CALIFORNIA RESOURCES CORPORATION The following discussion should be read in conjunction with other sections of this report, including but not limited to, Part I, Item 1 and 2 - Business and Properties and Part II, Item 8 - Financial Statements and Supplementary Data.
Basis of Presentation
All financial information presented consists of our consolidated results of operations, financial position and cash flows unless otherwise indicated. We have eliminated all significant intercompany transactions and accounts. We account for our share of oil and natural gas production activities, in which we have a direct working interest, by reporting our proportionate share of assets, liabilities, revenues, costs and cash flows within the relevant lines on our balance sheets and statements of operations and cash flows. We emerged from Chapter 11 bankruptcy proceedings onOctober 27, 2020 as further described below. We adopted and applied the relevant guidance with respect to the accounting and financial reporting for entities that have emerged from bankruptcy proceedings. Under fresh start accounting, the reorganized entity is considered a new reporting entity. We elected to apply fresh start accounting effectiveOctober 31, 2020 , an accounting convenience date, and the$2.5 billion reorganization value of the emerging entity was assigned to individual assets and liabilities based on their estimated relative fair values. As such, fresh start accounting was reflected on our consolidated balance sheet as ofOctober 31, 2020 . As a result of the application of fresh start accounting and the effects of the implementation of the Plan, the financial statements afterOctober 31, 2020 may not be comparable to the financial statements prior to that date. References to "Predecessor" refer to the Company for periods ended on or prior toOctober 31, 2020 and references to "Successor" refer to the Company for periods subsequent toOctober 31, 2020 . Certain operating results and key operating performance measures, for example production, average realized prices, revenues, operating expense, taxes other than on income and general and administrative expenses, were not significantly impacted by the reorganization. Accordingly, we believe that discussing the combined results of operations and cash flows of the Predecessor and Successor companies is useful when analyzing financial results and performance measures. For items that are not comparable, for example depreciation, depletion and amortization, interest expense, impairment and net income (loss), we have included additional analysis. Emergence from Bankruptcy Proceedings and Subsequent Refinancing OnJuly 15, 2020 , we filed voluntary petitions for relief under Chapter 11 of Title 11 of the Bankruptcy Code in theBankruptcy Court . The Chapter 11 Cases were jointly administered under the caption In reCalifornia Resources Corporation , et al., Case No. 20-33568 (DRJ). We filed with theBankruptcy Court , onJuly 24, 2020 , the Debtors' Joint Plan of Reorganization under Chapter 11 of the Bankruptcy Code and, onOctober 8, 2020 , the Amended Debtors' Joint Plan of Reorganization Under Chapter 11 of the Bankruptcy Code. OnOctober 13, 2020 , theBankruptcy Court confirmed the Plan, which was conditioned on certain items such as obtaining exit financing. The conditions to effectiveness of the Plan were satisfied and we emerged from Chapter 11 onOctober 27, 2020 (Effective Date). We emerged from bankruptcy on the Effective Date with a new board of directors, new equity owners and a significantly improved financial position. Under the plan of reorganization approved by theBankruptcy Court (the Plan), all of our outstanding pre-emergence indebtedness under our credit facilities and senior notes was cancelled. At emergence, we entered into a new revolving credit facility with a$1.2 billion borrowing base and$540 million of lender commitments (Revolving Credit Facility). Our post-emergence capital structure also included a$200 million second lien term loan (Second Lien Term Loan) and$300 million of secured notes due 2027 issued by our wholly-owned subsidiary in connection with our acquisition of our partner's interest in ourElk Hills power joint venture (EHP Notes).
On
47
--------------------------------------------------------------------------------For information on the transactions which occurred pursuant to the Plan upon our emergence from Chapter 11 and fresh start accounting, see Part II, Item 8 - Financial Statements, Note 2 Chapter 11 Proceedings and Part II, Item 8 - Financial Statements, Note 3 Fresh Start Accounting.
Response to COVID-19 Pandemic and Industry Downturn
We have taken several steps and continue to actively work to mitigate the effects of the COVID-19 pandemic and the industry downturn on our operations, financial condition and liquidity.
In response to the rapid fall in commodity prices inMarch 2020 , we ceased all field development and growth projects and shut in certain wells. We also reduced our 2020 capital budget to a level that preserves the mechanical integrity of our facilities and allows us to operate them in a safe and environmentally responsible manner. As a result, our production declined during 2020. Our 2021 capital investment program targets development of shallow oil projects in core fields and with this program, we expect total production (on a BOE basis) will decline moderately throughout 2021; however, we believe oil production will likely remain mostly flat from entry to exit. We also monetized all of our crude oil hedges inMarch 2020 , except for certain hedges held by our joint venture withBenefit Street Partners (BSP JV), for approximately$63 million to preserve our liquidity. We began shutting in high cost, negative margin wells inMarch 2020 to reduce operating costs and enhance cash flow which curtailed average net production volumes by approximately 3 MBoe/d in 2020. We began returning wells to production inDecember 2020 . As part of our operational efficiency measures, we evaluated our diverse portfolio and our various production mechanisms with a focus on wells with higher operating costs. Our teams utilized our extensive automation controls, monitored weekly well margins, and made temporary adjustments to our producing wells to ensure our operations aligned with the price environment. As a result of these actions, as well as further cost rationalization and streamlining efforts coupled with lower activity levels, our average operating expense run rate in the second half of 2020 was approximately$50 million per month compared to the first quarter of 2020 average of$65 million per month. We have also implemented various measures to protect the health of our workforce and to support the prevention of COVID-19 at our plants, rigs, fields and administrative offices. These initiatives were implemented in accordance with the orders, regulations and guidance of federal, state and local authorities to mitigate the risks of the disease and included restricting non-essential travel and temporarily closing our administrative offices during periods of higher incidence of community spread from mid-March untilmid-June 2020 and resuming again inmid-November 2020 by implementing remote work for our management team and substantially all of our office personnel, with limited return to the office in accordance with applicable protocols and restrictions on occupancy for those employees for whom remote work was not feasible. In addition, inApril 2020 , we implemented reduced work hours for nearly all of our office employees and reduced salaries for our management team, in each case on a temporary basis that ended inMay 2020 . InAugust 2020 , we implemented organizational and operational efficiencies that resulted in a reduction of our headcount to approximately 1,100 employees. These actions were made in an effort to preserve liquidity after the deterioration of commodity prices following the outbreak of COVID-19. Our operational employees and contractors, and certain support personnel, have been classified as an essential critical infrastructure workforce by government authorities. Accordingly, these essential personnel have been authorized to continue to work in their plant, rig, field and office locations under ourCOVID-19 Health and Safety Plan, which includes, among other things, protocols for employee training, health self-assessment screening by workers and visitors entering our locations, reporting of illness, notification of workers and contact tracing associated with positive COVID-19 cases, self-quarantine or isolation, hygiene, wearing facial coverings, applying social distancing to minimize close contact between workers, cleaning or disinfecting workspaces and protection of emergency response personnel. We have not experienced any operational slowdowns due to COVID-19 among our workforce. 48 --------------------------------------------------------------------------------
Production and Prices
