General
Except when the context otherwise requires or where otherwise indicated, all
references to ''CRC,'' the ''company,'' ''we,'' ''us'' and ''our'' refer to
We are an independent oil and natural gas exploration and production company operating properties exclusively withinCalifornia . We are incorporated inDelaware and became a publicly traded company onDecember 1, 2014 . OnJuly 15, 2020 , we filed voluntary petitions in theUnited States Bankruptcy Court for the Southern District of Texas seeking relief under Chapter 11 of Title 11 of the United States Bankruptcy Code and onOctober 27, 2020 we emerged from the Chapter 11 proceedings as further described below. Our condensed consolidated financial statements, including the Notes thereto, included in Part I, Item - Financial Statements have been prepared assuming we will continue as a going concern. We have applied Financial Accounting Standards Board Accounting Standards Codification 852, Reorganizations (ASC 852), in preparing these unaudited condensed consolidated financial statements. ASC 852 requires that the financial statements, for periods subsequent to the petition date (July 15, 2020 ), distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. As a result, we have segregated liabilities and obligations whose treatment and satisfaction are dependent on the outcome of the Chapter 11 Cases and classified these items as liabilities subject to compromise (LSTC) on our condensed consolidated balance sheet as ofSeptember 30, 2020 . In addition, we have classified all income, expenses, gains or losses that were incurred or realized as a result of the Chapter 11 Cases subsequent to the petition date as reorganization items, net in our condensed consolidated statement of operations for the period endedSeptember 30, 2020 . Further, we believe that we are required to adopt fresh start accounting upon emergence from bankruptcy because (1) the holders of existing voting shares prior to emergence received less than 50% of our new voting shares following our emergence from bankruptcy and (2) the reorganization value of our assets immediately prior to the confirmation of the Plan was less than the post-petition liabilities and allowed claims, which are included in liabilities subject to compromise. Fresh start accounting will be applied as ofOctober 27, 2020 , the date we emerged from bankruptcy. Under the principles of fresh start accounting, a new reporting entity is considered to have been created, and, as a result, the reorganization value of the emerging entity is assigned to individual assets and liabilities based on their estimated relative fair values. The process of estimating the fair value of our assets, liabilities and equity upon emergence is currently ongoing. In support of the Plan, the enterprise value of the successor company was estimated and approved by theBankruptcy Court to be in the range of$2.2 billion to$2.8 billion . As a result of the application of fresh start accounting and the effects of the implementation of the Plan, the financial statements of the successor entity will not be comparable to the financial statements, including this statement, prepared prior to our Effective Date. Chapter 11 Proceedings Our spin-off from Occidental Petroleum Corporation (Occidental) onNovember 30, 2014 burdened us with significant debt which was used to pay a$6.0 billion cash dividend to Occidental. Together with the activity level and payables that we assumed from Occidental and due to Occidental's retention of the vast majority of our receivables, our debt peaked at approximately$6.8 billion inMay 2015 . Since then, we have engaged in a series of asset sales, joint ventures, debt exchanges, tenders, debt repurchases and other financing transactions to reduce our overall level of debt and improve our balance sheet prior to filing for bankruptcy. As ofSeptember 30, 2020 , we had outstanding net long-term debt of approximately$5.1 billion , of which$4.4 billion is presented as liabilities subject to compromise on our condensed consolidated balance sheet. OnJuly 15, 2020 , we filed voluntary petitions for relief under Chapter 11 of Title 11 of the Bankruptcy Code (Chapter 11 Cases) in theUnited States Bankruptcy Court for the Southern District of Texas , Houston Division (Bankruptcy 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 (as amended, supplemented or modified, the Plan). 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). 34 -------------------------------------------------------------------------------- During the course of the Chapter 11 Cases, theBankruptcy Court granted the relief requested in certain motions, authorizing payments of pre-petition liabilities with respect to certain employee compensation and benefits, taxes, royalties, certain essential vendor payments and insurance and surety obligations, which allowed our business operations to continue uninterrupted during the pendency of the Chapter 11 Cases. All transactions outside the ordinary course of business required the prior approval of theBankruptcy Court . OnJuly 15, 2020 , immediately prior to the commencement of the Chapter 11 Cases, we and certain affiliates ofAres Management L.P. (Ares), includingECR Corporate Holdings L.P. , a portfolio company of Ares (ECR), entered into a Settlement and Assumption Agreement (Settlement Agreement) related to our midstream joint venture,Elk Hills Power, LLC (Ares JV or Elk Hills Power), which holds our Elk Hills power plant and a cryogenic gas processing plant. OnAugust 25, 2020 , theBankruptcy Court entered an order approving the Settlement Agreement on a final basis. Among other things, the Settlement Agreement