million was primarily driven by increased revenue as a result of improved pricing.
Severance and ad valorem taxes in the combined 2021 Successor and Predecessor Periods increased $8 million as compared to the 2020 Predecessor Period. The severance tax increase of $12 million was primarily driven by increased revenue as a result of improved pricing. The ad valorem tax decrease of $4 million was primarily driven by lower assessed property values in the combined 2021 Successor and Predecessor Periods for Brazos Valley and South Texas.
Gross Margin by Operating Area
The table below presents the gross margin for each of our operating areas. Gross margin by operating area is defined as oil, natural gas and NGL sales less production expenses, gathering, processing and transportation expenses, were $369 millionand severance and ad valorem taxes.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | Three Months Ended September 30, 2021 | | | Three Months Ended September 30, 2020 |
| | | | $/Boe | | | | | $/Boe |
| Appalachia | | $ | 289 | | | 14.47 | | | | $ | 55 | | | 3.40 | |
| Gulf Coast | | 161 | | | 17.78 | | | | 32 | | | 3.72 | |
| South Texas | | 182 | | | 29.88 | | | | 95 | | | 10.71 | |
| Brazos Valley | | 146 | | | 47.31 | | | | 99 | | | 22.45 | |
| Powder River Basin | | 52 | | | 26.56 | | | | 12 | | | 6.96 | |
| Mid-Continent | | — | | | — | | | | 2 | | | 0.81 | |
| Gross margin by operating area | | $ | 830 | | | 20.67 | | | | $ | 295 | | | 7.23 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor | | Non-GAAP Combined | | Predecessor |
| | Period from February 10, 2021 through
September 30, 2021 | | | Period from
January 1, 2021 through
February 9, 2021 | | Nine Months Ended
September 30, 2021 | | Nine Months Ended September 30, 2020 |
| | | | $/Boe | | | | | $/Boe | | | | $/Boe | | | | $/Boe |
| Appalachia | | $ | 539 | | | 10.76 | | | | $ | 80 | | | 9.75 | | | $ | 619 | | | 10.63 | | | $ | 200 | | | 4.23 | |
| Gulf Coast | | 295 | | | 13.75 | | | | 36 | | | 10.03 | | | 331 | | | 13.21 | | | 62 | | | 2.46 | |
| South Texas | | 442 | | | 27.53 | | | | 60 | | | 19.42 | | | 502 | | | 26.22 | | | 209 | | | 8.36 | |
| Brazos Valley | | 377 | | | 44.79 | | | | 54 | | | 32.47 | | | 431 | | | 42.72 | | | 273 | | | 18.76 | |
| Powder River Basin | | 121 | | | 23.23 | | | | 16 | | | 15.47 | | | 137 | | | 22.02 | | | 41 | | | 5.68 | |
| Mid-Continent | | — | | | — | | | | — | | | — | | | — | | | — | | | (3) | | | (1.16) | |
| Gross margin by operating area | | $ | 1,774 | | | 17.43 | | | | $ | 246 | | | 14.02 | | | $ | 2,020 | | | 17.01 | | | $ | 782 | | | 6.37 | |
Oil and Natural Gas Derivatives | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | Three Months Ended
September 30, 2021 | | | Three Months Ended
September 30, 2020 |
| Oil derivatives – realized gains (losses) | | $ | (128) | | | | $ | 2 | |
| Oil derivatives – unrealized gains (losses) | | 62 | | | | (4) | |
| Total losses on oil derivatives | | (66) | | | | (2) | |
| | | | | |
| Natural gas derivatives – realized gains (losses) | | (163) | | | | 5 | |
| Natural gas derivatives – unrealized losses | | (681) | | | | (164) | |
| Total losses on natural gas derivatives | | (844) | | | | (159) | |
| Total losses on oil and natural gas derivatives | | $ | (910) | | | | $ | (161) | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | Period from February 10, 2021 through September 30, 2021 | | | Period from January 1, 2021 through February 9, 2021 | | Nine Months Ended
September 30, 2020 |
| Oil derivatives – realized gains (losses) | | $ | (302) | | | | $ | (19) | | | $ | 698 | |
| Oil derivatives – unrealized losses | | (138) | | | | (190) | | | (9) | |
| Total gains (losses) on oil derivatives | | (440) | | | | (209) | | | 689 | |
| | | | | | | |
| Natural gas derivatives – realized gains (losses) | | (179) | | | | 6 | | | 179 | |
| Natural gas derivatives – unrealized losses | | (985) | | | | (179) | | | (295) | |
| Total losses on natural gas derivatives | | (1,164) | | | | (173) | | | (116) | |
| Total gains (losses) on oil and natural gas derivatives | | $ | (1,604) | | | | $ | (382) | | | $ | 573 | |
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 our derivative activity. Marketing Revenues and Expenses
| | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | Three Months Ended
September 30, 2021 | | | Three Months Ended
September 30, 2020 |
| Marketing revenues | | $ | 627 | | | | $ | 448 | |
| Marketing expenses | | 625 | | | | 450 | |
| Marketing margin | | $ | 2 | | | | $ | (2) | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | Period from February 10, 2021 through September 30, 2021 | | | Period from January 1, 2021 through February 9, 2021 | | Nine Months Ended
September 30, 2020 |
| Marketing revenues | | $ | 1,443 | | | | $ | 239 | | | $ | 1,412 | |
| Marketing expenses | | 1,440 | | | | 237 | | | 1,438 | |
| Marketing margin | | $ | 3 | | | | $ | 2 | | | $ | (26) | |
Marketing margin increased in the Current2021 Successor 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 $8.07 per boe in the Prior Quarter. The absolute and per unit decrease primarily related to divestitures in 2016 and 2017. A summary of oil, natural gas and NGL gathering, processing and transportation expenses by product is shown below.
|
| | | | | | | | |
| | | Three Months Ended
September 30, |
| | | 2017 | | 2016 |
| Oil ($ 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 Quarter 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 Quarter was primarily due to higher prices received for our oil, natural gas and NGL production. Production taxes in both the Current Quarter and the Prior Quarter included $1 million, or $0.01 and $0.02 per boe, respectively, associated with VPP production volumes.increased profit on third-party marketing as a result of improved pricing.
