What changed in this filing

/stocks — the workspaceLOADING

Item 2. Management’s Discussion and Analysis

2020-08-06 compared with 2020-06-25 · 368 added, 234 removed, 348 unchanged (63% of the section changed)

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Item 2 Management’s Discussion and Analysis of Financial Condition and Results of Operations

Except when the context otherwise requires or where otherwise indicated, all references to ‘‘CRC,’’ the ‘‘company,’’ ‘‘we,’’ ‘‘us’’ and ‘‘our’’ refer to California Resources Corporation and its subsidiaries.

We are an independent oil and natural gas exploration and production company operating properties exclusively within California.

We are incorporated in Delaware and became a publicly traded company on December 1, 2014.

On July 15, 2020, we filed voluntary petitions in the United States Bankruptcy Court for the Southern District of Texas seeking relief under Chapter 11 of Title 11 of the United States Bankruptcy Code 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.

These financial statements do not include any adjustments that might result from the outcome of our going concern uncertainty or the Chapter 11 Cases (as defined below).

There is substantial doubt that we can continue as a going concern if we are not able to complete the plan of reorganization contemplated by the RSA or another plan of reorganization as part of the Chapter 11 Cases as discussed below.

Further, the Chapter 11 Cases could result in a change in the basis of our accounting, which may have a material effect on the carrying value of certain assets and liabilities.

Business Environment and Industry Outlook

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These and other factors make it impossible to predict realized prices reliably.

Prices for oil and gas products in the first quarter of 2020 and in subsequent months 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 related to the shelter-in-place orders, travel restrictions and general economic uncertainty, which negatively impacted crude oil prices.

In the midst of the ongoing COVID-19 pandemic , members of the Organization of the Petroleum Exporting Countries (OPEC and together with Russia and other allied producing countries, OPEC+) and Russia did not extend existing oil production cuts expiring on April 1, 2020, and Saudi Arabia and Russia announced significant increases in crude oil production.

Prices for oil and gas products in the first half of 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 the shelter-in-place orders, travel restrictions and general economic uncertainty, which negatively impacted crude oil prices.

In addition , members of the Organization of the Petroleum Exporting Countries (OPEC) and Russia did not extend existing oil production cuts expiring on April 1, 2020, and Saudi Arabia and Russia announced significant increases in crude oil production.

The unprecedented dual impact of a severe global oil demand decline due to the COVID-19 pandemic repercussions coupled with a substantial increase in supply from Saudi Arabia and Russia resulted in a collapse in crude oil prices.

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In April 2020, oil prices continued to decline precipitously temporarily reaching negative values for spot WTI crude.

In May 2020, oil prices began to recover as producers across the world, including OPEC, Russia, the United States and others started cutting their production levels sharply and announced significant capital reductions , and an easing of shelter-in-place restrictions created partial demand recovery.

However, the current futures forward curve for Brent crude indicates that prices may continue at relatively lower prices 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 in the first quarter of 2020.

In addition to lower average realized prices for the quarter and related negative impact to our liquidity, the sharp drop in commodity prices at the end of the first quarter of 2020 also resulted in an impairment charge of $1.7 billion for the first quarter.

In May 2020 and June 2020, oil prices began to recover as producers across the world, including OPEC, Russia, the United States and others started cutting their production levels sharply and announced significant capital reductions , and an easing of shelter-in-place restrictions created partial demand recovery.

However, demand and pricing may again decline due to the resurgence of the outbreak across parts of the United States and related re-imposition of certain restrictions.

The current futures forward curve for Brent crude indicates that prices may continue at close to current levels but 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 lower commodity prices have continued into the second quarter and are currently expected to remain depressed for an extended period of time based on current futures curves.

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 the severity of the pandemic and actions taken by government authorities to contain the pandemic or actions taken by other producers in response to commodity prices movements, among other things.

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, the severity 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 months ended March 31, 2020 and 2019 and for the months of April and May 2020:

The following table presents the average daily Brent, WTI and NYMEX prices for the three and six months ended June 30, 2020 and 2019:

Three months ended

Month ended April 30,

Month ended May 31,

June 30, Six months ended

2020 2019 2020 2019

Brent oil ($/Bbl) $ 33.27 $ 68.32 $ 42.12 $ 66.11

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MMBtu refers to one million British Thermal Units.

Voluntary Petitions for Relief Under Chapter 11 of the Bankruptcy Code

In light of our significant indebtedness and the unprecedented impact to our financial position resulting from the commodity price environment and the COVID-19 pandemic, combined with continued challenging conditions in the credit and capital markets, we filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Code (Bankruptcy Code) in the United States Bankruptcy Court for the Southern District of Texas, Houston Division (Bankruptcy Court) on July 15, 2020.

The Chapter 11 cases filed by us (Chapter 11 Cases) are being jointly administered under the caption In re California Resources Corporation, et al.

20-33568 (DRJ).

On July 24, 2020, we filed a Joint Plan of Reorganization Under Chapter 11 of the Bankruptcy Code with the Bankruptcy Court.

We continue to operate our business as “debtors-in-possession” (DIP) under the jurisdiction of the Bankruptcy Court and in accordance with the Bankruptcy Code.

To ensure our ability to continue operating in the ordinary course of business and to minimize the effect of the Chapter 11 Cases on our employees, vendors and customers, we filed motions for customary “first day” relief with the Bankruptcy Court.

On July 17, 2020, the Bankruptcy Court entered interim or final orders that included 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.

On July 21, 2020, the Bankruptcy Court approved on a final basis an order designed to assist us in preserving certain tax attributes.

This order established the procedures that certain stockholders and potential stockholders will be required to comply with regarding transfers of, or declarations of worthlessness with respect to, our common stock as well as certain notice obligations.

On July 22, 2020, the Bankruptcy Court approved on an interim basis a motion authorizing us to enter into DIP financing.