included a conversion right, which would be deemed exercised upon our emergence from bankruptcy, allowing us to acquire all (but not less than all) of the equity interests in the Ares JV held by ECR in exchange for secured notes (EHP Notes), approximately 20.8% of our new common stock (Ares Settlement Stock) and$2.5 million in cash. For more information on the Settlement Agreement, see Part I, Item 1 - Financial Statements, Note 7 Joint Ventures. The commencement of the Chapter 11 Cases constituted an event of default that accelerated our obligations under the following agreements: (i) Credit Agreement, dated as ofSeptember 24, 2014 , amongJPMorgan Chase Bank, N.A ., as administrative agent, and the lenders that are party thereto (2014 Revolving Credit Facility), (ii) Credit Agreement, dated as ofAugust 12, 2016 , amongThe Bank of New York Mellon Trust Company, N.A. , as collateral and administrative agent, and the lenders that are party thereto (2016 Credit Agreement), (iii) Credit Agreement, dated as ofNovember 17, 2017 , amongThe Bank of New York Mellon Trust Company, N.A. , as administrative agent, and the lenders that are party thereto (2017 Credit Agreement), and (iv) the indentures governing our 8% Senior Secured Second Lien Notes due 2022 (Second Lien Notes), 5.5% Senior Notes due 2021 (2021 Notes) and 6% Senior Notes due 2024 (2024 Notes and together with the 5% Senior Notes due 2020 and 2021 Notes, the Senior Notes). Additionally, other events of default, including cross-defaults, are present under these debt agreements. Under the Bankruptcy Code, the creditors under these debt agreements were stayed from taking any action against us, including exercising remedies as a result of any event of default. See Part I, Item 1 - Financial Statements, Note 6 Debt for additional details about our debt.
Joint Plan of Reorganization Under Chapter 11
Pursuant to the Plan, the following transactions occurred on the Effective Date:
•We issued an aggregate of 83.3 million shares of new common stock and reserved 4.4 million shares for issuance upon exercise of the warrants described below; •We acquired all of the member interests in the Ares JV held by ECR in exchange for the EHP Notes, 17.3 million shares of new common stock and$2.5 million in cash (see Part I, Item 1 - Financial Statements, Note 6 Debt and Part I, Item 1 - Financial Statements, Note 7 Joint Ventures for additional information); •Holders of secured claims under the 2017 Credit Agreement received 22.7 million shares of new common stock in exchange for those claims, and holders of deficiency claims under the 2017 Credit Agreement and all outstanding obligations under the 2016 Credit Agreement, Second Lien Notes, 2021 Notes and 2024 Notes received 4.4 million shares of new common stock in exchange for those claims; •In connection with the Subscription Rights offering and Backstop Commitment Agreement, 34.6 million shares of new common stock were issued in exchange for$446 million (net of a$4 million fee), the proceeds of which were used to pay down our debtor-in-possession financing; •Our Subscription Rights offering was backstopped by certain creditors who received 3.5 million shares of new common stock as a backstop commitment premium (refer to Part I, Item 1 - Financial Statements, Note 16 Equity for additional information on the backstop commitment premium); •The holders of Unsecured Debt Claims (as defined in the Plan) under the 2016 Credit Agreement, Second Lien Notes, 2021 Notes and 2024 Notes received Tier 1 Warrants and Tier 2 Warrants (each as defined in the Plan and collectively, Warrants) to purchase up to 2% and 3%, respectively, of our outstanding shares (on a fully diluted basis calculated immediately after the Effective Date), with an initial exercise price of$36.00 per share, which expire onOctober 27, 2024 and have customary anti-dilution protections (refer to Note 16 Equity for additional information on the Warrants); •All other general unsecured claims will be paid or disputed in the ordinary course of business; and •All existing equity interests were cancelled and their holders received no distributions. 35 -------------------------------------------------------------------------------- As a condition to our emergence, we repaid the outstanding balance of our debtor-in-possession financing with proceeds from our Subscription Rights offering, Backstop Commitment Agreement and a new senior secured revolving credit facility led byCitibank, N.A . We also issued approximately 821,000 shares of new common stock for a junior debtor-in-possession exit fee. For more information on our debtor-in-possession credit agreements and our post-emergence indebtedness, see Part I, Item 1 - Financial Statements, Note 6 Debt. Additionally, pursuant to our Plan, our post-emergence Board of Directors consists of nine directors as follows: (i) our President and Chief Executive Officer,Todd A. Stevens , (ii) seven non-employee directors, includingDouglas E. Brooks , Tiffany (TJ) Thom Cepak,James N. Chapman ,Mark A. McFarland ,Julio M. Quintana ,William B. Roby andBrian Steck , and (iii) one vacancy which will be filled by our post-emergence Board of Directors in accordance with our charter and bylaws. The seven non-employee directors were all appointed to the Board of Directors onOctober 27, 2020 . Our Board of Directors has determined thatMs. Cepak and Messrs. Brooks, Chapman, McFarland, Quintana, Roby and Steck are independent directors as that term is defined in the listing standards of theNew York Stock Exchange (NYSE).Mr. Stevens is not considered by our Board of Directors to be independent because of his current employment with CRC.