General and Administrative Expenses. General and administrative expenses were $54 millionMarketing margin increased in the Current Quarter2021 Successor Period primarily due to the significant drop in oil prices during the 2020 Predecessor Period that resulted in an unfavorable inventory valuation adjustment.
Exploration Expense
| | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | Three Months Ended
September 30, 2021 | | | Three Months Ended
September 30, 2020 |
| Impairments of unproved properties | | $ | 1 | | | | $ | 3 | |
| | | | | |
| Geological and geophysical expense and other | | 1 | | | | 2 | |
| Total exploration expense | | $ | 2 | | | | $ | 5 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | Period from February 10, 2021 through September 30, 2021 | | | Period from January 1, 2021 through February 9, 2021 | | Nine Months Ended
September 30, 2020 |
| Impairments of unproved properties | | $ | 1 | | | | $ | 2 | | | $ | 402 | |
| Dry hole expense | | — | | | | — | | | 7 | |
| Geological and geophysical expense and other | | 3 | | | | — | | | 8 | |
| Total exploration expense | | $ | 4 | | | | $ | 2 | | | $ | 417 | |
The 2020 Predecessor Period exploration expense is the result of non-cash impairment charges in unproved properties, primarily in our Brazos Valley, Gulf Coast, Powder River Basin 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.Mid-Continent operating areas. See Note 413 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for further discussiondiscussion.General and Administrative Expenses
| | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | Three Months Ended
September 30, 2021 | | | Three Months Ended
September 30, 2020 |
| Gross compensation and benefits | | $ | 68 | | | | $ | 93 | |
| Non-labor | | 24 | | | | 29 | |
| Allocations and reimbursements | | (62) | | | | (70) | |
| Total general and administrative expenses, net | | $ | 30 | | | | $ | 52 | |
| | | | | |
| General and administrative expenses, net per Boe | | $ | 0.74 | | | | $ | 1.27 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | Period from February 10, 2021 through September 30, 2021 | | | Period from January 1, 2021 through February 9, 2021 | | Nine Months Ended
September 30, 2020 |
| Gross compensation and benefits | | $ | 162 | | | | $ | 32 | | | $ | 305 | |
| Non-labor | | 60 | | | | 12 | | | 167 | |
| Allocations and reimbursements | | (153) | | | | (23) | | | (243) | |
| Total general and administrative expenses, net | | $ | 69 | | | | $ | 21 | | | $ | 229 | |
| | | | | | | |
| General and administrative expenses, net per Boe | | $ | 0.68 | | | | $ | 1.19 | | | $ | 1.86 | |
Oil, Natural GasCompensation and NGL benefits before reimbursements and allocations during the 2021 Successor Quarter decreased $25 million compared to the 2020 Predecessor Quarter due to reductions in workforce in the 2020 and 2021 Predecessor Periods. Non-labor before reimbursements and allocations during the 2021 Successor Quarter decreased $5 million compared to the 2020 Predecessor Quarter primarily due to cost reduction initiatives for professional services. The decrease in allocations and reimbursements was the result of staffing reductions and the sale of Mid-Continent properties in 2020.
Compensation and benefits before reimbursements and allocations during the combined 2021 Successor and Predecessor Periods decreased $111 million compared to the 2020 Predecessor Period due to reductions in workforce in the 2020 and 2021 Predecessor Periods. Non-labor before reimbursements and allocations during the combined 2021 Successor and Predecessor Periods decreased $95 million compared to the 2020 Predecessor Period due to cost reduction initiatives for professional services as well as $43 million in fees for legal, financial and restructuring advisors incurred in preparation for the Chapter 11 Cases in the 2020 Predecessor Period. The decrease in allocations and reimbursements during the combined 2021 Successor and Predecessor Periods compared to the 2020 Predecessor Period was the result of reduced drilling, staffing reductions and the sale of Mid-Continent properties in 2020.
Separation and Other Termination Costs
| | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | Three Months Ended
September 30, 2021 | | | Three Months Ended
September 30, 2020 |
| Separation and other termination costs | | $ | — | | | | $ | 16 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | Period from February 10, 2021 through September 30, 2021 | | | Period from January 1, 2021 through February 9, 2021 | | Nine Months Ended
September 30, 2020 |
| Separation and other termination costs | | $ | 11 | | | | $ | 22 | | | $ | 43 | |
Separation and other termination costs relate to one-time termination benefits for certain employees.
Depreciation, Depletion and Amortization. Depreciation,
| | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | Three Months Ended
September 30, 2021 | | | Three Months Ended
September 30, 2020 |
| Depreciation, depletion and amortization | | $ | 228 | | | | $ | 170 | |
| Depreciation, depletion and amortization per Boe | | $ | 5.67 | | | | $ | 4.17 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | Period from February 10, 2021 through September 30, 2021 | | | Period from January 1, 2021 through February 9, 2021 | | Nine Months Ended
September 30, 2020 |
| Depreciation, depletion and amortization | | $ | 579 | | | | $ | 72 | | | $ | 931 | |
| Depreciation, depletion and amortization per Boe | | $ | 5.72 | | | | $ | 4.11 | | | $ | 7.58 | |
The absolute and per unit increase in depreciation, depletion and amortization (DD&A) of oil, natural gas and NGL properties was $228 million and $251 million infor the Current2021 Successor Quarter andcompared to the Prior Quarter, respectively. The decrease in the Current2020 Predecessor Quarter was primarily the result of decreased production as a resultthe revaluation of the saledepletable asset base occurring in connection with our emergence from bankruptcy. Fresh start accounting requires that new fair values be established for our assets as of certainthe emergence date. See Note 3 for additional information on revaluation of our Barnettoil and Mid-Continent assets in 2016 and the salegas properties.