The commencement of the Chapter 11 Cases constitutes an event of default that accelerated our obligations under the following agreements:

(i) Credit Agreement, dated as of September 24, 2014, among JPMorgan Chase Bank, N.A., as administrative agent, and the lenders that are party thereto (2014 Revolving Credit Facility), (ii) Credit Agreement, dated as of August 12, 2016, among The 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 of November 17, 2017, among The Bank of America 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).

Additionally, other events of default, including cross-defaults, are present under these debt agreements.

Under the Bankruptcy Code, the creditors under these debt agreements are 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 5 Debt for additional details about our debt.

Restructuring Support Agreement

On July 15, 2020, we entered into a Restructuring Support Agreement which was subsequently amended on July 24, 2020 (RSA).

This RSA contemplates a restructuring plan that establishes a reorganized company with a new capital structure.

The transactions contemplated by the RSA plan include (i) entering into a senior secured superpriority DIP credit facility (Senior DIP Facility) in an aggregate principal amount of up to approximately $483 million, (ii) entering into a junior secured superpriority DIP term loan facility in an aggregate amount of $650 million (Junior DIP Facility), (iii) the implementation of financing upon emergence from bankruptcy, (iv) the issuance of new common stock, and (v) a $450 million equity rights offering, backstopped by certain parties to the RSA.

The following creditors have entered into the RSA:

(i) lenders holding approximately 85% of the outstanding principal amount of loans under the 2017 Credit Agreement, (ii) creditors holding approximately 68% of the aggregate claims arising under the 2016 Credit Agreement, the Second Lien Notes, the 2021 Notes and the 2024 Notes, and (iii) one or more funds, investment vehicles and/or accounts managed or advised by Ares Management LLC (Ares) or its affiliates, including ECR Corporate Holdings L.P.

The transactions contemplated by the RSA, if approved, will result in current holders of our common stock receiving no distribution on account of their claims or interests.

No assurance can be given that the Bankruptcy Court will approve the terms proposed under the RSA.

Debtor-in-Possession Credit Agreements

On July 23, 2020, we entered into (1) a Senior Secured Superpriority DIP Credit Agreement with JPMorgan, as administrative agent, and certain other lenders (Senior DIP Credit Agreement) and (2) a Junior Secured Superpriority DIP Credit Agreement with Alter Domus, as administrative agent, and certain lenders (Junior DIP Credit Agreement).

For more information on our debtor-in-possession credit agreements, see Part I, Item 1 – Financial Statements, Note 5 Debt and Liquidity and Capital Resources below.

Ares JV Settlement Agreement

On July 15, 2020, prior to the commencement of the Chapter 11 Cases, we and certain affiliates of Ares, including ECR, entered into a settlement and assumption agreement (Settlement Agreement).

On July 17, 2020, the Bankruptcy Court entered an order approving the Settlement Agreement on an interim basis pending a final hearing.

Upon entry of a final order by the Bankruptcy Court, we will be granted the right to acquire all of the equity interests of the Ares JV owned by ECR in exchange for secured notes, cash and common stock upon emergence from bankruptcy.

We have also agreed to certain covenants and amendments to the Ares JV limited liability company agreement.

The Settlement Agreement may be terminated in certain limited circumstances.

For more information on the Ares JV, see Part I, Item 1 – Financial Statements, Note 6 Joint Ventures.

Going Concern Analysis and Recent Developments

Our spin–off from Occidental Petroleum Corporation (Occidental) in December 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 a vast majority of receivables, our debt peaked at approximately $6.8 billion in May 2015.

Since then, we have engaged in a series of assets sales, joint ventures, debt exchanges, tenders and other financing transactions to reduce our overall debt and improve our balance sheet.

As of March 31, 2020, we had reduced outstanding debt to approximately $4.9 billion, a substantial portion of which will mature in 2021.

Our significant indebtedness, the unprecedented impact to our financial position resulting from the commodity price decreases due to the COVID-19 pandemic and actions of foreign producers, and the continued challenging conditions in the credit and capital markets raise substantial doubt regarding our ability to continue as a going concern.

As discussed further below, we are actively discussing the terms of a restructuring with our creditors and other stakeholders with the objective of enabling us to continue operations better positioned to capitalize on our asset base and operating capabilities.

However, there can be no assurances that we will be able to successfully restructure our indebtedness and no assurances can be given as to what value, if any, will be ascribed to each of our securities or what types or amounts of distributions, if any, our various stakeholders would receive in any restructuring.

Any restructuring could result in holders of certain liabilities and/or securities, including our common stock, receiving no distribution on account of their claims or interest.

On February 20, 2020, we launched offers to exchange a significant portion of our Second Lien Notes and our 5.5% Senior Notes due 2021 (2021 Notes) and 6% Senior Notes due 2024 (2024 Notes) into interests in an entity that would hold a term royalty interest in certain of our oil and natural gas assets or new term loans and warrants to purchase our common stock.

If the offers were fully subscribed, we expected that the transactions would have reduced our net debt by approximately $1 billion if successfully completed.

On March 16, 2020, we announced the termination of the offers as a result of developments in the commodity and financial markets at that time that rendered the offers inadvisable and impractical.

On May 15, 2020, we did not make an interest payment of approximately $4.3 million on our 2024 Notes.

The indenture governing the 2024 Notes provides for a 30-day grace period and the payment was subsequently made on June 12, 2020.

On May 29, 2020, we did not pay approximately $51 million in the aggregate of interest due under (i) our $1.3 billion credit agreement with The Bank of New York Mellon Trust Company, N.A., as administrative agent, and certain other lenders (2017 Credit Agreement), and (ii) our $1 billion credit agreement with The Bank of New York Mellon Trust Company, N.A., as administrative agent, and certain other lenders (2016 Credit Agreement).

Our failure to make those interest payments constituted events of default under our 2017 Credit Agreement and 2016 Credit Agreement and, as a result of cross default, under our Credit Agreement with JPMorgan Chase Bank, N.A., as administrative agent, and certain other lenders (2014 Revolving Credit Facility).