Changes to our Stock-Based Compensation Programs
As a result of our bankruptcy, the outstanding stock-based awards under our Amended and Restated California Resources Corporation Long-Term Incentive Plan were cancelled on our Effective Date. Any new stock-based awards or compensation plans will be reviewed and approved by our Board of Directors, which includes seven new directors appointed onOctober 27, 2020 .
The cancellation of these stock-based compensation awards resulted in the recognition of all previously unrecognized compensation expense for equity-settled awards and the liability related to our cash-settled awards was eliminated as the participants received no consideration. The net effect of these adjustments was not material to our financial statements.
Changes to the 2020 Compensation Programs in Second Quarter 2020
In the second quarter of 2020, resulting from the unprecedented circumstances affecting the industry and market volatility, we reviewed our incentive programs for the entire workforce to determine whether those programs appropriately aligned compensation opportunities with our 2020 goals and ensured the stability of our workforce. Following this review, effectiveMay 19, 2020 , our then Board of Directors approved changes in the variable compensation programs for all participating employees. The previously established target amounts of 2020 variable compensation programs did not change; however, all amounts that vest are being settled in cash. As a condition to receiving any award, participants waived participation in our 2020 annual incentive program and forfeited all stock-based compensation awards previously granted in 2020. At that time, there were no changes to stock-based compensation awards granted prior toFebruary 2020 ; however, these pre-2020 awards were subsequently cancelled as part of the Plan. Changes to the variable compensation programs had the effect of accelerating the associated payments into 2020 from future periods. However, the total amount of compensation to be paid under the variable compensation programs at target for 2020 remained largely the same as the amounts that would have been paid at target prior to the changes. Our future compensation programs will be determined by our new Board of Directors.
Organizational Changes
During the course of the Chapter 11 Cases, we evaluated the structure of our workforce and, inAugust 2020 , we implemented organizational changes that resulted in a reduction of our headcount from 1,250 to approximately 1,100 employees. We believe the steps taken improved and strengthened our business as we emerge from bankruptcy. We recorded a one-time$10 million restructuring charge in the third quarter of 2020. We will continue to evaluate resource levels depending on commodity prices.
Business Environment and Industry Outlook
36 -------------------------------------------------------------------------------- Our operating results and those of the oil and gas industry as a whole are heavily influenced by commodity prices. Oil and gas prices and differentials may fluctuate significantly as a result of numerous market-related variables, especially given current global geopolitical and economic conditions. These and other factors make it impossible to predict realized prices reliably. Prices for oil and gas products in 2020 have been strongly influenced by the Coronavirus Disease 2019 (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 addition, members of theOrganization of the Petroleum Exporting Countries (OPEC) andRussia agreed to carry out record oil production cuts inApril 2020 to be followed by gradual incremental increases in multiple steps. In the summer of 2020,OPEC andRussia moved ahead with the first hike in crude oil output. The next hike in crude oil output is currently scheduled forJanuary 2021 . As a result of these conditions, the Brent oil price has been trading in a narrow range around$40 per barrel for several months. Reduced demand initially caused shortages in available storage facilities globally and required many oil and gas producers to shut-in wells or curtail production. InApril 2020 , oil prices declined precipitously, temporarily reaching negative values for spot West Texas Intermediate (WTI) crude. FromMay 2020 throughAugust 2020 , oil prices began to recover as inventory levels stabilized and an easing of shelter-in-place restrictions created partial demand recovery. Prices declined again slightly inSeptember 2020 as demand for oil dropped due to an increase in COVID-19 cases around the world. Demand and pricing may decline again due to a resurgence in the number of cases globally and across parts ofthe United States , which could result in the re-imposition of certain restrictions. The current futures forward curve for Brent crude indicates that prices may continue at close to current levels, which are significantly lower than pre-pandemic levels, for an extended period of time. We continue to closely monitor the impact of COVID-19, which negatively impacted our business and results of operations beginning in the first quarter of 2020. The extent to which our total year operating results will be impacted by the pandemic will depend largely on future developments, which are highly uncertain and cannot be accurately predicted, including new information that may emerge concerning potential vaccines, a resurgence of the pandemic and actions taken to contain it or actions taken by government authorities or other producers in response to commodity price movements, among other things. See Part II, Item 1A - Risk Factors, below for further discussion regarding the impact of the pandemic and declines in commodity prices.