Prices for oil and gas products in 2020 have been strongly influenced by the COVID-19 pandemic and by the actions of foreign producers. The COVID-19 pandemic caused an unprecedented demand collapse due to global shelter-in-place orders, travel restrictions and general economic uncertainty, which negatively impacted crude oil prices. In response, members of theOPEC andRussia agreed to carry out record oil production cuts inApril 2020 to be followed by gradual incremental increases in multiple steps. In addition,U.S. oil and gas companies reduced their oil production by approximately 3 MMBbl/d in 2020 from peak production levels addressing the oversupplied market situation at the time of crisis. Due to these developing market dynamics, which include a successful OPEC+ agreement, a disciplined return of production in theU.S. and a broader, gradual return of demand, oil prices rebounded above$50 per barrel by the end of 2020. Brent oil price traded around$60 per barrel inFebruary 2021 . Reduced demand initially caused shortages in available storage facilities globally and required many oil and gas producers to shut-in wells or curtail production. InApril 2020 , oil prices declined precipitously, temporarily reaching negative values for spot West Texas Intermediate (WTI) crude. FromMay 2020 throughAugust 2020 , oil prices began to recover as inventory levels stabilized and an easing of shelter-in-place restrictions created partial demand recovery. Prices declined again slightly inSeptember 2020 as demand for oil dropped due to an increase in COVID-19 cases around the world. Oil demand and underlying commodity prices remain fragile as potential resurgence in new COVID-19 cases could force government authorities to re-impose mobility restrictions further impacting oil demand. The current futures forward curve for Brent crude indicates that prices may maintain current levels in the near term. We continue to closely monitor the impact of COVID-19, which negatively impacted our business and results of operations beginning in the first quarter of 2020. The extent to which our 2021 operating results are impacted by the pandemic will depend largely on future developments, which are highly uncertain and cannot be accurately predicted, including the delivery of vaccinations, a resurgence of the pandemic or mutation of the virus and actions taken to contain it or actions taken by government authorities or other producers in response to commodity price movements, among other things. See Part I, Item 1A - Risk Factors, for further discussion regarding the impact of the pandemic and declines in commodity prices. 49 -------------------------------------------------------------------------------- The following table sets forth our average net production volumes of oil, NGLs and natural gas per day for the years endedDecember 31, 2020 , 2019 and 2018: Successor Predecessor Combined Predecessor November 1, 2020 - January 1, 2020 - December 31, 2020 October 31, 2020 2020 2019 2018 Oil (MBbl/d) San Joaquin Basin 38 42 42 52 53 Los Angeles Basin 23 25 24 24 25 Ventura Basin 2 3 3 4 4 Total 63 70 69 80 82 NGLs (MBbl/d) San Joaquin Basin 12 13 13 15 15 Ventura Basin - - - - 1 Total 12 13 13 15 16 Natural gas (MMcf/d) San Joaquin Basin 138 147 145 162 165 Los Angeles Basin 1 2 2 2 1 Ventura Basin 3 4 4 5 7 Sacramento Basin 23 21 21 28 29 Total 165 174 172 197 202 Total Production (MBoe/d)(a)(b) 103 112 111 128
132
Note: MBbl/d refers to thousands of barrels per day; MMcf/d refers to millions of cubic feet per day; MBoe/d refers to thousands of barrels of oil equivalent per day. (a)We temporarily shut-in production of 3 MBoe/d in 2020, which negatively impacted our production compared to 2019. Additionally, our divestiture of a 50% working interest in certain zones within ourLost Hills field resulted in a decrease of approximately 2 MBoe/d beginning in the second quarter of 2019. Our PSC-type contract positively impacted our oil production in 2020 by approximately 3 MBoe/d compared to 2019. PSC-type contracts had no impact on our oil production in 2019 compared to 2018. (b)Natural gas volumes have been converted to Boe based on the equivalence of energy content of six thousand cubic feet of natural gas to one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence. 50 -------------------------------------------------------------------------------- Our operating results and those of the oil and natural gas industry as a whole are heavily influenced by commodity prices. Oil and natural gas prices and differentials may fluctuate significantly as a result of numerous market-related variables. These and other factors make it impossible to predict realized prices reliably. The following tables set forth average benchmark prices, average realized prices and price realizations as a percentage of average benchmark prices for our products for the periods indicated below: Successor Predecessor November 1, 2020 - December 31, 2020 January 1, 2020 - October 31, 2020 Price Realization Price Realization Oil ($ per Bbl) Brent$ 47.10 $ 42.43 Realized price without hedge$ 45.65 97% $ 41.21 97% Settled hedges (0.28) 1.98 Realized price with hedge$ 45.37 96% $ 43.19 102% WTI$ 44.21 $ 38.44 Realized price without hedge$ 45.65 103% $ 41.21 107% Realized price with hedge$ 45.37 103% $ 43.19 112% NGLs ($ per Bbl) Realized price(a)$ 38.00 81% $ 25.70 61% Realized price(b)$ 38.00 86% $ 25.70 67% Natural gas NYMEX ($/MMBTU)$ 2.86 $ 1.95 Realized price without hedge ($/Mcf)$ 3.21 112% $ 2.11 108% Settled hedges (0.07) 0.06 Realized price with hedge ($/Mcf)$ 3.14 110% $ 2.17 111%
(a) Realization is calculated as a percentage of Brent. (b) Realization is calculated as a percentage of WTI.
51
--------------------------------------------------------------------------------
Combined Predecessor
January 1, 2020 - December 31, 2020 2019 2018
Price Realization Price Realization Price Realization
Oil ($ per Bbl)
Brent $ 43.21 $ 64.18 $ 71.53
Realized price without hedge $ 41.89 97% $ 64.83 101% $ 70.11 98%
Settled hedges 1.64 3.82 (7.51)
Realized price with hedge $ 43.53 101% $ 68.65 107% $ 62.60 88%
WTI $ 39.40 $ 57.03 $ 64.77
Realized price without hedge $ 41.89 106% $ 64.83 114% $ 70.11 108%
Realized price with hedge $ 43.53 110% $ 68.65 120% $ 62.60 97%
NGLs ($ per Bbl)
Realized price(a) $ 27.63 64% $ 31.71 49% $ 43.67 61%
Realized price(b) $ 27.63 70% $ 31.71 56% $ 43.67 67%
Natural gas
NYMEX ($/MMBTU) $ 2.10 $ 2.67 $ 2.97
Realized price without hedge
($/Mcf) $ 2.28 109% $ 2.87 107% $ 3.00 101%
Settled hedges 0.04 (0.01) (0.02)
Realized price with hedge
($/Mcf) $ 2.32 110% $ 2.86 107% $ 2.98 100%
(a) Realization is calculated as a percentage of Brent. (b) Realization is calculated as a percentage of WTI. Joint Ventures
We have a number of joint ventures that have allowed us to accelerate the development of our assets, which provided us with operational and financial flexibility as well as near-term production benefits.
Alpine JV
InJuly 2019 , we entered into a development joint venture withAlpine Energy Capital, LLC (Alpine) to fund the drilling of certain wells within theElk Hills field (Alpine JV). Alpine committed to invest an initial$320 million in theElk Hills field of which$226 million has been invested to date. Our consolidated financial statements reflect only our working interest share in the productive wells. OnMarch 27, 2020 , Alpine elected to suspend its funding obligations pursuant to a contractual right that was triggered when the average NYMEX 12-month forward strip price for Brent crude oil fell below$45 per barrel over a 30-trading day period. The suspension may be lifted by mutual consent. Funding for the initial development phase had not re-started. In connection with the Alpine JV, we issued a warrant to purchase up to 1.25 million shares of our Predecessor common stock at an exercise price of$40 per share. On the Effective Date, this warrant was cancelled, pursuant to the Plan. 52 --------------------------------------------------------------------------------
Royale JV
InOctober 2018 , we entered into a three-year development joint venture for a 30-well program with Royale Energy, Inc. (Royale) where Royale committed approximately$23 million for natural gas development inSacramento Valley , of which$8 million has been funded to date. We committed to investing approximately$13 million , of which$4 million has been funded to date. InJune 2020 , we entered into an amendment with Royale which postponed the start dates of the second- and third-year drilling programs by one year. Our consolidated results reflect our 40% working interest share of production from these wells.
MIRA JV
InApril 2017 , we entered into a development joint venture with Macquarie Infrastructure andReal Assets Inc. (MIRA) to develop certain of our oil and natural gas properties in theSan Joaquin basin in exchange for a 90% working interest in the related properties (MIRA JV). MIRA funded 100% of the drilling and completion costs of agreed-upon wells in the drilling program. Our 10% working interest increases to 75% if MIRA receives cash distributions equal to a predetermined threshold return. The initial phase of the agreed-upon capital program was funded throughDecember 31, 2020 . Our consolidated results reflect only our working interest share in the productive wells.