On June 2, 2020, we entered into forbearance agreements (Forbearance Agreements) with (i) certain lenders of a majority of the outstanding principal amount of the loans under the 2014 Revolving Credit Facility, (ii) certain lenders of a majority of the outstanding principal amount of the loans under the 2016 Credit Agreement, and (iii) certain lenders of a majority of the outstanding principal amount of the loans under the 2017 Credit Agreement.

Pursuant to the Forbearance Agreements, the lenders who are parties to the Forbearance Agreements agreed to forbear from exercising any remedies under the 2014 Revolving Credit Facility, 2016 Credit Agreement and 2017 Credit Agreement with respect to our failure to make the aforementioned interest payments, through the earlier of June 14, 2020 or an event of termination as set forth in the Forbearance Agreements.

On June 12, 2020, we amended the Forbearance Agreements to extend the forbearance period to June 30, 2020.

The Forbearance Agreements include a requirement that we maintain an aggregate book cash balance of not less than $40 million for more than three consecutive business days.

On June 15, 2020, we did not make an interest payment of approximately $72.3 million on our 8% Senior Secured Second Lien Notes due 2022 (Second Lien Notes).

The indenture governing the Second Lien Notes provides for a 30-day grace period, which will expire on July 15, 2020.

A failure to pay the interest within the 30-day grace period would constitute an event of default under this indenture and cross defaults under our other debt instruments and agreements.

We are actively discussing the terms of a restructuring with our creditors and other stakeholders with the objective of reaching an agreement before the forbearance period under the Forbearance Agreements expires on June 30, 2020.

There can be no assurances that an agreement regarding a restructuring will be reached by the end of the forbearance period or at all or that we will be able to successfully restructure our indebtedness.

In addition, no assurances can be given as to what values, if any, will be ascribed to each of our securities or what types or amounts of distributions, if any, our various stakeholders would receive in any restructuring.

Any restructuring could result in holders of certain liabilities and/or securities, including common stock, receiving no distribution on account of their claims or interest.

See Part II, Item 1A – Risk Factors , below for further discussion regarding risks related to our ability to continue as a going concern.

Our spin–off from Occidental Petroleum Corporation (Occidental) on November 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 in May 2015.

Since then, we have engaged in a series of assets sales, joint ventures, debt exchanges, tenders and repurchases and other financing transactions to reduce our overall debt and improve our balance sheet.

As of June 30, 2020, we had reduced our outstanding debt to approximately $5.1 billion, a substantial portion of which would have matured in 2021.

We currently expect that our cash flows, cash on hand and financing available through our DIP credit agreements should provide sufficient liquidity during the pendency of the Chapter 11 Cases.

However, for the duration of the Chapter 11 Cases, our operations and our ability to develop and execute our business plan are subject to a high degree of risks and uncertainty associated with the Chapter 11 proceedings.

The outcome of the Chapter 11 Cases is also subject to a high degree of uncertainty and is dependent upon factors that are outside of our control, including actions of the Bankruptcy Court, our creditors, and Ares.

There can be no assurance that we will confirm and consummate the plan under the RSA or complete another plan of reorganization with respect to the Chapter 11 proceedings.

For the duration of the Chapter 11 Cases, our operations and ability to develop and execute our business plan are subject to the risks and uncertainties associated with the Chapter 11 Cases.

See Part II, Item 1A – Risk Factors , below for further discussion of these risks and risks related to our ability to continue as a going concern.

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 early March, in response to the rapid fall in commodity prices, 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.

In response to the rapid fall in commodity prices, 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 $3 million in the second quarter of 2020.

We also monetized all of our crude oil hedges for April 2020 forward with our counterparties, except for certain hedges held by our joint venture with Benefit Street Partners (BSP JV), for approximately $63 million to enhance our liquidity.

We shut in certain marginal wells to reduce operating costs which curtailed average gross production volumes by approximately 7 MBoe/d and average net production volumes by 6 MBoe/d in May 2020.

As part of our operational efficiency measures, we also evaluated our diverse portfolio and our various production mechanisms with a focus on wells with higher operating costs.

We shut in certain wells to reduce operating costs which curtailed average gross production volumes by approximately 6 MBoe/d and average net production volumes by 5 MBoe/d during the second quarter of 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, our current operating expense run rate is below $45 million per month compared to the first quarter average of $64 million per month.

As a result of these actions, as well as further cost rationalization and streamlining efforts coupled with lower activity levels, our current operating expense run rate is below $45 million per month compared to the first quarter average of $64 million per month.

At our current level of capital investment, we anticipate production will continue to decline at a moderate pace through the remainder of the year.

In early March 2020, we 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 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, including finance and accounting teams, worked remotely beginning in March 2020 and continuing into June 2020, when a phased return to the office began.

In addition, on April 6, 2020, we implemented reduced work hours for nearly all of our office employees.

This temporary arrangement ended at the end of May 2020.

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, including finance and accounting teams, worked remotely beginning in March 2020.

In June 2020, we began a phased return to the office, focused on those employees for whom remote work was not feasible.

In addition, on April 6, 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 in May 2020.

These reductions were made in an effort to preserve liquidity after the further deterioration of commodity prices following the outbreak of COVID-19.

Our operational employees and contractors have been classified as an essential critical infrastructure workforce by government authorities and continue to work in their plant and field locations under our COVID-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.

Our operational employees and contractors and certain support personnel have been classified as an essential critical infrastructure workforce by government authorities and continue to work in their plant, rig, field and office locations under our COVID-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.

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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 have the flexibility to shut in wells while retaining our oil and gas leases which are held by production.

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 in California, we have undertaken initiatives to obtain additional value from our surface acreage, including pursuing renewable energy opportunities, agricultural activities and other commercial uses.

Our share of production and reserves from operations in the Wilmington field is subject to contractual arrangements similar to production-sharing contracts (PSCs) that are in effect through the economic life of the assets.

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However, our net economic benefit is greater when product prices are higher.

These contracts represented approximately 18% of our net production for the quarter ended March 31, 2020 .

These contracts represented approximately 20% of our net production for the quarter ended June 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.

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Crude Oil — We sell nearly all of our crude oil into the California refining markets, which offer relatively favorable pricing for comparable grades relative to other U.S.