The following table presents the average daily Brent, WTI and NYMEX prices for
the three and nine months ended
Three months ended Nine months ended September 30, September 30, 2020 2019 2020 2019 Brent oil ($/Bbl)$ 43.37 $ 62.00 $ 42.53 $ 64.74 WTI oil ($/Bbl)$ 40.93 $ 56.45 $ 38.32 $ 57.06 NYMEX gas ($/MMBtu)$ 1.93 $ 2.27 $ 1.92 $ 2.72
Note: Bbl refers to a barrel; MMBtu refers to one million British Thermal Units. Operations
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.
37 -------------------------------------------------------------------------------- In response to the rapid fall in commodity prices inMarch 2020 , we reduced our 2020 capital budget to a level that maintains the mechanical integrity of our facilities to operate them in a safe and environmentally responsible manner and ceased all field development and growth projects. As a result, our internally funded capital was$7 million in the second and third quarters of 2020. 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 enhance 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 5 MBoe/d and 3 MBoe/d for the second and third quarters of 2020, respectively. 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 third quarter 2020 average operating expense run rate is below$50 million per month compared to the first quarter of 2020 average of$64 million per month. At our current level of capital investment and surface activity levels, production could continue to decline at a moderate pace through the remainder of the year. 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 in accordance with the orders and guidance of federal, state and local authorities to mitigate the risks of the disease and included temporarily closing all our administrative offices and implementing remote working for most office employees. As a result, our management team and substantially all of our office personnel worked remotely beginning inMarch 2020 . InJune 2020 , we began a phased return to the office, focused on 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, they worked through the shutdowns and continue to work in their plant, rig, field and office locations under ourCOVID-19 Health and Safety Plan that includes protocols for reporting of illness, self-quarantine, hygiene, applying social distancing to minimize close contact between workers, cleaning or disinfection of workspaces and protection of emergency response personnel. We have not experienced any operational slowdowns due to COVID-19 among our workforce.
Our Operations
We conduct our operations on properties that we hold through fee interests, mineral leases and other contractual arrangements. We are the largest non-governmental oil and natural gas mineral acreage holder inCalifornia , with interests in 2.1 million net mineral acres, approximately 60% of which is held in fee and 17% is held by production. Our oil and gas leases have primary terms ranging from one to ten years. Once production commences, the leases are typically extended on the producing acreage through the end of their producing life. As a result of our large mineral acre position held in fee, we generally have the flexibility to shut-in wells while retaining our oil and gas leases which are held by production. We also own or control a network of integrated infrastructure that complements our operations including gas processing plants, oil and gas gathering systems, power plants and other related assets. Our strategically located infrastructure helps us maximize the value generated from our production. We respond to economic conditions by adjusting the amount and allocation of our capital program while continuing to identify efficiencies and cost savings. Volatility in oil prices may materially affect the quantities of oil and gas reserves we can economically produce over the longer term. With our significant land holdings inCalifornia , we have undertaken initiatives to obtain additional value from our surface acreage, including pursuing carbon capture and sequestration, renewable energy opportunities, agricultural activities and other commercial uses. 38 -------------------------------------------------------------------------------- Our share of production and reserves from operations in theWilmington field is subject to contractual arrangements similar to production-sharing contracts (PSCs) that are in effect through the economic life of the assets. Under such contracts we are obligated to fund all capital and production costs. We record a share of production and reserves to recover a portion of such capital and production costs and an additional share for profit. Our portion of the production represents volumes: (i) to recover our partners' share of capital and production costs that we incur on their behalf, (ii) for our share of contractually defined base production and (iii) for our share of remaining production thereafter. We generate returns through our defined share of production from (ii) and (iii) above. These contracts do not transfer any right of ownership to us and reserves reported from these arrangements are based on our economic interest as defined in the contracts. Our share of production and reserves from these contracts decreases when product prices rise and increases when prices decline, assuming comparable capital investment and production costs. However, our net economic benefit is greater when product prices are higher. These contracts represented approximately 17% of our net production for the three months endedSeptember 30, 2020 . In line with industry practice for reporting PSC-type contracts, we report 100% of operating costs under such contracts in our condensed consolidated statements of operations as opposed to reporting only our share of those costs. We report the proceeds from production designed to recover our partners' share of such costs (cost recovery) in our revenues. Our reported production volumes reflect only our share of the total volumes produced, including cost recovery, which is less than the total volumes produced under the PSC-type contracts. This difference in reporting full operating and general and administrative costs but only our net share of production equally inflates our revenue, general and administrative and operating costs and has no effect on our net results.