BSP JV
InFebruary 2017 , we entered into a development joint venture withBenefit Street Partners (BSP) where BSP cumulatively contributed$200 million over a period of approximately two years in exchange for preferred interests in the BSP JV. BSP is entitled to preferential distributions and, if BSP receives cash distributions equal to a predetermined threshold, the preferred interest is automatically redeemed in full with no additional payment. At current prices, we believe BSP's preferred interest could be redeemed within the next twelve months. The funds contributed by BSP were used to develop certain of our oil and natural gas properties. The BSP JV holds net profits interests in existing and future cash flow from certain of our properties and the proceeds from the net profits interests are used by the BSP JV to (1) pay quarterly minimum distributions to BSP, (2) make additional distributions to BSP until the predetermined threshold is achieved, and (3) pay for development costs within the project area, upon mutual agreement between members. Our consolidated results reflect the full operations of the BSP JV, with BSP's share of net income reported in net income attributable to noncontrolling interests on our consolidated statements of operations.
Midstream JV
Ares JV
InFebruary 2018 , our wholly-owned subsidiaryCalifornia Resources Elk Hills, LLC (CREH) entered into a joint venture with ECR, a portfolio company of Ares, with respect to the Elk Hills power plant (a 550-megawatt natural gas fired power plant) and a 200 MMcf/day cryogenic gas processing plant. These assets were held by the joint venture entity,Elk Hills Power, LLC (Elk Hills Power), and each of CREH and ECR held an equity interest in this entity. OnJuly 15, 2020 , we entered into the Settlement Agreement with ECR and Ares which, among other things, granted us the right to acquire all of the equity interests of Elk Hills Power owned by ECR in exchange for (i) EHP Notes in the aggregate principal amount of$300 million , (ii) approximately 20.8% (subject to dilution) of common stock issued upon our emergence from bankruptcy, and (iii) approximately$2.0 million in cash. The Settlement Agreement also provided that all joint venture arrangements would be terminated upon exercise of this right. We were deemed to have exercised the conversion right onOctober 27, 2020 . Upon our emergence from bankruptcy, Elk Hills Power became our indirect wholly-owned subsidiary, and Ares and its affiliates ceased to have any direct or indirect interest inElk Hills Power . In connection with this conversion, Elk Hills Power's limited liability company agreement was amended and restated. 53 -------------------------------------------------------------------------------- We determined that the amended terms were substantively different such that the existing equity interests held by ECR were treated as redeemed in exchange for new member interests issued at fair value in the third quarter of 2020. The estimated fair value of the new member interests was lower than the carrying value of the existing member interests by$138 million . In accordance with accounting rules, the gain from the modification of the equity instrument was recorded to additional paid-in capital on our consolidated Predecessor balance sheet. However, as required by GAAP, the gain on the modification was included in our earnings per share calculations. See Part II, Item 8 - Financial Statements and Supplementary Data, Note 17 Earnings per Share for adjustments to net income (loss) attributable to common stock which includes a modification of noncontrolling interest. Our consolidated statements of operations for the Predecessor reflects the operations of the Ares JV, with ECR's share of net income (loss) reported in net income attributable to noncontrolling interests. ECR's redeemable noncontrolling interests was reported in mezzanine equity due to an embedded optional redemption feature.
For more information on the Ares JV, see Part II, Item 8 - Financial Statements and Supplementary Data, Note 7 Joint Ventures. For more information on the Settlement Agreement, see Part II, Item 8 - Financial Statements and Supplementary Data, Note 2 Chapter 11 Proceedings.
Divestitures and Acquisitions
Divestitures
InMay 2019 , we sold 50% of our working interest and transferred operatorship in certain zones within ourLost Hills field, located in theSan Joaquin basin, for total consideration in excess of$200 million , consisting of approximately$168 million in cash and a carried 200-well development program to be drilled through 2023 with an estimated value of$35 million (Lost Hills divestiture). We received cash proceeds of$164 million after transaction costs and purchase price adjustments, which were used to pay down our 2014 Revolving Credit Facility. The low commodity price environment in 2020 extended the time period of the carry through 2024.
In
Acquisitions InApril 2018 , we acquired fromChevron U.S.A., Inc. (Chevron ) its share of the remaining working, surface and mineral interests in the approximately 47,000-acre Elk Hills unit (the Elk Hills transaction) for approximately$518 million , including$7 million of liabilities assumed relating to asset retirement obligations. We accounted for the Elk Hills transaction as a business combination and allocated$435 million to proved properties,$77 million to other property, plant and equipment and$6 million to materials and supplies. The consideration paid consisted of$460 million in cash and 2.85 million shares of our pre-emergence common stock issued at the close of the transaction (valued at$51 million ). As part of the Elk Hills transaction,Chevron reduced its royalty interest in one of our oil and natural gas properties by half and extended the time frame to invest the remainder of our capital commitment on that property by two years, to the end of 2022. As ofDecember 31, 2020 , our remaining commitment was approximately$12 million . In addition, the parties mutually agreed to release each other from pending claims with respect to the former Elk Hills unit.
In
Additionally, we had several other acquisitions totaling approximately
Seasonality
While certain aspects of our operations are affected by seasonal factors, such
as energy costs, overall, seasonality has not been a material driver of changes
in our earnings during the year.
54
--------------------------------------------------------------------------------Income Taxes
Net (loss) income before income taxes, for all periods presented, was generated solely from domestic operations. We did not record a significant income tax provision (benefit) in any of the periods presented, due to our valuation allowance.
Total income tax provision (benefit) differs from the amounts computed by applying theU.S. federal income tax rate to pre-tax income (loss) as follows: Successor Predecessor November 1, 2020 - January 1, 2020 - Years ended December 31, 2020 October 31, 2020 December 31, 2019 2018 U.S. federal statutory tax rate (21) % 21 % 21 % 21 % State income taxes, net (7) 7 7 6 Exclusion of income attributable to noncontrolling interests, net - (1) (35) (5) Debt restructuring, net - (8) - - Changes in tax attributes, net - 7 (9) (6) Nondeductible compensation, net - - 3 - Change in valuation allowance, net 27 (27) 14 (17) Other, net 1 1 - 1 Effective tax rate - % - % 1 % - % Our effective tax rate is primarily affected by state taxes, income included in our consolidated results which is taxed to noncontrolling interests, the benefit of tax credits, when available. Further, as a result of our emergence from bankruptcy, we wrote-off deferred tax assets because of the limitation on the realizability of our net operating loss and tax carryforwards as described further below. Given our income tax position, any item affecting our effective tax rate is generally offset by an equal change in the valuation allowance. In connection with our emergence from bankruptcy and cancellation of claims, which were included in liabilities subject to compromise as of our emergence date, we generated cancellation of debt income for tax purposes which was excluded from taxable income under rules related to bankruptcy proceedings. In exchange for this exclusion, for federal purposes, we were required to reduce our net operating loss (NOL) and tax credit carryforwards and the tax basis of our assets, primarily property, plant and equipment. The primary driver of the income tax benefit related to the cancellation of our debt is due to the mechanics of attribute reduction for state combined income tax reporting purposes. Our ability to utilize our remaining NOL, tax credit and interest expense carryforwards may be limited since we experienced an "ownership change" in connection with the restructuring process. Absent an applicable exception, if a corporation undergoes an ownership change, the amount of its NOLs and other carryforwards that may be used to reduceU.S. federal and state income tax obligations is subject to an annual limitation. Although an exception to the imposition of an annual limitation applies in Chapter 11 Cases under Section 382(l)(5) of the Internal Revenue Code of 1986, as amended, it is currently not likely if we will apply such section because if we experience a subsequent ownership change within two years of the Effective Date, any remaining net operating losses and certain other tax attributes, including interest expense carryforwards, may be subject to further and more severe limitations. Accordingly, the write-off of the benefit for our remaining NOLs and other carryforwards had the effect of increasing our effective tax rate in the Predecessor period. We are evaluating alternatives available in order to minimize the impact of the change in ownership that does not subject pre-emergence NOLs and other tax attributes to an ownership change. 55 -------------------------------------------------------------------------------- Management assesses the available positive and negative evidence to estimate whether sufficient future taxable income will be generated to permit use of existing deferred tax assets. A significant piece of evidence evaluated is a history of operating losses. Such evidence limits our ability to consider other evidence such as projections for growth. As ofDecember 31, 2020 , we concluded that we could not realize, on a more-likely-than-not basis, any of our deferred tax assets and there is not sufficient evidence to support the reversal of all or any portion of this allowance. Given our recent and anticipated future earnings trends, we do not believe any significant amount of the valuation allowance as ofDecember 31, 2020 will be released within the next 12 months. Changes in assumptions could materially affect the recognized amount of valuation allowance. As ofDecember 31, 2020 , we hadU.S. federal net operating loss carryforwards of approximately$17 million , which begin to expire in 2039. Our carryforward for business interest expense of$855 million does not expire. As ofDecember 31, 2020 , we hadCalifornia net operating loss carryforwards of approximately$2 billion , which begin to expire in 2026, and an insignificant amount of tax credit carryforwards. For additional information on tax-related items, see information set forth in Part II, Item 8 - Financial Statements and Supplementary Data, Note 12 Income Taxes.