Substantially all of our crude oil production is connected, via our gathering systems, to third-party pipelines and California refining markets and we have not encountered any issues with storage or reaching these markets during the recent industry downturn.

Substantially all of our crude oil production is connected, via our gathering systems, to third-party pipelines and California 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.

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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 expired, we made a one-time payment of $20 million in April 2020.

In connection with another pipeline delivery contract that we assumed from Occidental, we made a one-time deficiency payment of $20 million in April 2020 when the contract expired.

We sell virtually all of our NGLs using index-based pricing.

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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 assurances that our hedging programs will be adequate to accomplish our objectives.

We can give no assurance that our hedging programs will be adequate to accomplish our objectives.

In early March 2020, in response to the rapid fall in commodity prices, we monetized all of our crude oil hedges in place for April 2020 forward with our counterparties, except for certain hedges held by our BSP JV, for approximately $63 million to enhance our liquidity.

As a result, we did not have any commodity hedges that we would benefit from after the end of the first quarter.

As of June 30, 2020, we did not have any commodity hedges covering our share of production.

The Senior DIP Credit Agreement requires us to enter into hedging arrangements covering at least 25% of our share of expected crude oil production for the next twelve months.

On July 24, 2020, we entered into various derivative instruments through July 2021 to satisfy this requirement.

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 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 in California, we have undertaken initiatives to unlock additional value from our surface acreage, including pursuing renewable energy opportunities, agricultural activities and other commercial uses.

Development 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.

The following table summarizes the cumulative investment through March 31, 2020 by our development joint venture partners, before transaction costs:

The following table summarizes the cumulative investment through June 30, 2020 by our development joint venture partners, before transaction costs:

Cumulative Investment through

March 31, 2020

June 30, 2020

(in millions)

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If prices remain below the threshold for over 100 consecutive trading days, the development phase may be terminated by us, subject to agreement by Alpine.

In February 2018, our wholly owned subsidiary California Resources Elk Hills, LLC (CREH) entered into a midstream joint venture 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.

We hold 50% of the Class A common interests and 95.25% of the Class C common interests in the Ares JV.

ECR holds 50% of the Class A common interests, 100% of the Class B preferred interests and 4.75% of the Class C common interests.

As contemplated by the terms of the joint venture, CREH purchases electricity, steam 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 will be used by the Ares JV to make distributions as contemplated by the Second Amended and Restated Limited Liability Company Agreement of Elk Hills Power, LLC.

CREH also serves as the operator of the Ares JV and provides operational and support services in exchange for a monthly fee pursuant to a Master Services Agreement.

For more information on the Ares JV, see Part I, Item 1 – Financial Statements, Note 6 Joint Ventures.

For more information on the Settlement Agreement, see Part I, Item 1 – Financial Statements, Note 1 Basis of Presentation.

Fixed and Variable Costs

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Production and Prices

The following table sets forth our average net production volumes of oil, NGLs and natural gas per day for the three months ended March 31, 2020 and 2019 :

The following table sets forth our average net production volumes of oil, NGLs and natural gas per day for the three and six months ended June 30, 2020 and 2019:

Three months ended

June 30, Six months ended

2020 2019 2020 2019

San Joaquin Basin 41 52 44 54

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Ventura Basin 2 4 3 4

Total 70 79 73 82

NGLs (MBbl/d)

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Ventura Basin — 1 — 1

Total 13 16 14 15

Natural gas (MMcf/d)

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Sacramento Basin 21 30 22 29

Total 174 203 179 202

Total Net Production (MBoe/d) 112 129 117 131

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Barrels of oil equivalence does not necessarily result in price equivalence.

For the three months ended March 31, 2020 compared to the same period in 2019, total daily production decreased by approximately 12 MBoe/d or 9% .

The decrease in production largely represented base decline resulting from low internal capital investment during the last 12 months.

In addition, our May 2019 divestiture of a 50% working interest in certain zones within our Lost Hills field resulted in a decrease of approximately 2 MBoe/d in 2020 compared to the prior comparative quarter.

Our PSC-type contracts positively impacted our oil production in 2020 by over 2 MBoe/d compared to 2019.

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 months ended March 31, 2020 and 2019 :

Three months ended March 31,

For the three months ended June 30, 2020 compared to the same period in 2019, total daily production decreased by approximately 17 MBoe/d or 13%.

The decrease in production largely represented base decline resulting from low internal capital investment, the temporary shut in of certain wells beginning in March 2020 and the effect of the May 2019 partial divestiture of the Lost Hills field.

The shut in wells and the Lost Hills divestiture reduced our second quarter 2020 net production by 7 MBoe/d.

Due to the lower price environment, our PSC-type contracts positively impacted our oil production in the second quarter of 2020 by over 5 MBoe/d compared to the same period in 2019.

Excluding the effect of the Lost Hills transaction, the shut in wells and the PSC effects, our base decline was below 12%, which is in line with our range of stated base decline rates.

For the six months ended June 30,2020 compared to the same period in 2019, total daily production decreased by approximately 14 MBoe/d or 11%.

The decrease in production largely represented base decline resulting from low internal capital investment, shut in production and the effect of the May 2019 partial divestiture of the Lost Hills field.

The shut in wells and the Lost Hills divestiture reduced our net production for the six months ended June 30, 2020 by 7 MBoe/d.

Due to the lower price environment, our PSC-type contracts positively impacted our oil production in the first half of 2020 by over 4 MBoe/d compared to the same period in 2019.

Excluding the effect of the Lost Hills transaction, the shut in wells and the PSC effects, our base decline was approximately 8%.