The average DD&A rate per boe, which is a function of capitalized costs, future development costs and the related underlying reservesunit decrease 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 Quarter2021 Predecessor Period compared to $25 million in the Prior Quarter. On a unit-of-production basis, depreciation and amortization of other assets2020 Predecessor Period was $0.41 per boe inattributable to an $8.4 billion impairment to 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. OurPredecessor’s proved 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. recognized at March 31, 2020.
Impairments
| | | | | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | Period from February 10, 2021 through September 30, 2021 | | | Period from January 1, 2021 through February 9, 2021 | | Nine Months Ended
September 30, 2020 |
| Impairments of proved oil and natural gas properties | | $ | — | | | | $ | — | | | $ | 8,446 | |
| Impairments of other fixed assets and other | | 1 | | | | — | | | 76 | |
| Total impairments | | $ | 1 | | | | $ | — | | | $ | 8,522 | |
In the Current Quarter, capitalized costs2020 Predecessor Period, we recorded impairments of proved oil and natural gas properties did not exceedrelated to South Texas, Brazos Valley, Powder River Basin, Mid-Continent and other non-core assets, all of which were due to lower forecasted commodity prices. Additionally, in the ceiling. For2020 Predecessor Period, we recorded a $76 million impairment of our sand mine assets that support our Brazos Valley operating area for the Prior Quarter, capitalized costs of oildifference between fair value and natural gas properties exceeded the ceiling, resulting in an impairment of the carrying value of the assets. See Note 14 of the notes to our oil and natural gas propertiescondensed consolidated financial statements included in Item 1 of $497 million.Part I of this report for further discussion. Impairments of Fixed Assets and Other.Other Operating Expense (Income), Net
| | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | Three Months Ended
September 30, 2021 | | | Three Months Ended
September 30, 2020 |
| Other operating expense, net | | $ | 3 | | | | $ | 1 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | Period from February 10, 2021 through September 30, 2021 | | | Period from January 1, 2021 through February 9, 2021 | | Nine Months Ended
September 30, 2020 |
| Other operating expense (income), net | | $ | 1 | | | | $ | (12) | | | $ | 67 | |
In the Current Quarter2020 Predecessor Period, we terminated certain gathering, processing and transportation contracts and recognized a non-recurring $80 million expense related to 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 $334contract terminations as well as $29 million of charges in the Prior Quarter 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 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 amountsoperating expense primarily related to royalty settlements offset by $42 million of income from the saleamortization of other property and equipment.volumetric production payment deferred revenue.
Interest Expense. Interest
| | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | Three Months Ended
September 30, 2021 | | | Three Months Ended
September 30, 2020 |
| Interest expense on debt | | $ | 19 | | | | $ | 25 | |
| Amortization of premium, discount, issuance costs and other | | 1 | | | | 2 | |
| Capitalized interest | | (3) | | | | (2) | |
| Total interest expense | | $ | 17 | | | | $ | 25 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | Period from February 10, 2021 through September 30, 2021 | | | Period from January 1, 2021 through February 9, 2021 | | Nine Months Ended
September 30, 2020 |
| Interest expense on debt | | $ | 50 | | | | $ | 11 | | | $ | 377 | |
| Amortization of premium, discount, issuance costs and other | | 4 | | | | — | | | (57) | |
| Capitalized interest | | (7) | | | | — | | | (13) | |
| Total interest expense | | $ | 47 | | | | $ | 11 | | | $ | 307 | |
The decrease in total interest expense was $114 million in the Current2021 Successor Quarter and 2021 Successor Period compared to $73 millionthe 2020 Predecessor Quarter and 2020 Predecessor Period resulted from the decrease in outstanding debt obligations between periods. Upon emergence from the Prior Quarter as follows:
|
| | | | | | | | |
| | | Three Months Ended
September 30, |
| | | 2017 | | 2016 |
| | | ($ 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 periodChapter 11 Cases, all outstanding obligations under our Predecessor senior notes 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 expensewere cancelled in exchange for shares of New Common Stock and
a decrease in capitalized interest as a resultWarrants. See Note 3 and Note 5 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 relatednotes to our equity investmentcondensed consolidated financial statements included in Sundrop Fuels, Inc.Item 1 of Part I of this report for a discussion of the Chapter 11 Cases.
Gains (Losses) on Purchases or Exchanges of Debt.
In the Current Quarter,2020 Predecessor Period, we repurchased $5approximately $160 million aggregate principal amount of our outstanding senior notes and contingent convertible senior notes for $6 million. We$95 million and 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.approximately $65 million.
Other Income Tax Expense (Benefit). Chesapeake(Expense)
| | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | Three Months Ended
September 30, 2021 | | | Three Months Ended
September 30, 2020 |
| Other income | | $ | — | | | | $ | 2 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | Period from February 10, 2021 through September 30, 2021 | | | Period from January 1, 2021 through February 9, 2021 | | Nine Months Ended
September 30, 2020 |
| Other income (expense) | | $ | 31 | | | | $ | 2 | | | $ | (9) | |
In the 2021 Successor Period, we recorded a nominal amountgain of $22 million for a refund from a midstream provider.