Statement of Operations Analysis
Results of Oil and Natural Gas Operations
The following represents key operating data for our oil and natural gas
operations, excluding corporate items, on a per Boe basis for the years ended
Successor Predecessor
November 1, 2020
- December 31, January 1, 2020 -
2020 October 31, 2020 2019 2018
Operating costs(a) $ 18.19 $ 14.95 $ 19.16 $ 18.88
Operating costs, excluding effects of
PSC-type contracts(b) $ 16.86 $ 14.14 $ 17.70 $ 17.47
Field general and administrative
expenses(c) $ 1.12 $ 1.11 $ 1.20 $ 1.01
Field depreciation, depletion and
amortization(d) $ 4.95 $ 8.75 $ 9.40 $ 9.71
Field taxes other than on income(e) $ 0.64 $
3.10
(a)The decrease in operating costs in the Predecessor period in 2020 was primarily due to shut-in wells and lower activity in response to the lower price environment as well as workforce reductions and reduced work hours in the second quarter of 2020. Operating costs on a per barrel basis were higher in the Successor period as a result of moderately lower production volumes and higher workover and maintenance activity levels. (b)As described in Items 1 and 2 - Business and Properties - Operations - Production, Price and Cost History, the reporting of our PSC-type contracts creates a difference between reported operating costs, which are for the full field, and reported volumes, which are only our net share, inflating the per barrel operating costs. These amounts represent our operating costs after adjusting for this difference. (c)Field general and administrative expenses increased in 2019 compared to 2018, primarily due to the Elk Hills transaction that occurred inApril 2018 since certain costs are no longer recovered from our former working interest partner. Our 2019 costs include 12 months without such cost recovery compared to nine months without cost recovery in 2018. (d)Field depreciation, depletion and amortization decreased in the Predecessor period in 2020 from prior years as a result of a lower depletable basis resulting from our asset impairment recorded in the first quarter. Field depreciation, depletion and amortization further declined in the Successor period due to a decrease in our depletable basis as a result of our fresh start fair value adjustments. (e)Field taxes other than on income declined in the Successor period primarily resulting from reduced emissions compared to 2019 due to lower activity levels, including shut-in wells, and better-than-expected market pricing on the purchase of greenhouse gas emission credits. 56 --------------------------------------------------------------------------------
Consolidated Results of Operations
The periods ofNovember 1, 2020 throughDecember 31, 2020 (Successor period) andJanuary 1, 2020 throughOctober 31, 2020 (Predecessor period) are distinct reporting periods as a result of the adoption of fresh start accounting upon emergence from Chapter 11 bankruptcy and are not comparable to prior periods. We have combined these periods in 2020 to provide comparability of information to the years endedDecember 31, 2019 and 2018. While this combined presentation is not presented according to generally accepted accounting principles inthe United States (GAAP) and no comparable GAAP measures are presented, management believes that providing this information is relevant and useful for making comparisons to the prior years. Where the combined amounts are not on a comparable basis to prior years (including depreciation, depletion and amortization and interest and debt expense, net and net loss (income) attributable from noncontrolling interests), our discussion addresses Predecessor and Successor results separately.
The following represents key operating data for consolidated operations for the periods presented (in millions):
Successor Predecessor Combined Predecessor
November 1, Year ended Year ended Year ended
2020 - January 1, 2020 - December 31, December 31, December 31,
December 31, October 31, 2020 2020 2019 2018
2020
Oil and natural gas sales(a) $ 237 $ 1,092 $ 1,329 $ 2,270 $ 2,590
Net derivative (loss) gain from
commodity contracts (141) 91 (50) (59) 1
Trading revenue 38 124 162 286 330
Electricity sales 15 86 101 112 111
Other revenue 3 14 17 25 32
Operating costs (114) (511) (625) (895) (912)
General and administrative
expenses (40) (212) (252) (290) (299)
Depreciation, depletion and
amortization (34) (328) (362) (471) (502)
Asset impairment - (1,736) (1,736) - -
Taxes other than on income (10) (134) (144) (157) (149)
Exploration expense (1) (10) (11) (29) (34)
Trading costs (24) (78) (102) (201) (250)
Electricity cost of sales (10) (53) (63) (68) (61)
Transportation costs (8) (35) (43) (40) (36)
Other expenses, net (17) (89) (106) (54) (52)
Reorganization items, net (3) 4,060 4,057 - -
Interest and debt expense, net (11) (206) (217) (383) (379)
Net gain on early extinguishment
of debt - 5 5 126 57
Gain on asset divestitures - - - - 5
Other non-operating expenses (5) (84) (89) (72) (23)
Income (loss) before income
taxes (125) 1,996 1,871 100 429
Income tax provision - - - (1) -
Net income (loss) (125) 1,996 1,871 99 429
Net loss (income) attributable
to noncontrolling interests $ 2 $ (107) $ (105) $ (127) $ (101)
Net (loss) income attributable
to common stock $ (123) $ 1,889 $ 1,766 $ (28) $ 328
Adjusted net income (loss)(a) $ 28 $ (285) $ (257) $ 70 $ 61
Adjusted EBITDAX(a) $ 83 $ 406 $ 489 $ 1,142 $ 1,117
(a)Adjusted net income (loss) and Adjusted EBITDAX are non-GAAP measures. See
the Non-GAAP Financial Measures section below for a reconciliations to their
nearest GAAP measures.
57
--------------------------------------------------------------------------------
Year Ended
Oil and natural gas sales - Oil and natural gas sales, excluding the impact of settled hedges, were$1,329 million for the combined period ofJanuary 1, 2020 throughDecember 31, 2020 , which is a decrease of 41%, or$941 million , compared to$2,270 million in 2019. The decrease was due to changes in realized prices and production as reflected in the following table: Oil NGLs Natural Gas Total (in millions) Year ended December 31, 2019$ 1,884 $ 179 $ 207 $ 2,270 Changes in realized prices (666) (23) (42) (731) Changes in production (168) (21) (21) (210) Year ended December 31, 2020$ 1,050 $ 135 $ 144 $ 1,329
Note: See Production and Prices for average benchmark and realized prices, realizations and production.