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 six months ended June 30, 2020 and 2019:

Three months ended June 30,

Price Realization Price Realization

Oil ($ per Bbl)

Brent $ 33.27 $ 68.32

Realized price without hedge $ 30.27 91% $ 68.77 101%

Settled hedges 0.55 1.89

Realized price with hedge $ 30.82 93% $ 70.66 103%

WTI $ 27.85 $ 59.82

Realized price without hedge $ 30.27 109% $ 68.77 115%

Realized price with hedge $ 30.82 111% $ 70.66 118%

NGLs ($ per Bbl)

Realized price (% of Brent) $ 21.05 63% $ 27.82 41%

Realized price (% of WTI) $ 21.05 76% $ 27.82 47%

NYMEX ($/MMBtu) $ 1.77 $ 2.66

Realized price without hedge ($/Mcf) $ 1.65 93% $ 2.33 88%

Settled hedges 0.08 0.03

Realized price with hedge ($/Mcf) $ 1.73 98% $ 2.36 89%

Six months ended June 30, 2020

Price Realization Price Realization

Oil ($ per Bbl)

Brent $ 42.12 $ 66.11

Realized price without hedge $ 41.02 97% $ 65.97 100%

Settled hedges 2.74 1.93

Realized price with hedge (a)

$ 43.76 104% $ 67.90 103%

WTI $ 37.01 $ 57.36

Realized price without hedge $ 41.02 111% $ 65.97 115%

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Realized price with hedge ($/Mcf) $ 2.05 107% $ 2.86 97%

March 31, 2020 prices exclude the effect of $63 million of proceeds received in the first quarter of 2020 from settling derivative contracts with counterparties prior to maturity.

Oil — Brent index and realized prices were lower in the three months ended March 31, 2020 compared to the same prior-year period due to the combination of the supply increase caused by the Saudi-Russia price war and the severe demand decline caused by COVID-19 that began in March 2020.

During April 2020, Brent index prices and our realizations further deteriorated to $26.63 and 79%, respectively, and recovered slightly in May 2020 to $32.41 and 93%, respectively.

NGLs — Prices for NGLs decreased from the same prior-year period as supply associated with high gas-producing basins outpaced steady demand, causing lower domestic NGL prices in the first quarter of 2020.

(a) Prices for the first six months of 2020 exclude the effect of $63 million of proceeds received in the first quarter of 2020 from settling derivative contracts with counterparties prior to maturity.

Oil — Brent index and realized prices were lower in both the three and six months ended June 30, 2020 compared to the same prior-year period due to the combination of the supply increase caused by the Saudi-Russia price war and the severe demand decline caused by COVID-19.

Further, our realizations without hedge were significantly affected in the three months ended June 30, 2020, and to a lesser extent in the six months ended June 30, 2020, primarily due to the unprecedented global oversupply of oil and Saudi Arabia's price cuts for oil to the U.S.

and other markets in April 2020.

These two events led to lower crude realizations for foreign oil imported into California and depressed prices for native California crude.

We continue to receive premium prices for NGLs relative to national hub prices.

Natural Gas — Our natural gas realized prices were lower in the three months ended March 31, 2020 than the comparable period of 2019.

The decrease was due to increased nationwide natural gas production, opposite of last year’s local supply constraints, resulting in lower prices across the country, and decreased demand resulting from the shelter-in-place order related to COVID-19 that began in March 2020.

Natural Gas — Our natural gas realized prices were lower in both the three and six months ended June 30, 2020 than the comparable periods of 2019.

The decrease was due to increased nationwide natural gas production and lower demand resulting from the shelter-in-place orders related to COVID-19 that began in March 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.

Balance Sheet Analysis

The following table sets forth changes in our balance sheet between March 31, 2020 and December 31, 2019 :

The following table sets forth changes in our balance sheet between June 30, 2020 and December 31, 2019:

June 30, December 31,

(in millions)

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Property, plant and equipment, net

Current maturities of long-term debt

$ 4,449 $ 6,352

Other assets $ 78 $ 115

Current portion of long-term debt $ 5,083 $ 100

Current deferred gain and issuance costs, net $ 125 $ —

Accounts payable $ 196 $ 296

6 unchanged sentences

Equity attributable to noncontrolling interests $ 76 $ 93

Cash — Cash at March 31, 2020 and December 31, 2019 included restricted cash of $10 million and $3 million , respectively.

Cash increased in the first quarter of 2020 primarily as a result of monetizing our crude oil hedges in place for April 2020 forward (other than hedges held by our BSP JV).

Cash — Cash at June 30, 2020 and December 31, 2019 included restricted cash of $21 million and $3 million, respectively.

See Liquidity and Capital Resources for our cash flow analysis.

Trade receivables — The decrease in trade receivables was largely driven by lower production, realized product prices and trading activities in the first quarter of 2020 compared to the fourth quarter of 2019.

Trade receivables — The decrease in trade receivables was largely driven by lower realized product prices and lower production volumes in June 2020 compared to December 2019.

Other current assets, net — The decrease in other current assets, net was primarily due to the sale of our crude oil hedge positions resulting in a decrease in the fair value of the current portion of our derivative assets.

Additionally, in March 2020, we recorded an $11 million impairment on capital investments which were recovered from our joint interest partners solely from production.

The dramatic commodity price declines at the end of the quarter resulted in changes to our cash flow forecasts and ultimate collectability of these development costs under our PSCs.

Property, plant and equipment, net — The decrease in property, plant and equipment, net primarily reflected the $1.7 billion impairment of certain of our proved and unproved properties, depreciation, depletion, and amortization (DD&A) and sales of certain royalty interests and non-core assets in the first quarter of 2020 as a result of the sharp decrease in commodity prices.

Additionally, in March 2020, we recorded an $11 million impairment on capital investments to be recovered from our joint interest partners solely from production.

Property, plant and equipment, net — The decrease in property, plant and equipment, net primarily reflected the $1.7 billion impairment of certain of our proved and unproved properties recorded in the first quarter of 2020, depreciation, depletion, and amortization (DD&A) and to a lesser extent sales of certain royalty interests and non-core assets in the first quarter of 2020.

The decrease was partially offset by capital investments including the planned major maintenance at our Elk Hills power plant.

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Other assets — Other assets decreased primarily due to utilizing parts for the planned major maintenance of our Elk Hills power plant as well as a decrease in operating lease assets due to releasing drilling rigs in the first quarter of 2020.