We own a large and geographically diverse portfolio of assets that generate the following revenue streams:
Crude Oil - We sell nearly all of our crude oil into theCalifornia refining markets, which offer relatively favorable pricing for comparable grades relative to otherU.S. regions. Substantially all of our crude oil production is connected, via our gathering systems, to third-party pipelines andCalifornia refining markets and we have not encountered any significant issues with storage or reaching these markets during the industry downturn. We do not refine or process the crude oil we produce and do not have any significant long-term transportation arrangements.California is heavily reliant on imported sources of energy, with approximately 72% of oil and 90% of natural gas consumed in 2019 imported from outside the state. Nearly all of the imported oil arrives via supertanker, mostly from foreign locations. As a result,California refiners have typically purchased crude oil at international waterborne-based Brent prices. We continue to receive a premium in comparison to other comparable grades due to the demand for our product in the state ofCalifornia . We believe that the limited crude transportation infrastructure from other parts of theU.S. intoCalifornia will continue to contribute to higher realizations than most otherU.S. oil markets for comparable grades. Natural Gas - We sell all of our natural gas not used in our operations into theCalifornia markets on a monthly basis at market-based index pricing. Natural gas prices and differentials are strongly affected by local market fundamentals, such as storage capacity and the availability of transportation capacity from producing areas. Transportation capacity influences prices becauseCalifornia imports approximately 90% of its natural gas from other states andCanada . As a result, we typically enjoy favorable pricing relative to out-of-state producers due to lower transportation costs on the delivery of our natural gas. Changes in natural gas prices have a smaller impact on our operating results than changes in oil prices as only approximately 25% of our total equivalent production volume and even a smaller percentage of our revenue is from natural gas. In addition to selling natural gas, we also use natural gas for our steamfloods and power generation. As a result, the positive impact of higher natural gas prices is partially offset by higher operating costs of our steamflood projects and power generation, but higher prices still have a net positive effect on our operating results due to higher revenue. Conversely, lower natural gas prices lower the operating costs but have a net negative effect on our financial results. We currently have sufficient firm transportation capacity contracts to transport our natural gas, where some capacity volumes vary by month. We sell virtually all of our natural gas production under individually negotiated contracts using market-based pricing on a monthly or shorter basis. 39 -------------------------------------------------------------------------------- Natural Gas Liquid (NGL) - NGL price realizations are related to the supply and demand for the products making up these liquids. Some of them more typically correlate to the price of oil while others are affected by natural gas prices as well as the demand for certain chemical products for which they are used as feedstock. In addition, infrastructure constraints and seasonality can magnify pricing volatility. Our earnings are also affected by the performance of our complementary processing and power-generation assets. We process our wet gas to extract NGLs and other natural gas byproducts. We then deliver dry gas to pipelines and separately sell the NGLs. The efficiency with which we extract liquids from the wet gas stream affects our operating results. Our natural gas processing plants also facilitate access to third-party delivery points near the Elk Hills field. We currently have a pipeline delivery contract to transport 6,500 barrels per day of NGLs to market. Our contract to deliver NGLs requires us to cash settle any shortfall between the committed quantities and volumes actually delivered. In connection with another pipeline delivery contract that we assumed from Occidental, we made a one-time deficiency payment of$20 million inApril 2020 when the contract expired. We sell virtually all of our NGLs using index-based pricing. Our NGLs are generally sold pursuant to contracts that are renewed annually. Approximately 33% of our NGLs are sold to export markets. Electricity - Part of the electrical output from the Elk Hills power plant is used by Elk Hills and other nearby fields, which reduces operating costs and increases reliability. We sell the excess electricity generated to a local utility, other third parties and the grid. The power sold to the utility is subject to agreements through the end of 2023, which include a monthly capacity payment plus a variable payment based on the quantity of power purchased each month. Any excess capacity not sold to other third parties is sold to the grid. The prices obtained for excess power impact our earnings but generally by an insignificant amount.