The effect of settled hedges is not included in the table above. Proceeds from settled hedges were$107 million for the combined year endedDecember 31, 2020 . For the year endedDecember 31, 2019 , proceeds from settled hedges were$111 million . Net derivative (loss) gain from commodity contracts - Net derivative loss from commodity contracts was$50 million for the combined year endedDecember 31, 2020 compared to$59 million for same period of 2019, representing an overall change of$9 million as reflected in the following table. The non-cash changes in the fair value of our outstanding derivatives resulted from the positions held as well as the relationship between contract prices and the associated forward curves at the end of each year. Successor Predecessor Combined Predecessor November 1, January 1, 2020 Year ended 2020 - - October 31, December 31, Year ended December 31, 2020 2020 December 31, 2019 2020 (in millions) Non-cash derivative (loss) gain, excluding noncontrolling interest$ (138) $ (19) $ (157) $ (166) Non-cash derivative (loss) gain, noncontrolling interest (2) 2 - (4) Total non-cash changes (140) (17) (157) (170) Net (payments) proceeds on commodity derivatives (1) 108 107 111 Net derivative (loss) gain from commodity contracts$ (141) $ 91$ (50) $ (59) Trading revenue - Trading revenues were a combined$162 million for the year endedDecember 31, 2020 , a decrease of$124 million , or 43% from$286 million during the year endedDecember 31, 2019 . The decrease was due to lower volumes and prices related to our natural gas trading activities. The decline in volumes and prices were impacted by a decrease in energy demand resulting from the pandemic and milder temperatures in 2020. Operating costs - Operating costs for the combined year endedDecember 31, 2020 was$625 million , which was a decrease of$270 million or 30% from$895 million for the same period in 2019. The decrease was primarily attributable to efficiencies and streamlining of our operations and reduced operating costs from shut-in wells as well as lower activity levels such as downhole maintenance. Operating costs also declined as a result of our workforce reductions and reduced work schedules during April andMay 2020 . 58 -------------------------------------------------------------------------------- General and administrative expenses - Our general and administrative expenses (G&A) were$252 million for the combined year endedDecember 31, 2020 , which was a decrease of$38 million from$290 million in the year endedDecember 31, 2019 . The decrease in G&A expenses resulted from workforce reductions, cost saving efforts, a decline in spending across a number of cost categories and reduced work hours in April andMay 2020 . These savings were partially offset by the cost of obtaining additional directors and officers insurance related to our Chapter 11 Cases, lower capitalized salary costs as a result of suspending our capital program beginning inMarch 2020 as well a slight increase in employee incentive awards due to changes to the variable portion of our incentive compensation program inMay 2020 , which had the effect of increasing our cash-settled awards to target and achieving a higher payout on performance metrics. Depreciation, depletion and amortization - Depreciation, depletion and amortization during the Successor period reflects fair value adjustments recorded as part of fresh start accounting on our emergence date. For further detail about fresh start accounting, see Part II, Item 8 - Financial Statements and Supplementary Data, Note 3 Fresh Start Accounting. The decrease in depreciation, depletion and amortization on an annualized basis for the Predecessor period endedOctober 31, 2020 from 2019 was predominately due to a decrease in our depletable basis as a result of our asset impairment recorded in the first quarter of 2020, see Part II, Item 8 - Financial Statements and Supplementary Data, Note 13 Asset Impairments. Asset impairments - We recorded an impairment charge inMarch 2020 due to the sharp drop in commodity prices at the end of the first quarter of 2020. The 2020 Predecessor period includes this impairment charge of$1.7 billion , of which$1.5 billion related to certain of our proved properties and approximately$228 million related to unproved acreage that is no longer included in our development plans. The fair values of our proved oil and natural gas properties were determined as of the date of the assessment using discounted cash flow models, which included estimates of future oil and natural gas production, index prices based on available forward curves and internally generated price forecasts thereafter, pricing adjustments for differentials, estimated future operating costs and capital development plans. We used a market-based weighted average cost of capital to discount the future net cash flows. For further detail about our first quarter 2020 asset impairment, see Part II, Item 8 - Financial Statements and Supplementary Data, Note 13 Asset Impairments.
Exploration expense - Exploration expense decreased to
Trading costs - Natural gas purchases related to trading activity were$102 million for the combined year endedDecember 31, 2020 , which was a decrease of$99 million or 49% from$201 million in 2019. The decrease was predominantly the result of lower volume and prices related to our natural gas trading activities. The decline in volumes and prices were impacted by a decrease in energy demand resulting from the pandemic and milder temperatures in 2020. Other expenses, net - Other expenses, net was$106 million for the combined year endedDecember 31, 2020 , which was an increase of$52 million from$54 million in 2019. The increase was largely the result of a one-time deficiency payment made inApril 2020 in connection with an expiring pipeline delivery contract and employee termination charges related to ourAugust 2020 workforce reduction and the departure of our former chief executive officer inDecember 2020 . Reorganization items, net - We recognized a$4.1 billion net gain in the 2020 Predecessor period primarily related to the cancellation of our pre-emergence debt and the associated write-off of the unamortized balance of deferred gain, original issue discounts and deferred issuance costs partially offset by legal, professional and other fees, including debtor-in-possession financing costs, which were incurred during our bankruptcy proceedings. See Part II, Item 8 - Financial Statements and Supplementary Data, Note 2 Chapter 11 Proceedings for additional information about reorganization items, net. 59 -------------------------------------------------------------------------------- Interest and debt expense, net - Interest and debt expense, net for the Successor period includes interest on our Revolving Credit Facility, Second Lien Notes and EHP Notes as well as amortization of debt issuance costs as shown in the table below. We expect that our future interest expense will generally be in line with the interest on debt for the Successor period on an annualized basis. Interest and debt expense, net decreased in the Predecessor period of 2020 compared to the year endedDecember 31, 2019 primarily due to ceasing to record interest expense on our debt as of the petition date and the subsequent discharge of our debt upon emergence from bankruptcy. Additionally, we decreased the amount of interest expense capitalized in the 2020 Predecessor period as compared to 2019 primarily due to decreased drilling activity. See Part II, Item 8 - Financial Statements and Supplementary Data, Note 8 Debt for additional information on our credit agreements.
The table below shows interest and debt expense, net for the Successor and Predecessor periods (in millions):
Successor Predecessor Predecessor
November 1, 2020 - January 1, 2020 - Year ended
December 31, 2020 October 31, 2020 December 31, 2019
Interest expense on debt $ 10 $ 223 $ 437
Amortization of deferred gain - (39) (70)
Amortization of debt issuance 1 29 28
Other interest - 1 2
Capitalized interest - (8) $ (14)
Interest and debt expense, net $ 11 $ 206 $ 383
Net gain on early extinguishment of debt - We repurchased debt in the first
quarter of 2020 and recognized a net gain on early extinguishment of debt for
the combined year ended December 31, 2020 of $5 million , which is a decrease of
$121 million from $126 million during the same period in 2019. The decrease was
due to lower debt repurchase activity in 2020.
Other non-operating expenses - Other non-operating expenses for the combined
year ended December 31, 2020 increased $17 million to $89 million , compared to
$72 million for the same period of 2019. This increase was primarily the result
of legal, professional and other fees associated with the preparation of the
Chapter 11 Cases, incurred prior to our petition date.
Net loss (income) attributable to noncontrolling interests - Upon emergence from
bankruptcy, we acquired all of ECR's member interests in the Ares JV; therefore,
the allocation of net loss (income) to noncontrolling interest holders in the
Successor period is not comparable to the Predecessor periods.
The net loss allocated to the noncontrolling interest holder in the Successor period primarily relates to non-cash losses on derivatives.
The decrease in net income allocated to noncontrolling interests in the Predecessor period of 2020 included ten months as compared to twelve months in 2019 due to the acquisition of ECR's interest in the Ares JV at emergence and to a lesser extent, lower revenue from the net profits interest held by the BSP JV due to a decline in commodity prices between periods.
See Part II, Item 8 - Financial Statements and Supplementary Data, Note 7 Joint Ventures for additional information on the Ares JV.