Reorganization Items, Net
| | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | Three Months Ended September 30, 2021 | | | Three Months Ended September 30, 2020 |
| Accrual for allowed claims | | $ | — | | | | $ | (465) | |
| Debt and equity financing fees | | — | | | | (115) | |
| Professional service provider fees and other | | — | | | | (40) | |
| Gains on the settlement of liabilities subject to compromise | | — | | | | 9 | |
| Total reorganization items, net | | $ | — | | | | $ | (611) | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | Successor | | | Predecessor |
| | Period from February 10, 2021 through September 30, 2021 | | | Period from January 1, 2021 through
February 9, 2021 | | Nine Months Ended
September 30, 2020 |
| Gains on the settlement of liabilities subject to compromise | | $ | — | | | | $ | 6,443 | | | $ | 9 | |
| Accrual for allowed claims | | — | | | | (1,002) | | | (465) | |
| Write off of unamortized debt premiums (discounts) on Predecessor debt | | — | | | | — | | | 518 | |
| Write off of unamortized debt issuance costs on Predecessor debt | | — | | | | — | | | (61) | |
| Gain on fresh start adjustments | | — | | | | 201 | | | — | |
| Gain from release of commitment liabilities | | — | | | | 55 | | | — | |
| Debt and equity financing fees | | — | | | | — | | | (178) | |
| Professional service provider fees and other | | — | | | | (60) | | | (40) | |
| Success fees for professional service providers | | — | | | | (38) | | | — | |
| Surrender of other receivable | | — | | | | (18) | | | — | |
| FLLO alternative transaction fee | | — | | | | (12) | | | — | |
| Total reorganization items, net | | $ | — | | | | $ | 5,569 | | | $ | (217) | |
In the 2021 and 2020 Predecessor Periods, we recorded a net gain of $5.569 billion and a net loss of $217 million, respectively, in reorganization items, net related to the Chapter 11 Cases. See Note 2 and Note 3 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for a discussion of the Chapter 11 Cases and for discussion of adoption of fresh start accounting. Income Taxes
An income tax benefit of $10 million was recorded for the 2021 Successor Period as a result of projecting current state income taxes. Although we are projecting a current state tax liability, a benefit has been recorded in the Current Quarter.2021 Successor Period due to the application of our estimated annual effective tax rate to the 2021 Successor Period book net loss before income taxes. An income tax benefit of $57 million was recorded for the 2021 Predecessor Period and an income tax benefit of $13 million was recorded for the 2020 Predecessor Period. Our effective income tax rates were 0.0% in both the Current Quarter and the Prior Quarter. The resulting effective income tax ratesrate was 2.0% for the Current Quarter2021 Successor Period, (1.1%) for the 2021 Predecessor Period and 0.1% for the Prior Quarter are primarily due to the offsetting impact of the change in the valuation allowance. Further, our2020 Predecessor Period. Our effective tax rate can fluctuate as a result of the impact of discrete items, state income taxes and permanent differences. See Note 129 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 $1 million in the Current Quarter 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, 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 Period 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.taxes.
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.Forward-Looking Statements |
| |
(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 billion in the Current Period compared to $1.436 billion in the Prior Period. On 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 received 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 restructuring 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 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 $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. Depreciation and amortization of other assets was $62 million in the Current Period compared 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 $0.46 per boe in the Prior Period. Property and equipment costs are depreciated on a straight-line basis over the estimated useful lives of the assets. The following table shows depreciation expense by asset class for the Current Period and the Prior Period and the estimated useful lives of these assets.
|
| | | | | | | | | | |
| | | Nine Months Ended
September 30, | | Estimated Useful Life |
| | | 2017 | | 2016 | |
| | | ($ 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. |
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”).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 COVID-19 pandemic and NGL productionthe impact thereof on our business, financial condition, results of operations and future expenses, estimated operating costs, assumptions regarding future oil, natural gascash flows, the potential effects of the Plan restructuring on our operations, management, and NGL prices, planned drilling activity, estimatesemployees, actions by, or disputes among or between, members of future drilling and completionOPEC+ 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, and comply withthe amount and timing of any cash dividends, and our ESG initiatives. In this context, forward-looking statements often address our expected future business, financial maintenance covenants, meet contractual cash commitments to third parties, debt repurchases, operatingperformance and capital efficiencies, business strategy, the effect of our remediation plan for a material weakness,financial condition, and other plans and objectives for future operations. Disclosures concerning the fair values of derivative contracts and their estimated contribution to our future results of operations are based upon market informationoften contain words such as of a specific date. These market prices are subject to significant volatility."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 ability to execute on our business strategy following emergence from bankruptcy;
•the impact of the COVID-19 pandemic and its effect on our business, financial condition, employees, contractors, vendors and the global demand for oil and natural gas and U.S. and world financial markets;
•risks related to the Vine Acquisition, including our ability to successfully integrate the business of Vine into the Company and achieve the expected results are describedsynergies from the Vine Acquisition within the expected timeframe;
•our ability to comply with the covenants under Risk Factors in Item 1A ofour annual report on Form 10-K for the year ended December 31, 2016 (2016 Form 10-K)Exit Credit Facility and include:other indebtedness;
•our ability to realize anticipated cash cost reductions;
•the volatility of oil, natural gas 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;
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 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;
leasehold terms expiring before production can be established;•the limitations our level of indebtedness may have on our financial flexibility;
•our inability to access the capital markets on favorable terms;
•the availability of cash flows from operations and other funds to fund cash dividends, finance reserve replacement costs or satisfy our debt obligations;
commodity derivative activities resulting in lower prices realized on oil, natural gas and NGL sales;
the need to secure derivative liabilities and the inability of counterparties to satisfy their obligations;
•adverse developments or losses from pending or future litigation and regulatory proceedings, including royalty claims;
charges incurred•legislative, regulatory and ESG initiatives, including as a result of the change 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;
effectsthe U.S. presidential administration, addressing environmental concerns, including initiatives addressing the impact of environmental protection laws and regulation on our business;
legislative and regulatory initiativesglobal climate change or further regulating hydraulic fracturing;fracturing, methane emissions, flaring or water disposal;
our need to secure adequate supplies of water for our drilling operations and to dispose of or recycle the water used;
impacts of potential legislative and regulatory actions addressing climate change;
federal and state tax proposals affecting our industry;
potential OTC derivatives regulation limiting our ability to hedge against commodity price fluctuations;
competition in the oil and gas exploration and production industry;
a deterioration in general economic, business or industry conditions;
negative public perceptions of our industry;
limited control over properties we do not operate;
pipeline and gathering system capacity constraints and transportation interruptions;
•terrorist activities and/or cyber-attacks adversely impacting our operations;
potential challenges by SSE’s former creditors•effects of purchase price adjustments and indemnity obligations; and
•other factors that are described under Risk Factors in Item 1A of our spin-off2020 Form 10-K and Risk Factors in Item 1A of in connection with SSE’s recently completed bankruptcy under Chapter 11Part II of the U.S. Bankruptcy Code; an interruption in operations at our headquarters due to a catastrophic event;
the continuation of suspended dividend payments on our common stock;
the effectiveness 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.this report.