Derivatives and Hedging Activities
We opportunistically seek strategic hedging transactions to help protect our cash flow, operating margin and capital program from both the cyclical nature of commodity prices and interest rate movements while maintaining adequate liquidity and improving our ability to comply with our debt covenants. We can give no assurance that our hedging programs will be adequate to accomplish our objectives. The Senior DIP Credit Agreement 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 derivative instruments to satisfy this requirement. Our post-emergence Revolving Credit Facility and Second Lien Term Loan require us to maintain hedges on a higher amount of crude oil production as described in Part I, Item 1 - Financial Statements, Note 6 Debt.
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 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. The following table
summarizes the cumulative investment through
Cumulative Investment through September 30, 2020 (in millions) Alpine $ 227 Royale 17 MIRA 139 BSP 200 Total Capital Investment $ 583 40
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For more information on our development joint ventures, please see our most
recent Form 10-K for the year ended
Alpine JV
InJuly 2019 , we entered into a development agreement withAlpine Energy Capital, LLC (Alpine). Alpine has committed to invest$320 million , which may be increased to a total investment of$500 million subject to the mutual agreement of the parties. The initial$320 million commitment covers multiple development opportunities and is intended to be invested over a period of up to three years in accordance with a 275-well development plan. OnMarch 27, 2020 , Alpine elected to suspend its funding obligations pursuant to a contractual right that is triggered if the average NYMEX 12-month forward strip price for Brent crude oil falls below$45 per barrel over a 30-trading day period. The suspension may be lifted by mutual consent. As ofSeptember 30, 2020 , funding for the initial development phase has not re-started.
Midstream Joint Venture
Ares JV
InFebruary 2018 , our wholly-owned subsidiaryCalifornia Resources Elk Hills, LLC (CREH) entered into a midstream JV with ECR, a portfolio company of Ares. The Ares JV holds the Elk Hills power plant (a 550-megawatt natural gas fired power plant) and a 200 MMcf/d cryogenic gas processing plant. On the Effective Date, as required by the Note Purchase Agreement, CREH transferred its ownership of two low temperature separation plants located at the Elk Hills field to Elk Hills Power. Prior to our Effective Date, we held 50% of the Class A common interest and 95.25% of the Class C common interest in the Ares JV. ECR held 50% of the Class A common interest, 100% of the Class B preferred interest and 4.75% of the Class C common interest. The Ares JV was required to distribute each month its excess cash flow over its working capital requirements first to the Class B holders and then to the Class C common interests, on a pro-rata basis. As contemplated by the terms of the JV, CREH purchased electricity and gas processing services from the Ares JV (subject to certain limitations, including certain geographical limitations) in exchange for monthly capacity payments pursuant to the terms of a Commercial Agreement, the proceeds of which were used by the Ares JV to make distributions as contemplated by the Second Amended and Restated Limited Liability Company Agreement ofElk Hills Power, LLC . CREH also served as the operator of the Ares JV and provided operational and support services in exchange for a monthly fee pursuant to a Master Services Agreement. These agreements became intercompany agreements on the Effective Date and were cancelled as described below. As described above in Business Environment and Outlook and Part I, Item 1 - Financial Statements, Note 1 Chapter 11 Proceedings, we entered into the Settlement Agreement with ECR and Ares which, among other things, changed the liquidation preference for the Class B member interest to$835 million , decreased the preferred return from 13.5% per annum to 9.5% per annum payable at the end of each month, removed the liquidation premium for the Class A common interest and removed the payment of any previously accrued but unpaid preferred distributions plus a make-whole payment that ECR, as the holder of the Class B preferred interests, would otherwise have been entitled to in the event of a redemption transaction. The Settlement Agreement granted us the right (Conversion Right) to acquire all (but not less than all) of the equity interests of Elk Hills Power owned by ECR in exchange for the EHP Notes, Ares Settlement Stock and$2.5 million in cash. The Conversion right was deemed to have been exercised on the Effective Date. Although certain provisions in the Settlement Agreement were not effective until certain conditions were met, such as theBankruptcy Court entering a final order, we determined that the amended terms were substantively different such that the existing Class A common, Class B preferred and Class C common member interests held by ECR were treated as redeemed in exchange for new member interests issued at fair value. 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 GAAP, the return from noncontrolling interest holders was recorded to additional paid-in capital on our condensed consolidated balance sheet as ofSeptember 30, 2020 . However as required by GAAP, the return is included in our earnings per share calculations. See Part I, Item 1 - Financial Statements, Note 10 Earnings per Share for adjustments to net income (loss) attributable to common stock which include a return from noncontrolling interests. 