Year Ended
See Part II, Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations, Statement of Operations Analysis in our 2019 Form 10-K for our analysis of the changes in our consolidated statements of operations for the year endedDecember 31, 2019 compared toDecember 31, 2018 . 60 --------------------------------------------------------------------------------
Non-GAAP Financial Measures
Adjusted net income (loss) - Our results of operations, which are presented in accordance withU.S. generally accepted accounting principles (GAAP), can include the effects of unusual, out-of-period and infrequent transactions and events affecting earnings that vary widely and unpredictably (in particular certain non-cash items such as derivative gains and losses) in nature, timing, amount and frequency. Therefore, management uses a measure called adjusted net income (loss) that excludes those items. This measure is not meant to disassociate these items from management's performance but rather is meant to provide useful information to investors interested in comparing our performance between periods. Reported earnings are considered representative of management's performance over the long term. Adjusted net income (loss) is not considered to be an alternative to net income (loss) reported in accordance with GAAP. The following table presents a reconciliation of the GAAP financial measure of net income (loss) to the non-GAAP financial measure of adjusted net income (loss) and presents the GAAP financial measure of net income (loss) attributable to common stock per diluted share and the non-GAAP financial measure of adjusted net income (loss) per diluted share (in millions, except per share data): Successor Predecessor Combined Predecessor November 1, Year ended Year ended Year ended 2020 - January 1, 2020 - December 31, December 31, December 31, December 31, October 31, 2020 2020 2019 2018 2020 Net income (loss)$ (125) $ 1,996$ 1,871 $ 99 $ 429 Net income attributable to noncontrolling interests 2 (107) (105) (127) (101) Net (loss) income attributable to common stock (123) 1,889 1,766 (28) 328 Unusual, infrequent and other items: Asset impairment - 1,736 1,736 - - Reorganization items, net 3 (4,060) (4,057) - - Legal, professional and other fees related to our reorganization - 65 65 - - Non-cash derivative loss (gain) from commodities, excluding noncontrolling interest 138 19 157 166 (224) Non-cash derivative loss from interest-rate contracts - - - 4 6 Severance and termination costs 5 10 15 47 4 Deficiency payment on a pipeline delivery contract - 20 20 - - Power plant maintenance - 7 7 - - Write-off of deferred financing costs - 4 4 4 4 Incentive and retention award modification - 4 4 - - Net gain on early extinguishment of debt - (5) (5) (126) (57) Gain on asset divestitures - - - - (5) Rig termination expenses 1 4 5 3 8 Ad valorem late payment penalties - 4 4 Other, net 4 18 22 - (3) Total unusual, infrequent and other items 151 (2,174) (2,023) 98 (267) Adjusted net income (loss)$ 28 $
(285)
Net (loss) income attributable to common stock per diluted share$ (1.48) $ 40.42 -$ (0.57) $ 6.77 Adjusted net income (loss) per diluted share$ 0.34 $ (2.98) -$ 1.40 $ 1.27 61
--------------------------------------------------------------------------------
Adjusted EBITDAX - We define Adjusted EBITDAX as earnings before interest
expense; income taxes; depreciation, depletion and amortization; exploration
expense; other unusual, infrequent and out-of-period items; and other non-cash
items. We believe this measure provides useful information in assessing our
financial condition, results of operations and cash flows and is widely used by
the industry, the investment community and our lenders. Although this is a
non-GAAP measure, the amounts included in the calculation were computed in
accordance with GAAP. Certain items excluded from this non-GAAP measure are
significant components in understanding and assessing our financial performance,
such as our cost of capital and tax structure, as well as depreciation,
depletion and amortization of our assets. This measure should be read in
conjunction with the information contained in our financial statements prepared
in accordance with GAAP. A version of Adjusted EBITDAX is a material component
of certain of our financial covenants under our Revolving Credit Facility and is
provided in addition to, and not as an alternative for, income and liquidity
measures calculated in accordance with GAAP.
The following table presents a reconciliation of the GAAP financial measure of
net income (loss) to the non-GAAP financial measure of Adjusted EBITDAX (in
millions):
Successor Predecessor Combined Predecessor
November 1, Year ended Year ended Year ended
2020 - January 1, 2020 - December 31, December 31, December 31,
December 31, October 31, 2020 2020 2019 2018
2020
Net income (loss) $ (125) $ 1,996 $ 1,871 $ 99 $ 429
Interest and debt expense, net 11 206 217 383 379
Depreciation, depletion and
amortization 34 328 362 471 502
Exploration expense 1 10 11 29 34
Unusual, infrequent and other items 151 (2,174) (2,023) 98 (267)
Non-cash items
Accretion expense 8 33 41 36 27 Stock-settled compensation - 6 6 13 15 Post-retirement medical and pension 1 3 4 8 4 Other non-cash items 2 (2) - 5 (6) Adjusted EBITDAX$ 83 $ 406 $ 489$ 1,142 $ 1,117 The following table sets forth a reconciliation of the GAAP measure of net cash provided by operating activities to the non-GAAP financial measure of Adjusted EBITDAX (in millions): Successor Predecessor Combined Predecessor November 1, Year ended Year ended 2020 - January 1, 2020 Year ended December 31, December 31, December 31, - October 31, December 31, 2020 2019 2018 2020 2020 Net cash provided (used) by operating activities$ (12) $ 118 $ 106$ 676 $ 461 Cash interest 8 87 95 439 441 Exploration expenditures 1 10 11 18 17 Working capital changes 86 191 277 8 199 Other, net - - - 1 (1) Adjusted EBITDAX$ 83 $ 406 $ 489$ 1,142 $ 1,117 62
--------------------------------------------------------------------------------
Liquidity and Capital Resources
Cash Flow Analysis
Cash flows from operating activities - Our net cash provided by operating activities is sensitive to many variables, particularly changes in commodity prices. Commodity price movements may also lead to changes in other variables in our business, including adjustments to our capital program. Our net cash provided by operating activities of$106 million for the combined year endedDecember 31, 2020 decreased$570 million , or 84%, from$676 million for the same period in 2019. This decrease was primarily driven by a lower commodity price environment, declining production and$113 million of payments of professional and other fees related to our bankruptcy proceedings during 2020. This decrease was partially offset by a reduction in our cost structure due to lower activity levels in 2020, including the effect of shut-in wells, operational efficiencies and workforce reductions as compared to 2019 as well as reduced cash interest between comparative periods. Cash flows from investing activities - Our net cash used in investing activities was$37 million in the combined year endedDecember 31, 2020 , which was a decrease of$357 million , or 91%, from$394 million for the same period in 2019. The decrease primarily related to reducing our capital investment in 2020 to a level necessary to maintain the mechanical integrity of our facilities to operate them in a safe and environmentally responsible manner partially offset by a decrease in proceeds from asset divestitures. The table below summarizes net cash used in investing activities (in millions): Successor Predecessor Combined Predecessor November 1, 2020 January 1, 2020 Year ended Year ended - December 31, - October 31, December 31, 2020 December 31, 2019 2020 2020 Capital investments $ (7) $ (40) $ (47) $ (455) Changes in capital investment accruals (1) (24) (25) (85) Acquisitions, divestitures and other 1 34 35 146 Net cash used in investing activities $ (7) $ (30) $ (37) $ (394) Cash flows from financing activities - Our net cash used in financing activities was$58 million in the combined year endedDecember 31, 2020 . Uses of cash in 2020 related to our debt transactions including$518 million net repayments on our 2014 Revolving Credit Facility (some of which was repaid with debtor-in-possession financing) and$100 million used to payoff of our 2020 Senior Notes in the first quarter. At emergence, we borrowed$200 million under our Second Lien Term Loan, the proceeds of which were used to repay a portion of our debtor-in-possession financing. The outstanding balance on our Revolving Credit Facility was$99 million as ofDecember 31, 2020 . As a result of our bankruptcy proceedings, we incurred$45 million in debt financing and issuance costs. We also made$104 million of distributions to noncontrolling interest holders in the Predecessor period of 2020, which included payments to our former noncontrolling interest holder, ECR. Our distributions to noncontrolling interest holders was$30 million in the Successor period. We raised proceeds of$446 million from an equity issuance at the time of our emergence from bankruptcy. Our net cash used in financing activities for the year endedDecember 31, 2019 was$282 million and included net repayments of$23 million on our 2014 Revolving Credit facility,$102 million in net distributions to noncontrolling interest holders and$156 million used to repurchase our Second Lien Notes. 63 --------------------------------------------------------------------------------
The table below summarizes net cash (used) provided by financing activities for
the years ended
Successor Predecessor Combined Predecessor
November 1, January 1, 2020 - Year ended Year ended
2020 - December October 31, 2020 December 31, 2020 December 31, 2019
31, 2020
Debt transactions $ (126) $ (241) $ (367) $ (181)
(Distributions to) contributions
from noncontrolling interest
holders, net (30) (104) (134) (102)
Issuance of common stock - 446 446 4
Other - (3) (3) $ (3)
Net cash (used) provided by
financing activities $ (156) $ 98 $ (58) $ (282)
Liquidity
Our primary sources of liquidity and capital resources are cash flows from
operations, cash on hand and available borrowing capacity under our Revolving
Credit Facility. We emerged from our bankruptcy with a strong balance sheet and
low leverage. We have substantially revamped our cost structure while
maintaining sustainable operations. We consider our low leverage and ability to
control costs to be a core strength and strategic advantage, which we are
focused on maintaining. At current commodity prices and the 2021 capital program
described below, we expect to generate positive free cash flow, which may be
used to (i) increase investments in our drilling program to accelerate value,
(ii) pay dividends or buy back stock to the extent permitted under our Revolving
Credit Facility, or (iii) maintain cash on our balance sheet. We may be required
to begin paying income taxes if Brent prices remain above $55 per barrel for a
sustained period. Our tax paying status depends on a number of factors,
including but not limited to, the amount and type of our capital spend, cost
structure and activity levels. We believe we have sufficient sources of cash to
meet our obligations for the next twelve months.