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 furnish quarterly, annual, and current reports for certain of our subsidiaries free of charge on our website at chk.com. 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 there 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.
| | | | | |
| 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 oil, natural gas, 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 and NGL.NGL, which have been historically volatile. To mitigate a portion of our exposure to adverse price changes, we have enteredenter into various derivative instruments. These instrumentsOur oil, natural gas and NGL derivative activities, when combined with our sales of oil, natural gas 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 812 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.As of September 30, 2017, ourFor the combined 2021 Successor and Predecessor Periods, oil, natural gas, and NGL revenue, excluding any effect of our derivative instruments, consisted of the following types of instruments:
Swaps: Chesapeake receives a fixed pricewere $1,294 million, $1,547 million and pays a floating market price to the counterparty for the hedged commodity. In exchange for higher fixed prices$172 million, respectively. Based on certain of our swap trades, we may sell call options and call swaptions.
Options: Chesapeake sells, and occasionally buys, call options in exchange for a premium. At the time of settlement, if the market price exceeds the fixed price of the call option, Chesapeake pays the counterparty the excess on sold call options, and Chesapeake receives the excess on bought call options. If the market price settles below the fixed price of the call option, no payment is due from either party.
Call Swaptions: Chesapeake sells call swaptions to counterparties that allow the counterparty, on a specific date, to extend an existing fixed-price swap for a certain period of time
Collars: These instruments contain a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, Chesapeake receives the fixed price and pays the market price. If the market price is between the put and the call strike prices, no payments are due from either party. Three-way collars include the sale by Chesapeake of an additional put option in exchange for a more favorable strike price on the call option. This eliminates the counterparty’s downside exposure below the second put option strike price.
Basis Protection Swaps: These instruments are arrangements that guarantee a fixed price differential to NYMEX from a specified delivery point. Chesapeake receives the fixed price differential and pays the floating market price differential to the counterparty for the hedged commodity.
As of September 30, 2017, we had the following openproduction, oil, natural gas, and NGL derivative instruments:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Weighted Average Price | | Fair Value |
| | | Volume | | Fixed | | Call | | Put | | Differential | | Asset
(Liability) |
| | | (mmbbl) | | ($ 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 pricerevenue for the 2021 Successor and Predecessor Periods would have increased or decreased by approximately $129 million, $154 million, and $18 million, respectively, for each 10% increase or decrease in prices. As 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 $61 million of net derivative losses related to settled contracts for future production periods that will be recorded within oil, natural gas and NGL sales as realized gains (losses) on derivatives once they are transferred from either accumulated other comprehensive income or unrealized gains (losses) on derivatives in2021, the month of related production, based on the terms specified in the original contract as noted below.
|
| | | | |
| | | September 30,
2017 |
| | | ($ in millions) |
| Short-term | | $ | 2 |
|
| Long-term | | (63 | ) |
| Total | | $ | (61 | ) |
The table below reconciles the changes in fair valuevalues of our oil and natural gas derivatives duringwere net liabilities of $467 million and $1,143 million, respectively. A 10% increase or decrease in forward oil prices would decrease or increase the Current Period. Ofvaluation of oil derivatives by approximately $124 million. A 10% increase in forward natural gas prices would decrease the $9 million fair value asset asvaluation of September 30, 2017, a $20 million asset relatesnatural gas derivatives by approximately $259 million. A 10% decrease in forward natural gas prices would increase the valuation of natural gas derivatives by approximately $258 million. See Note 12 of the 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 |
|
Interest Rate DerivativesRisk
The table below presents principal cash flowsOur exposure to interest rate changes relates primarily to borrowings under our Exit Credit Facility for the 2021 Successor Period and related weighted average interest rates by expected maturity dates, usingpre-petition revolving credit facility and DIP Facility for the earliest demand repurchase date2020 and 2021 Predecessor Periods. Interest is payable on borrowings under the Exit Credit Facility, pre-petition revolving credit facility and DIP Facility based on floating rates. See Note 5 for contingent convertible senior notes.additional information. As of September 30, 2017,2021, we had total debt of $9.775 billion, including $7.250 billion of fixed rate debt atno outstanding borrowings under our Exit Credit Facility - Tranche A Loans and $221 million under our Exit Credit Facility - Tranche B Loans. A 1.0% increase in interest rates averaging 6.87% and $2.525 billionbased on the variable borrowings as of floating rate debt atSeptember 30, 2021 would result in an increase in our interest rateexpense of 6.47%.approximately $2 million per year. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Years of Maturity | | |
| | 2017 | | 2018 | | 2019 | | 2020 | | 2021 | | Thereafter | | Total |
| | ($ 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 investments and the interest rate we pay on borrowings under our revolving credit facility, term loan and our 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 maturity of the notes, the counterparties paid us €246 million and 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 values of the cross currency swaps were recorded on the condensed consolidated balance sheet as a liability of $73 million as of December 31, 2016.
| |
| 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 September 30, 2021 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.effective.