41 -------------------------------------------------------------------------------- We were deemed to have exercised the Conversion Right on the Effective Date and we issued the EHP Notes in the aggregate principal amount of$300 million , Ares Settlement Stock comprising approximately 20.8% (subject to dilution) of the new common stock (Conversion) and$2.5 million in cash. Upon the Conversion, Elk Hills Power became an indirect wholly-owned subsidiary, and Ares and its affiliates ceased to have any direct or indirect interest inElk Hills Power , other than any interest Ares may have indirectly through its interests in the EHP Notes and Ares Settlement Stock. In connection with the Conversion, Elk Hills Power's limited liability company agreement was amended and restated. In connection with the Conversion, on the Effective Date, we entered into a Sponsor Support Agreement dated the Effective Date (Support Agreement) pursuant to which, among other things, the parties agreed that Elk Hills Power will be our primary provider of electricity to, and will be the primary processor of our natural gas produced from, the Elk Hills field, which is already consistent with our current practice. On the Effective Date, in connection with the Conversion, we terminated: (a) the Commercial Agreement, dated as ofFebruary 7, 2018 , by and between Elk Hills Power and CREH and (b) the Master Services Agreement, dated as ofFebruary 7, 2018 , by and between Elk Hills Power and CREH. For more information on the Ares JV, see Part I, Item 1 - Financial Statements, Note 7 Joint Ventures. For more information on the Settlement Agreement, see Part I, Item 1 - Financial Statements, Note 1 Chapter 11 Proceedings. Fixed and Variable Costs Our production costs include (1) variable costs that fluctuate with production levels and (2) fixed costs that typically do not vary with changes in production levels or well counts, especially in the short term. The substantial majority of our near-term fixed costs become variable over the longer term because we manage them based on the field's stage of life and operating characteristics. For example, portions of labor and material costs, energy, workovers and maintenance expenditures correlate to well count, production and activity levels. Portions of these same costs can be relatively fixed over the near term; however, they are managed down as fields mature in a manner that correlates to production and commodity price levels. A certain amount of costs for facilities, surface support, surveillance and related maintenance can be regarded as fixed in the early phases of a program. However, as the production from a certain area matures, well count increases and daily per well production drops, such support costs can be reduced and consolidated over a larger number of wells, reducing costs per operating well. Further, many of our other costs, such as property taxes and oilfield services, are variable and will respond to activity levels and tend to correlate with commodity prices. As a result of the measures taken to address the recent industry downturn, we have demonstrated that we can significantly reduce our operating costs in response to prevailing market conditions. As a result, we continue to believe that a significant portion of our operating costs are variable over the lifecycle of our fields. We actively manage our fields to optimize production and minimize costs. When we see growth in a field, we increase capacities and, similarly, when a field nears the end of its economic life, we manage the costs while it remains economically viable to produce. 42 --------------------------------------------------------------------------------
Production and Prices
The following table sets forth our average net production volumes of oil, NGLs and natural gas per day for the three and nine months endedSeptember 30, 2020 and 2019: Three months ended Nine months ended September 30, September 30, 2020 2019 2020 2019 Oil (MBbl/d) San Joaquin Basin 40 51 42 53 Los Angeles Basin 22 24 25 24 Ventura Basin 2 4 3 4 Total 64 79 70 81 NGLs (MBbl/d) San Joaquin Basin 14 16 14 15 Ventura Basin - - - 1 Total 14 16 14 16 Natural gas (MMcf/d) San Joaquin Basin 142 162 148 163 Los Angeles Basin 2 2 2 2 Ventura Basin 4 4 4 6 Sacramento Basin 20 28 21 29 Total 168 196 175 200 Total Net Production (MBoe/d) 106 128 113 130 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 (Boe) per day. 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. For the three months endedSeptember 30, 2020 compared to the same period in 2019, total daily production decreased by approximately 22 MBoe/d or 17%. The decrease in production related to higher downtime caused by significantly reduced well repair work, as well as the temporary shut-in of certain wells beginning inMarch 2020 , which negatively impacted our net production for the three months endedSeptember 30, 2020 by 3 MBoe/d compared to the same prior-year period. Due to the lower price environment, our PSC-type contracts positively impacted our oil production in the third quarter of 2020 by approximately 1 MBoe/d compared to the same period in 2019. Excluding the effects of shut-in production and PSC-type contracts, our base decline was still in line with our previously disclosed rate of low to mid-teens, which largely resulted from low internal capital investment and well repair work. For the nine months endedSeptember 30, 2020 compared to the same period in 2019, total daily production decreased by approximately 17 MBoe/d or 13%. The decrease in production related to higher downtime caused by significantly reduced well repair work, as well as the temporary shut-in of certain wells beginning inMarch 2020 , and the effect of theMay 2019 partial divestiture of theLost Hills field, which negatively impacted our net production for the nine months endedSeptember 30, 2020 by 3 MBoe/d compared to the same prior-year period. Due to the lower price environment, our PSC-type contracts positively impacted our oil production in the nine months of 2020 by 3 MBoe/d compared to the same period in 2019. Excluding the effects of theLost Hills transaction, shut-in production and PSC-type contracts, our base decline was still in line with our previously disclosed rate of low to mid-teens, which largely resulted from low internal capital investment and well repair work.