As of December 31, 2020 , we had liquidity of $335 million , which consisted of
$28 million in unrestricted cash and $307 million of available borrowing
capacity under our Revolving Credit Facility. After giving effect to our January
2021 debt issuance discussed below, we had on a pro forma basis liquidity of
$425 million , which consisted of $28 million in unrestricted cash and $397
million of available borrowing capacity under our Revolving Credit Facility.
In January 2021 , we completed a private offering of $600 million in aggregate
principal amount of our 7.125% senior unsecured notes due 2026 (Senior Notes).
The net proceeds of $590 million were used to repay in full our Second Lien Term
Loan and our EHP Notes, with the remaining proceeds used to pay down a portion
of the outstanding borrowings under our Revolving Credit Facility. The proceeds
received were net of $10 million in debt issuance and transaction costs. For
more information on this debt issuance, refer to Part II, Item 8 - Financial
Statements and Supplementary Data, Note 19 Subsequent Events and for more
information on our debt, refer to Part II, Item 8 - Financial Statements and
Supplementary Data, Note 8 Debt.
The following table presents our pro forma long-term debt assuming the January
2021 debt issuance and related use of proceeds occurred on December 31, 2020 :
Actual Transaction
December 31, 2020 Adjustments Pro Forma
(in millions)
Revolving Credit Facility $ 99 $ (90) $ 9
Second Lien Term Loan 200 (200) -
EHP Notes 300 (300) -
Senior Notes - 600 600
Face amount of long-term debt 599 10 609
Unamortized debt issuance costs (2) (8) (10)
Total long-term debt $ 597 $ 2 $ 599
As of
64
--------------------------------------------------------------------------------For a description of the terms and conditions of our long-term indebtedness, see Part II, Item 8 - Financial Statements and Supplementary Data, Note 8 Debt.
Derivatives and Hedging Activities
Commodity Contracts
The credit agreement governing our senior debtor-in-possession facility during bankruptcy, which was paid in full and terminated on the Effective Date, required us to enter into hedging arrangements covering at least 25% of our share of expected crude oil production for the next twelve months. OnJuly 24, 2020 , we entered into various instruments to satisfy this requirement. Our post-emergence Revolving Credit Facility and Second Lien Term Loan require us to maintain a significantly higher amount of hedges on expected crude oil production, as described in Part II, Item 8 - Financial Statements and Supplementary Data, Note 8 Debt. As described above, our Second Lien Term Loan was paid in full inJanuary 2021 . Unless otherwise indicated, we use the term "hedge" to describe derivative instruments that are designed to achieve our hedging program goals, even though they are not accounted for as cash-flow or fair-value hedges. We did not have any commodity derivatives designated as accounting hedges as of and during the combined year endedDecember 31, 2020 . We currently have the following Brent-based crude oil contracts, as ofFebruary 28, 2021 : Q1 Q2 Q3 Q4 January - 2021 2021 2021 2021 2022 October 2023 Sold Calls: Barrels per day 19,028 33,537 36,362 36,700 30,783 17,758
Weighted-average price per barrel
$ 50.31 $ 60.70 $ 59.37 $ 58.01 Purchased Puts Barrels per day 39,148 37,872 36,617 35,483 30,783 17,758
Weighted-average price per barrel
$ 40.00 $ 40.00 $ 40.00 $ 40.00 Sold Puts Barrels per day 15,659 15,149 14,647 14,193 3,042 -
Weighted-average price per barrel
$ 30.00 $ 32.00 $ 32.00 $ - Swaps Barrels per day 8,524 9,639 9,063 8,922 6,576 5,919
Weighted-average price per barrel
The BSP JV entered into crude oil derivatives for insignificant volumes through 2021 that are included in our consolidated results but not in the above table. The BSP JV also entered into natural gas swaps for insignificant volumes for periods throughMay 2021 . The hedges entered into by the BSP JV could affect the timing of the reversion of BSP's preferred interest.
Capital Program
We seek to create value by investing part of our operating cash flow back into
our business. We respond to economic conditions by adjusting the amount and
allocation of our capital program while continuing to identify efficiencies and
cost savings. Because we own or control substantially all of our assets, the
amount and timing of capital expenditures is within our control, subject to our
discretion and may be adjusted during the year depending on commodity prices and
other factors. We retain the flexibility to defer planned capital expenditures
depending on a variety of factors, including, but not limited to, prevailing and
anticipated prices for oil, natural gas and NGLs, the success of our drilling
program, operating costs and other general market conditions.
65
--------------------------------------------------------------------------------
We focus our capital program on oil projects that provide high margins and low
decline rates, prioritizing projects with quick paybacks and full-cycle returns
to maximize our free cash flow. Our technical teams are consistently working to
enhance value by improving the economics of our inventory through detailed
geologic studies as well as application of more effective and efficient drilling
and completion techniques. We regularly monitor internal performance and
external factors and adjust our capital investment program with the objective of
creating the most value from our asset portfolio. We believe investing in these
projects will generate positive cash flow allowing us to fund future capital
programs with a high oil mix. Our low decline rates compared to our industry
peers together with our high level of operational control give us the
flexibility to adjust the level of our capital investments as circumstances
warrant.
2020 Capital Program
We entered 2020 with an internally funded capital program plan of$100 million to$300 million . InMarch 2020 , we reduced our capital investment to a level that intended to maintain the mechanical integrity of our facilities to operate in a safe and environmentally responsible manner in response to the collapse in crude oil prices and ceased all field development and growth projects. We made$40 million of internally funded capital investments during the 2020 Predecessor period and$7 million during the Successor period. Our JV partners invested$93 million during the year endedDecember 31, 2020 as shown in the table below. For further information regarding the Alpine JV see Joint Ventures above. The table below sets forth our internally funded capital investments by activity type included in our consolidated financial statements for the combined year endedDecember 31, 2020 and investments in our fields by our JV partners (in millions): Drilling Workovers Facilities Exploration Other Total Capital Investments Internally funded$ 15 $ 9 $ 22 $ -$ 1 $ 47 Capital investments not included in our financial statements MIRA-funded capital 1 - - - $ - $ 1 Alpine-funded capital 92 - - - $ - $ 92 Total capital investments$ 108 $ 9 $ 22 $ -$ 1 $ 140 2021 Capital Program Our capital program will be dynamic in response to oil market volatility while focusing on maintaining strong liquidity and maximizing our free cash flow. The 2021 capital program will target reinvestment of approximately 50% of anticipated available cash flow from operations at current commodity prices. Our 2021 capital program is anticipated to be between$200 million and$225 million , including approximately$40 million of mechanical integrity and midstream turnaround activities deferred from 2020 to 2021. The current plan anticipates CRC to gradually raise quarterly investment throughout the year if the commodity environment continues to strengthen. If commodity prices decline significantly from current levels, we may need to adjust our capital program in response to market conditions. Off-Balance-Sheet Arrangements We have no off-balance-sheet arrangements other than the purchase obligations described in the Contractual Obligations section below. 66 --------------------------------------------------------------------------------
Contractual Obligations
The table below summarizes our on- and off- balance sheet obligations as of
Payments Due by Year
Less than 1 More than 5
Total Year 1-3 Years 3-5 Years Years
On-Balance Sheet (in millions)
Long-term debt(a) $ 599 $ - $ - $ 299 $ 300
Interest on long-term debt(b) 257 43 86 79 49
Pension and postretirement(c) 221 19 23 19 160
Operating and finance leases(d) 49 8 15 11 15
Other long-term liabilities 9 3 6 - -
Off-Balance Sheet
Purchase obligations(e) 186 42 85 12 47
Total(f) $ 1,321 $ 115 $ 215 $ 420 $ 571
(a)In performing the calculation, the Revolving Credit Facility borrowings
outstanding at December 31, 2020 of $99 million were assumed to be outstanding
for the entire term of the agreement. See Part II, Item 8 - Financial Statements
and Supplementary Data, Note 8 Debt for more information. On January 20, 2021 ,
we completed an offering of $600 million aggregate principal amount of the
Senior Notes. We used the net proceeds to repay in full our Second Lien Term
Loan and EHP Notes, with the remainder of the net proceeds used to repay a
portion of the outstanding borrowings under the Revolving Credit Facility. See
Part II, Item 8 - Financial Statements and Supplementary Data, Note 19
Subsequent Events for more information.