Current maturities of long-term debt — Current maturities of long-term debt decreased by $100 million reflecting payment in full of our 2020 Senior Notes due in January 2020.

Accrued liabilities — The decrease in accrued liabilities primarily reflected bonus payments made in the first quarter of 2020 as well as the timing of payments to our joint venture partners and interest payments to our lenders.

Mezzanine equity — Mezzanine equity predominantly reflected the carrying amount of the Class A common and Class B preferred interests held by the noncontrolling interest partner in our midstream JV.

Equity attributable to common stock — Equity attributable to common stock decreased primarily as a result of the net loss in the three months ended March 31, 2020 .

Current portion of long-term debt — The increase in the current portion of long-term debt was a result of the reclassification of our long-term debt to current as described in Part I, Item 1 – Financial Statements, Note 5 Debt .

Current portion of deferred gain and issuance costs, net — The increase in the current portion of deferred gain and issuance costs, net was primarily a result of reclassifying capitalized costs associated with our long-term debt to current.

Accounts payable — The decrease in accounts payable was due to lower amounts payable to vendors following the reduction of our capital plan in the second quarter of 2020 compared to the fourth quarter of 2019.

Accrued liabilities — The increase in accrued liabilities primarily related to an increase in accrued interest as a result of our failure to make certain interest payments and property tax payments during the second quarter of 2020 compared to balances due as of the fourth quarter of 2019.

These amounts were partially offset by the bonus payments to employees made in the first quarter of 2020 with respect to 2019 performance as well as a decrease in activities of the Alpine JV following their suspension of further capital funding due to low commodity prices.

Long-term debt — The decrease in long-term debt resulted from the reclassification of long-term debt to current as of June 30, 2020.

Deferred gain and issuance costs, net — The decrease in deferred gain and issuance costs, net resulted from the reclassification of costs associated with our long-term debt to current as of June 30, 2020.

Mezzanine equity — The increase in mezzanine equity primarily resulted from the preferred return to the Class B interests held by the noncontrolling interest partner in our Ares JV.

Equity attributable to common stock — Equity attributable to common stock decreased primarily as a result of the net loss in the six months ended June 30, 2020.

Statements of Operations Analysis

Results of Oil and Gas Operations

The following represents key operating data for our oil and gas operations, excluding certain corporate items, on a per Boe basis for the three months ended March 31, 2020 and 2019 :

The following represents key operating data for our oil and gas operations, excluding certain corporate items, on a per Boe basis for the three and six months ended June 30, 2020 and 2019:

Three months ended

June 30, Six months ended

2020 2019 2020 2019

Production costs $ 12.42 $ 19.62 $ 14.99 $ 19.54

Production costs, excluding effects of PSC-type contracts (a)

$ 12.00 $ 17.98 $ 14.33 $ 17.99

Field general and administrative expenses (b)

$ 1.17 $ 1.28 $ 1.08 $ 1.27

Field depreciation, depletion and amortization (b)

$ 7.82 $ 9.55 $ 8.98 $ 9.47

Field taxes other than on income (b)

As described in the Operations section, the reporting of our PSC-type contracts creates a difference between reported production costs, which are for the full field, and reported volumes, which are only our net share, inflating the per barrel production costs.

$ 2.84 $ 2.39 $ 2.96 $ 2.53

(a) As described in the Operations section, the reporting of our PSC-type contracts creates a difference between reported production costs, which are for the full field, and reported volumes, which are only our net share, inflating the per barrel production costs.

These amounts represent our production costs after adjusting for this difference.

Excludes corporate expenses.

(b) Excludes corporate expenses.

Consolidated Results of Operations

The following represents key operating data for our consolidated operations for the three months ended March 31, 2020 and 2019 :

The following represents key operating data for our consolidated operations for the three and six months ended June 30, 2020 and 2019:

Three months ended

June 30, Six months ended

2020 2019 2020 2019

(in millions)

Oil and natural gas sales $ 245 $ 578 $ 675 $ 1,179

Net derivative gain (loss) from commodity contracts

Net derivative (loss) gain from commodity contracts (4) 21 75 (68)

Other revenue 35 54 99 232

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Other non-operating expenses (47) (3) (61) (10)

Loss before income taxes

(Loss) income before income taxes (247) 41 (1,992) (3)

Income tax — — — —

Net (loss) income (247) 41 (1,992) (3)

Net income attributable to noncontrolling interests (24) (29) (75) (52)

Net loss attributable to common stock

Net (loss) income attributable to common stock $ (271) $ 12 $ (2,067) $ (55)

Adjusted net (loss) income (a)

$ (202) $ (14) $ (210) $ 17

Adjusted EBITDAX (a)

$ 19 $ 255 $ 270 $ 556

Effective tax rate — % — % — % — %

Adjusted net (loss) income and adjusted EBITDAX are non-GAAP measures.

See the Non-GAAP Financial Measures section below for reconciliations to their nearest GAAP measures.

Three months ended March 31, 2020 vs.

Oil and natural gas sales — Oil and natural gas sales decreased 28% , or $171 million , for the three months ended March 31, 2020 compared to the same period of 2019 due to lower realized prices and production as reflected in the following table:

(a) Adjusted net (loss) income and adjusted EBITDAX are non-GAAP measures.

See the Non-GAAP Financial Measures section below for reconciliations to their nearest U.S.

GAAP equivalent.

Three months ended June 30, 2020 vs.

Oil and natural gas sales — Oil and natural gas sales decreased 58%, or $333 million, for the three months ended June 30, 2020 compared to the same period of 2019 due to lower realized prices and production as reflected in the following table:

Oil NGLs Natural Gas Total

(in millions)

Three months ended March 31, 2019

Three months ended June 30, 2019 $ 496 $ 39 $ 43 $ 578

Changes in realized prices (279) (10) (13) (302)

Changes in production (24) (3) (4) (31)

Three months ended March 31, 2020

Three months ended June 30, 2020 $ 193 $ 26 $ 26 $ 245

See Production and Prices for index prices, realizations and production volumes for comparative periods.