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.
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
Chapter 11 Proceedings
Commencement of the Chapter 11 Cases automatically stayed the proceedings and actions against us that are described below, in addition to actions seeking to collect pre-petition indebtedness or to exercise control over the property of the Company’s bankruptcy estates. 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. See Note 2 of the notes to our condensed consolidated financial statements included in Item 1 of Part I of this report for additional information. Litigation and Regulatory Proceedings
The Company isWe 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 46 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.Regulatory and Related Proceedings. The Company has received DOJ, U.S. Postal Service and state subpoenas seeking information 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 lease 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 We are involved in various other lawsuits and disputes incidental to itsour 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 The majority of these prepetition legal proceedings, including the matters below, have been named in various lawsuits alleging royalty underpayment. The suits against us allege, among other things, that we used below-market prices, made improper deductions, used improper measurement techniques and/settled during the Chapter 11 Cases or entered into arrangements with affiliates that resulted in underpayment of royaltieswill be resolved in connection with the production and saleclaims reconciliation process before the Bankruptcy Court. Any allowed claim related to such prepetition litigation will be treated in accordance with the Plan.
Environmental Contingencies
The nature of natural gas and NGL. Plaintiffs have varying royalty provisions in their respective leases,the oil and gas law variesbusiness carries with it certain environmental risks for us and our 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 addressing the potential liability. Depending on the extent of an identified environmental concern, we may, among other things, exclude a property from statethe transaction, require the seller to state, and royalty owners and producers differremediate the property to our satisfaction in their interpretationan acquisition or agree to assume liability for the remediation 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. 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.
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.property.
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 namedwere recently dismissed as a defendant in a number of putative class actions and one mass tort actionfrom numerous lawsuits in Oklahoma alleging that we and several other companies have engaged in activities that have caused earthquakes. These actions seek, among other things,The lawsuits sought compensation for injury to real and personal property, diminution of property value, economic losses due to business interruption, interference with the use and enjoyment of property, annoyance and inconvenience, personal injury and emotional distress. In addition, they sought the reimbursement of insurance premiums and the award of punitive damages.damages, attorneys’ fees, costs, expenses and interest. Any allowed claim related to such prepetition litigation will be treated in accordance with the Plan.
Other Matters
Based on management’s current assessment, we are of the 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.
Our business has many risks. Factors that could materially adversely affect our business, financial condition, operating results or liquidity and the trading price of our common stock preferred stock or senior notes are described under “Risk Factors” in Item 1A of our 20162020 Form 10-K and the additional risk factors provided below, which supplement the risk factors included in our 2020 Form 10-K. This information should be considered carefully, together with other information in this report and other reports and materials we file with the SEC.
Risks Relating to the Vine Acquisition
The synergies attributable to the Vine Acquisition may vary from expectations.
We may fail to realize the anticipated benefits and synergies expected from the Vine Acquisition, which could adversely affect our business, financial condition and operating results. The success of the Vine Acquisition will depend, in significant part, on our ability to successfully integrate the acquired business, grow the revenue of the combined company and realize the anticipated strategic benefits and synergies from the combination, such as operational and financial scale, and increased free cash flow. However, achieving these goals requires, among other things, realization of the targeted cost synergies expected from the merger. The growth and the anticipated benefits of the transactions may not be realized fully or at all, or may take longer to realize than expected. Actual operating, technological, strategic and revenue opportunities, if achieved at all, may be less significant than expected or may take longer to achieve than anticipated. If we are not able to achieve these objectives and realize the anticipated benefits and synergies expected from the Vine Acquisition within the anticipated timing or at all, our business, financial condition and operating results may be adversely affected.
We and Vine will be subject to business uncertainties for a period of time after the closing of the Vine Acquisition, which could adversely affect the combined company after the Vine Acquisition.
Uncertainty about the effect of the merger on employees, industry contacts and business partners may have an adverse effect on the combined company. These uncertainties may impair the combined company’s ability to attract, retain and motivate key personnel for a period of time after the closing of the Vine Acquisitionand could cause industry contacts, business partners and others that deal with the combined company to seek to change their existing business relationships with the combined company.
Uncertainties associated with the Vine Acquisition may cause a loss of management personnel and other key employees, which could adversely affect the future business and operations of the combined company.
The Company and Vine are dependent on the experience and industry knowledge of their officers and other key employees to execute their business plans. The combined company’s success after the Vine Acquisition will depend in part upon the ability of the Company and Vine to retain key management personnel and other key employees. Current and prospective employees of the Company and Vine may experience uncertainty about their roles within the combined company following the Vine Acquisition, which may have an adverse effect on the ability of the Company to attract or retain key management and other key personnel. Accordingly, no assurance can be given that the combined company will achieve the same success attracting or retaining key management personnel and other key employees as the Company may have independently achieved prior to the Vine Acquisition.