(b)The calculation of cash interest payments on our variable interest-rate debt
assumes the interest rate at December 31, 2020 will continue for the entire
term. This amount excludes the effects of the January 2021 refinancing.
(c)Represents undiscounted future obligations for defined benefit and
supplemental plans.
(d)Our operating leases include commercial office space, fleet vehicles and
certain facilities. Our finance leases include information technology equipment
and are not material to our consolidated financial statements taken as a whole.
(e)Amounts include payments that will become due under long-term agreements to
purchase goods and services used in the normal course of business primarily
including pipeline capacity and land leases. Purchase obligations for pipeline
capacity are based on contractual volumes and current market rates for that firm
transportation capacity during the contract period. Land leases reflect
obligations for fixed payments under our term contracts. Also included is a
commitment to invest approximately $12 million in evaluation and development
activities at one of our oil and natural gas properties prior to January 1,
2023 . Any deficiency in meeting this capital investment obligation would need to
be paid in cash.
(f)This table does not include our asset retirement obligations. See Part II,
Item 8 - Financial Statements and Supplementary Data, Note 1 Nature of Business,
Summary of Significant Accounting Policies and Other for more information.
Lawsuits, Claims, Commitments and Contingencies
We are involved, in the normal course of business, in lawsuits, environmental
and other claims and other contingencies that seek, among other things,
compensation for alleged personal injury, breach of contract, property damage or
other losses, punitive damages, civil penalties, or injunctive or declaratory
relief.
We accrue reserves for currently outstanding lawsuits, claims and proceedings
when it is probable that a liability has been incurred and the liability can be
reasonably estimated. Reserve balances at December 31, 2020 and 2019 were not
material to our consolidated balance sheets as of such dates.
In October 2020 , Signal Hill Services, Inc. defaulted on its decommissioning
obligations associated with two offshore platforms. The Bureau of Safety and
Environmental Enforcement determined that former lessees, including our former
parent, Occidental Petroleum Corporation (Oxy) with an approximately 35% share,
are responsible for accrued decommissioning obligations associated with these
offshore platforms. Oxy notified us of the claim under the indemnification
provisions of the Separation and Distribution Agreement between us and Oxy. We
are currently evaluating this claim.
We also evaluate the amount of reasonably possible losses that we could incur as
a result of these matters. We believe that reasonably possible losses that we
could incur in excess of reserves cannot be accurately determined.
See Part II, Item 8 - Financial Statements and Supplementary Data, Note 10 Lawsuits, Claims, Commitments and Contingencies.
67
--------------------------------------------------------------------------------Critical Accounting Policies and Estimates
Our critical accounting policies and estimates include property, plant and equipment and fair value measurements. See Part II, Item 8 - Financial Statements and Supplementary Data, Note 1 Nature of Business, Summary of Significant Accounting Policies and Other for details on these critical accounting policies and estimates that involve management's judgment and that could result in a material impact to the consolidated financial statements due to the levels of subjectivity and judgment.
Significant Accounting and Disclosure Changes
See Part II, Item 8 - Financial Statements and Supplementary Data, Note 4 Accounting and Disclosure Changes for a discussion of new accounting standards.
68
--------------------------------------------------------------------------------
FORWARD-LOOKING STATEMENTS
The information included herein contains forward-looking statements that involve
risks and uncertainties that could materially affect our expected results of
operations, liquidity, cash flows and business prospects. Such statements
include those regarding our expectations as to our future:
•financial position, liquidity, cash flows and results of operations
•business prospects
•transactions and projects
•operating costs
•operations and operational results including production, hedging and capital
investment
•budgets and maintenance capital requirements
•reserves
•type curves
•expected synergies from acquisitions and joint ventures
Actual results may differ from anticipated results, sometimes materially, and
reported results should not be considered an indication of future performance.
While we believe assumptions or bases underlying our expectations are reasonable
and make them in good faith, they almost always vary from actual results,
sometimes materially. We also believe third-party statements we cite are
accurate but have not independently verified them and do not warrant their
accuracy or completeness. Factors (but not necessarily all the factors) that
could cause results to differ include:
•our ability to execute our business plan post-emergence;
•the volatility of commodity prices and the potential for sustained low oil,
natural gas and natural gas liquids prices;
•impact of our recent emergence from bankruptcy on our business and
relationships;
•debt limitations on our financial flexibility;
•insufficient cash flow to fund planned investments, interest payments on our
debt, debt repurchases or changes to our capital plan;
•insufficient capital or liquidity, including as a result of lender
restrictions, unavailability of capital markets or inability to attract
potential investors;
•limitations on transportation or storage capacity and the need to shut-in
wells;
•inability to enter into desirable transactions, including acquisitions, asset
sales and joint ventures;
•our ability to utilize our net operating loss carryforwards to reduce our
income tax obligations;
•legislative or regulatory changes, including those related to drilling,
completion, well stimulation, operation, maintenance or abandonment of wells or
facilities, managing energy, water, land, greenhouse gases (GHGs) or other
emissions, protection of health, safety and the environment, or transportation,
marketing and sale of our products;
•joint ventures and acquisitions and our ability to achieve expected synergies;
•the recoverability of resources and unexpected geologic conditions;
•incorrect estimates of reserves and related future cash flows and the inability
to replace reserves;
•changes in business strategy;
•production-sharing contracts' effects on production and unit operating costs;
•the effect of our stock price on costs associated with incentive compensation;
•effects of hedging transactions;
•equipment, service or labor price inflation or unavailability;
•availability or timing of, or conditions imposed on, permits and approvals;
•lower-than-expected production, reserves or resources from development
projects, joint ventures or acquisitions, or higher-than-expected decline rates;
•disruptions due to accidents, mechanical failures, power outages,
transportation or storage constraints, natural disasters, labor difficulties,
cyber-attacks or other catastrophic events;
•pandemics, epidemics, outbreaks, or other public health events, such as the
COVID-19; and
•factors discussed in Part I, Item 1A - Risk Factors.
Words such as "anticipate," "believe," "continue," "could," "estimate,"
"expect," "goal," "intend," "likely," "may," "might," "plan," "potential,"
"project," "seek," "should," "target, "will" or "would" and similar words that
reflect the prospective nature of events or outcomes typically identify
forward-looking statements. Any forward-looking statement speaks only as of the
date on which such statement is made, and we undertake no obligation to correct
or update any forward-looking statement, whether as a result of new information,
future events or otherwise, except as required by applicable law.
69--------------------------------------------------------------------------------
© Edgar Online, source