The effect of settled hedges is not included in the table above.

Net proceeds from settled hedges were $35 million for the three months ended March 31, 2020 compared to net proceeds of $14 million for the same period of 2019 , which had a positive impact of $21 million on our total revenue between periods.

Including the effect of settled hedges and proceeds from derivative contracts sold in the first quarter of 2020, our oil and natural gas revenue decreased by $87 million or 14% compared to the same prior-year period.

Net derivative gain (loss) from commodity contracts — Net derivative gain from commodity contracts was $79 million for the three months ended March 31, 2020 compared to a loss of $89 million in the same period of 2019 , representing an overall change of $168 million as reflected in the following table.

Net proceeds from settled hedges were $5 million for the three months ended June 30, 2020 compared to net proceeds of $14 million for the same period of 2019, which had a negative impact of $9 million on our total revenue between periods.

Including the effect of settled hedges, our oil and natural gas revenue decreased by $342 million or 58% compared to the same prior-year period.

Net derivative (loss) gain from commodity contracts — Net derivative loss from commodity contracts was $4 million for the three months ended June 30, 2020 compared to a gain of $21 million in the same period of 2019, representing an overall change of $25 million as reflected in the following table.

Non-cash changes in the fair value of our outstanding derivatives resulted from the positions held at the end of each period as well as the relationship between contract prices, volatility, time to expiration and the associated forward curves.

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Non-cash derivative (loss) gain, excluding noncontrolling interest $ — $ 4

Non-cash derivative (loss) gain, noncontrolling interest (9) 3

Total non-cash changes (9) 7

Net proceeds on settled commodity derivatives 5 14

Net derivative (loss) gain $ (4) $ 21

Other revenue — The decrease in other revenue of $19 million to $35 million for the three months ended June 30, 2020 compared to $54 million in the same period of 2019 was primarily due to lower natural gas trading activity.

Production costs — Production costs for the three months ended June 30, 2020 decreased $103 million to $127 million compared to $230 million for the same period of 2019, resulting in a 45% decrease.

The decrease was primarily attributable to efficiencies and streamlining of our operations, along with our October 2019 workforce reduction and reduced work schedules during the months of April and May 2020.

The operating costs of shut in wells, as well as lower activity levels in response to the current environment, such as downhole maintenance, also contributed to the decrease.

General and administrative expenses — Our general and administrative (G&A) expenses decreased $10 million to $69 million for the three months ended June 30, 2020 compared to $79 million for the same period of 2019, primarily due to lower cash-settled stock-based compensation expense resulting from a decline in our stock price between comparative periods.

Additionally, G&A expenses were lower in 2020 as a result of cost savings attributable to our October 2019 workforce reduction and reduced work hours and reduced management salaries in response to the industry downturn and the COVID-19 pandemic in the second quarter of 2020 partially offset by additional compensation expense related to the modification of our 2020 variable compensation programs in May 2020.

See Part I, Item 1 – Financial Statements, Note 15 Compensation Plans for more information.

Depreciation, depletion and amortization — The decrease in depreciation, depletion, and amortization of $33 million to $88 million in the second quarter of 2020 compared to $121 million in 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.

Other expenses, net — The increase in other expenses of $12 million to $67 million for the three months ended June 30, 2020 compared to $55 million for the same period of 2019 was largely the result of a one-time payment of $20 million made in April 2020 in connection with an expiring pipeline delivery contract partially offset by a decrease in natural gas trading purchases.

Interest and debt expense, net — Interest and debt expense, net decreased $13 million to $85 million in the second quarter of 2020 compared to $98 million in the same period of 2019 due to the repayment of the 2020 Senior Notes in January 2020, the 2019 repurchases of our Second Lien Notes and lower variable interest rates on our borrowings under the 2016 Credit Agreement and 2017 Credit Agreement.

Net gain on early extinguishment of debt — We did not have a net gain on early extinguishment of debt for the three months ended June 30, 2020, which is a decrease of $20 million from the same period in 2019.

The decrease was due to a lack of open market purchases in the second quarter of 2020.

Other non-operating expense — Other non-operating expense increased $44 million to $47 million for the three months ended June 30, 2020 compared to $3 million in the same period for 2019.

The increase was primarily a result of professional fees and costs associated with the preparation of the Chapter 11 Cases.

Six months ended June 30, 2020 vs 2019

Oil and natural gas sales — Oil and natural gas sales decreased 43%, or $504 million, for the six months ended June 30, 2020 compared to the same period of 2019 due to lower realized prices and production as reflected in the following table:

Oil NGLs Natural Gas Total

(in millions)

Six months ended June 30, 2019 $ 976 $ 98 $ 105 $ 1,179

Changes in realized prices (371) (27) (33) (431)

Changes in production (56) (9) (8) (73)

Six months ended June 30, 2020 $ 549 $ 62 $ 64 $ 675

See Production and Prices for index prices, realizations and production volumes for comparative periods.

The effect of settled hedges is not included in the table above.

Net proceeds from settled hedges were $40 million for the six months ended June 30, 2020, excluding the effect of our derivative contracts sold prior to maturity in the first quarter of 2020, compared to net proceeds of $28 million for the same period of 2019, which had a positive impact of $12 million on our total revenue between periods.

Including the effect of settled hedges and proceeds from derivative contracts sold in the first quarter of 2020, our oil and natural gas revenue decreased by $429 million or 36% compared to the same prior-year period.

Net derivative gain (loss) from commodity contracts — Net derivative gain from commodity contracts was $75 million for the six months ended June 30, 2020 compared to a loss of $68 million in the same period of 2019, representing an overall change of $143 million as reflected in the following table.

Six months ended

(in millions)

Non-cash derivative (loss) gain, excluding noncontrolling interest $ (35) $ (93)

Non-cash derivative gain (loss), noncontrolling interest 7 (3)

3 unchanged sentences

Net derivative gain (loss) $ 75 $ (68)

Other revenue — The decrease in other revenue of $114 million to $64 million for the three months ended March 31, 2020 compared to $178 million in the same period of 2019 was due to lower natural gas trading activity and lower electricity sales due to a planned major maintenance at the Elk Hills power plant in 2020.