With an ongoing gradual increase of well repair work, we believe our base decline rate going forward will gradually return to the low to mid-teens.
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The following tables set forth the average realized prices and price
realizations as a percentage of average Brent, WTI and NYMEX for our products
for the three and nine months ended
Three months ended September 30, 2020 2019 Price Realization Price Realization Oil ($ per Bbl) Brent $ 43.37$ 62.00 Realized price without hedge $ 41.83 96%$ 62.85 101% Settled hedges 0.32 5.56 Realized price with hedge $ 42.15 97%$ 68.41 110% WTI $ 40.93$ 56.45 Realized price without hedge $ 41.83 102%$ 62.85 111% Realized price with hedge $ 42.15 103%$ 68.41 121% NGLs ($ per Bbl) Realized price (% of Brent) $ 25.16 58%$ 23.55 38% Realized price (% of WTI) $ 25.16 61%$ 23.55 42% Natural gas NYMEX ($/MMBtu) $ 1.93$ 2.27 Realized price without hedge ($/Mcf) $ 2.22 115%$ 2.73 120% Settled hedges 0.02 (0.01) Realized price with hedge ($/Mcf) $ 2.24 116%$ 2.72 120% Nine months ended September 30, 2020 2019 Price Realization Price Realization Oil ($ per Bbl) Brent $ 42.53$ 64.74 Realized price without hedge $ 41.27 97%$ 65.03 100% Settled hedges 2.00 3.13 Realized price with hedge $ 43.27 102%$ 68.16 105% WTI $ 38.32$ 57.06 Realized price without hedge $ 41.27 108%$ 65.03 114% Realized price with hedge $ 43.27 113%$ 68.16 119% NGLs ($ per Bbl) Realized price (% of Brent) $ 25.17 59%$ 31.04 48% Realized price (% of WTI) $ 25.17 66%$ 31.04 54% Natural gas NYMEX ($/MMBtu) $ 1.92$ 2.72 Realized price without hedge ($/Mcf) $ 2.05 107%$ 2.82 104% Settled hedges 0.06 (0.01) Realized price with hedge ($/Mcf) $ 2.11 110%$ 2.81 103% 44
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Oil - Brent index and realized prices were lower in both the three and nine months endedSeptember 30, 2020 compared to the same prior-year periods due to the combination of the supply increase caused by the Saudi-Russia price war and the severe demand decline caused by COVID-19. Prices collapsed inMarch 2020 and gradually improved to around the current levels inJune 2020 as a result of the significant production curtailmentsOPEC and other nations implemented in response to COVID-19. NGLs - Prices for NGLs increased slightly for the three months endedSeptember 30, 2020 compared to the same period in 2019 due to improvements in negotiated sales differentials along with stronger NGL values relative to crude. NGL prices declined for the nine months endedSeptember 30, 2020 compared to the same prior-year period as steadyU.S. production exceeded the COVID-19 related decline in demand, causing lower domestic NGL prices. We continued to receive premium prices for NGLs relative to national hub prices. Natural Gas - Our natural gas realized prices were lower in both the three and nine months endedSeptember 30, 2020 than the comparable periods of 2019. The decrease was due to increased nationwide natural gas production and higher inventories across theU.S. primarily due to lower demand resulting from the shelter-in-place orders related to COVID-19 that began inMarch 2020 . Prices were also negatively impacted by lower supply constraints on the SoCalGas system in 2020 compared to the same period in the prior year. Prices began to increase inSeptember 2020 anticipating lower future production as a result of reduced capital investment by producers.
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