We have incurred and will continue to incur significant transaction and merger-related costs in connection with the Vine Acquisition, which may be in excess of our expectations.
We have incurred and expect to continue to incur a number of non-recurring costs associated with negotiating and completing the Vine Acquisition, combining the operations of the two companies and achieving desired synergies. These fees and costs have been, and will continue to be, substantial. The substantial majority of non-recurring expenses will consist of transaction costs related to the Vine Acquisition and include, among others, employee retention costs, fees paid to financial, legal and accounting advisors, severance and benefit costs and filing fees.
We will also incur transaction fees and costs related to the integration of the companies, which may be substantial. Moreover, we may incur additional unanticipated expenses in connection with the Vine Acquisition and the integration, including costs associated with any stockholder litigation related to the Vine Acquisition. Although we expect that the elimination of duplicative costs as well as the realization of other efficiencies related to the
integration of the businesses should offset integration-related costs over time, this net benefit may not be achieved in the near term, or at all.
The costs described above, as well as other unanticipated costs and expenses, could have a material adverse effect on our financial condition and operating results.
Completion of the Vine Acquisition may have triggered change in control or other provisions in certain agreements to which Vine or its subsidiaries is a party.
The completion of the Vine Acquisition may trigger change in control or other provisions in certain agreements to which Vine or its subsidiaries is a party. If we are unable to negotiate waivers of those provisions, the counterparties may exercise their rights and remedies under such agreements, potentially terminating the agreement or seeking monetary damages. Additionally, even if we are able to negotiate waivers, the counterparties may require a fee for such waivers or seek to renegotiate the agreements on terms less favorable to the combined company.
We havesubstantial indebtedness after giving effect to the Vine Acquisition, which may limit our financial flexibility and adversely affect our financial results.
Under the merger agreement, Vine’s outstanding senior notes remained outstanding, and following certain internal reorganization transactions, we became the successor obligor of the senior notes. As of September 30, 2021, the aggregate principal amount of such outstanding senior notes was approximately $950 million. As of September 30, 2021, we had total long-term debt of approximately $1.3 billion, consisting primarily of the amounts outstanding under our credit facility and our senior unsecured notes.
The combined company’s pro forma indebtedness as of September 30, 2021, assuming consummation of the Vine Acquisition had occurred on such date and Vine’s senior notes remained outstanding, would have been approximately $2.2 billion, representing an increase in comparison to our recent, historical indebtedness. This increase in our indebtedness could have adverse effects on our financial condition and results of operations, including:
•increasing the difficulty of us to satisfy our debt obligations, including any repurchase obligations
that may arise thereunder;
•diverting a portion of our cash flows to service our indebtedness, which could reduce the funds
available for operations and other purposes;
•increasing our vulnerability to general adverse economic and industry conditions;
•placing us at a competitive disadvantage compared to our competitors that are less leveraged and,
therefore, may be able to take advantage of opportunities that we would be unable to pursue due to
our indebtedness;
•limiting our ability to access the capital markets to raise capital on favorable terms;
•impairing our ability to obtain additional financing in the future for working capital, capital
expenditures, acquisitions, general corporate or other purposes; and
•increasing our vulnerability to interest rate increases, as our borrowings under our revolving credit
facility are at variable interest rates.
We believe that the combined company will have flexibility to repay, refinance, repurchase, redeem, exchange or otherwise terminate large portions of its outstanding debt obligations. However, there can be no guarantee that we will be able to execute such refinancings on favorable terms, or at all, and a high level of indebtedness increases the risk that we may default on our debt obligations, including from the debt obligations assumed from Vine. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. Our future performance depends on many factors independent of the Vine Acquisition, some of which are beyond our control, such as general economic conditions and oil and natural gas prices. We may not be able to generate sufficient cash flows to pay the interest on our debt, and future working capital, borrowings or equity financing may not be available to pay or refinance such debt.
Lawsuits have been filed and may be filed against the Company, Vine and their respective affiliates in connection with the Vine Acquisition. An adverse ruling in any such lawsuit could result in substantial costs to the Company and Vine.
Securities class action lawsuits and derivative lawsuits are often brought against public companies that have entered into acquisition, merger or other business combination agreements like the merger agreement. Even if any of the lawsuits which have been filed and may be filed are without merit, defending against these claims can result in substantial costs and divert management time and resources. An adverse judgment could result in monetary damages, which could have a negative impact on our liquidity and financial condition.
Additionally, there can be no assurance that any of the defendants in any potential future lawsuits will be successful in the outcome of such lawsuits. The defense or settlement of any lawsuit or claim that remains unresolved at the time the merger is completed may adversely affect our business, financial condition, results of operations and cash flows.
Our integration of Vine into the Company may not be as successful as anticipated, and we may not achieve the intended benefits or do so within the intended timeframe.
The Vine Acquisition involves numerous operational, strategic, financial, accounting, legal, tax and other risks, potential liabilities associated with the acquired business, and uncertainties related to design, operation and integration of Vine’s internal control over financial reporting. Difficulties in integrating Vine into the Company may result in Vine performing differently than expected, operational challenges, or the failure to realize anticipated expense-related efficiencies. Potential difficulties that may be encountered in the integration process include, among others:
•the inability to successfully integrate the business of Vine into the Company in a manner that
permits the Company to achieve the full revenue and cost savings anticipated from the Vine
Acquisition;
•complexities associated with managing the larger, more complex integrated business;
•not realizing anticipated operating synergies;
•integrating personnel from the two companies and the loss of key employees;
•potential unknown liabilities and unforeseen expenses, delays or regulatory conditions associated
with the Vine Acquisition;
•integrating relationships with industry contacts and business partners;
•performance shortfalls as a result of the diversion of management’s attention caused by completing
the Vine Acquisition and the integration process; and
•the disruption of, or the loss of momentum in, ongoing business or inconsistencies in standards,
controls, procedures and policies.
Additionally, the success of the Vine Acquisition will depend, in part, on our ability to realize the anticipated benefits and cost savings from combining the two businesses, including operational and other synergies that we believe the combined company will achieve. The anticipated benefits and cost savings of the Vine Acquisition may not be realized fully or at all, may take longer to realize than expected or could have other adverse effects that we do not currently foresee.
Our results may suffer if we do not effectively manage our expanded operations following the Vine Acquisition.
The success of the Vine Acquisition will depend, in part, on our ability to realize the anticipated benefits and cost savings from combining the two businesses, including the need to integrate the operations and business of Vine into our existing business in an efficient and timely manner, to combine systems and management controls and to integrate relationships with customers, vendors, industry contacts and business partners.
The anticipated benefits and cost savings of the Vine Acquisition may not be realized fully or at all, may take longer to realize than expected or could have other adverse effects that we do not currently foresee. Some of the assumptions that we have made, such as the achievement of operating synergies, may not be realized. There could also be unknown liabilities and unforeseen expenses associated with the Vine Acquisition that were not discovered in the due diligence review conducted by each company prior to entering into the transaction.
The market price of our common stock may be affected by factors different from those that historically have affected the price of our common stock.
Our business differs from that of Vine in certain respects, and, accordingly, the financial position or results of operations and/or cash flows of the combined company, as well as the market price of our common stock, may be affected by factors different from those currently affecting our financial position or results of operations and/or cash flows as an independent standalone company.
As a result of the Vine Acquisition, we have incorporated Vine’s hedging activities into our business, and we may be exposed to additional commodity price risks arising from such hedges.
To mitigate its exposure to changes in commodity prices, Vine hedges natural gas prices from time to time, primarily through the use of certain derivative instruments. As a result of the merger, we assumed Vine’s existing derivative instruments. Actual natural gas prices may differ from our expectations and, as a result, such derivative instruments may have a negative impact on our business, financial condition and operating results.
The combined company may not be able to retain customers or suppliers, and customers or suppliers may seek to modify contractual obligations with the combined company, either of which could have an adverse effect on the combined company’s business and operations. Third parties may terminate or alter existing contracts or relationships with the Company or Vine as a result of the Vine Acquisition.
As a result of the Vine Acquisition, the combined company may experience impacts on relationships with customers and suppliers that may harm the combined company’s business and results of operations. Certain customers or suppliers may seek to terminate or modify contractual obligations following the Vine Acquisition whether or not contractual rights are triggered as a result of the Vine Acquisition. There can be no guarantee that customers and suppliers will remain with or continue to have a relationship with the combined company or do so on the same or similar contractual terms following the merger. If any customers or suppliers seek to terminate or modify contractual obligations or discontinue their relationships with the combined company, then the combined company’s business and results of operations may be harmed. If the combined company’s suppliers were to seek to terminate or modify an arrangement with the combined company, then the combined company may be unable to procure necessary supplies or services from other suppliers in a timely and efficient manner and on acceptable terms, or at all.
Vine also has contracts with vendors, landlords, licensors and other business partners that may require Vine to obtain consents from these other parties in connection with the Vine Acquisition. If these consents cannot be obtained, the combined company may suffer a loss of potential future revenue, incur costs and/or lose rights that may be material to the business of the combined company. Any such disruptions could limit the combined company’s ability to achieve the anticipated benefits of the Vine Acquisition.
We are subject to risks related to health epidemics and pandemics, including the ongoing COVID-19 pandemic, and it is difficult to predict what effect, if any, this might have on the combined company after the Vine Acquisition.
We face various risks related to public health issues, including epidemics, pandemics and other outbreaks, including the ongoing COVID-19 pandemic. The actual and potential effects of COVID-19 include, but are not limited to, its impact on general economic conditions, trade and financing markets, changes in customer behavior and continuity in business operations, all of which create significant uncertainty. In addition, the pandemic has resulted in governmental authorities implementing significant and varied measures to contain the spread of COVID-19, including travel bans and restrictions, quarantines, shelter in place and stay at home orders and business shutdowns. Governmental authorities may enact additional restrictions, or tighten existing measures if COVID-19 continues to spread. These measures, as well as the COVID-19 pandemic broadly, may have a negative effect on the combined company after the Vine Acquisition, which effect will be difficult to predict.
| | | | | |
ITEM 2. 2. | Unregistered Sales of Equity Securities and Use of Proceeds |
The following table presents information aboutThere were no repurchases of our common stock during the quarter ended September 30, 2017:2021.
|
| | | | | | | | | | | | | | |
| Period | | Total Number of Shares Purchased(a) | | Average Price Paid Per
Share(a) | | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | | Maximum Approximate Dollar Value of Shares That May Yet Be Purchased Under the Plans or Programs(b) |
| | | | | | | | | ($ in millions) |
| July 1, 2017 through July 31, 2017 | | 5,173 |
| | $ | 4.82 |
| | — |
| | $ | 1,000 |
|
| August 1, 2017 through August 31, 2017 | | — |
| | $ | — |
| | — |
| | $ | 1,000 |
|
| September 1, 2017 through September 30, 2017 | | — |
| | $ | — |
| | — |
| | $ | 1,000 |
|
| Total | | 5,173 |
| | $ | 4.82 |
| | — |
| | |
| | | | | |
(a)ITEM 3. | Includes shares of common stock purchased on behalf of Chesapeake’s deferred compensation plan related to participant deferrals and Company matching contributions.Defaults Upon Senior Securities |