Production costs — Production costs for the three months ended March 31, 2020 decreased $41 million to $192 million compared to $233 million for the same period of 2019 , resulting in an 18% decrease.

The decrease was primarily attributable to reduced downhole and surface maintenance activity across our fields, lower prices for natural gas used in our steamfloods, cost savings attributable to our October 2019 organizational redesign and additional cost saving initiatives implemented in March 2020 in response to lower commodity prices.

Additionally, our production costs related to the Lost Hills field declined by approximately $8 million in the first quarter of 2020 from the same period of 2019 as a result of our sale of a 50% working interest in the field in May 2019.

Our current operating expense run rate is below $45 million per month compared to the first quarter 2020 average of $64 million per month.

General and administrative expenses — Our general and administrative (G&A) expenses decreased $23 million to $60 million for the three months ended March 31, 2020 compared to $83 million for the same period of 2019 , primarily due to lower cash-settled stock-based compensation expense resulting from a decline in our stock price between comparative periods.

Additionally, G&A expenses were lower in 2020 as a result of cost savings attributable to our October 2019 organizational redesign and a reduced performance factor for certain performance-based awards.

Asset impairments — We performed impairment tests at March 31, 2020 due to the sharp drop in commodity prices at the end of the first quarter of 2020 .

As a result, in the first quarter of 2020 , we recorded an impairment charge of $1.7 billion, of which $1.5 billion related to certain of our proved properties and $228 million related to unproved acreage that we no longer intend to pursue.

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 based on management's expectations for the future considering the current environment.

Inputs included estimates of future oil and natural gas production, index prices based on forward curves until the market became illiquid and internally generated price forecasts thereafter, pricing adjustments for differentials, estimated future operating costs and capital development plans based on the embedded price assumptions.

We used a market-based weighted average cost of capital to discount the future net cash flows.

Other revenue — The decrease in other revenue of $133 million to $99 million for the six months ended June 30, 2020 compared to $232 million in the same period of 2019 was due to lower natural gas trading activity and lower electricity sales due to a planned major maintenance at the Elk Hills power plant in 2020.

Production costs — Production costs for the six months ended June 30, 2020 decreased $144 million to $319 million compared to $463 million for the same period of 2019, resulting in a 31% decrease.

The operating costs of shut in wells, as well as lower activity levels in response to the current environment, such as downhole maintenance, also contributed to the decrease.

General and administrative expenses — Our general and administrative (G&A) expenses decreased $33 million to $129 million for the six months ended June 30, 2020 compared to $162 million for the same period of 2019, primarily due to lower cash-settled stock-based compensation expense resulting from a decline in our stock price between comparative periods.

Additionally, G&A expenses were lower in 2020 as a result of cost savings attributable to our October 2019 workforce reduction and reduced work hours and reduced management salaries in response to the industry downturn and the COVID-19 pandemic in the second quarter of 2020 partially offset by an increase in compensation expense due to changes to our 2020 compensation program.

Depreciation, depletion and amortization — The decrease in depreciation, depletion, and amortization of $32 million to $207 million in the first half of 2020 compared to $239 million in 2019 was predominately due to the asset impairment recorded in the first quarter of 2020.

Asset impairments — In the first quarter of 2020, we recorded an impairment charge of $1.7 billion, of which $1.5 billion related to certain of our proved properties and $228 million related to unproved acreage that we no longer intend to pursue.

No asset impairments were recorded in the second quarter of 2020.

For further detail about the asset impairment, see Part I, Item 1 – Financial Statements, Note 14 Asset Impairments .

Other expenses, net — The decrease in other expenses of $79 million to $69 million for the three months ended March 31, 2020 compared to $148 million for the same period of 2019 was largely the result of lower gas trading activity in the first quarter of 2020.

Net income attributable to noncontrolling interests — The decrease in net income attributable to noncontrolling interests was primarily a result of a mark to market adjustment on derivatives related to our BSP JV between periods.

Other expenses, net — The decrease in other expenses of $67 million to $136 million for the six months ended June 30, 2020 compared to $203 million for the same period of 2019 was largely the result of lower natural gas trading activity, partially offset by a one-time deficiency payment of $20 million made in April 2020 in connection with an expiring pipeline delivery contract.

Interest and debt expense, net — Interest and debt expense, net decreased $26 million to $172 million in the first half of 2020 compared to $198 million in the same period of 2019 due to the repayment of the 2020 Senior Notes in January 2020, reduction in the outstanding balance of the Second Lien Notes due to open market purchases and a reduction in the interest rates in our 2016 Credit Agreement and 2017 Credit Agreement.

Net gain on early extinguishment of debt — The net gain on early extinguishment of debt for the six months ended June 30, 2020 was $5 million, which is a decrease of $21 million from $26 million during the same period in 2019.

The decrease was due to lower debt repurchase activity in 2020.

Other non-operating expense — Other non-operating expense increased $51 million to $61 million for the six months ended June 30, 2020 compared to $10 million in the same period for 2019.

The increase was primarily a result of professional fees and costs associated with the preparation of the Chapter 11 Cases.

Stock-Based Compensation

Our consolidated results of operations for the three months ended March 31, 2020 and 2019 include the effects of long-term stock-based compensation plans under which awards are granted annually to executives, non-executive employees and non-employee directors that are either settled with shares of our common stock or cash.

Our consolidated results of operations for the three and six months ended June 30, 2020 and 2019 include the effects of long-term stock-based compensation plans under which awards are granted annually to executives, non-executive employees and non-employee directors that are either settled with shares of our common stock or cash.

Our equity-settled awards granted to executives include stock options, restricted stock units and performance stock units that either cliff vest at the end of a three-year period or vest ratably over a three-year period, some of which are partially settled in cash.

2 unchanged sentences

Changes in our stock price introduce volatility in our results of operations because we pay cash-settled awards based on our stock price on the vesting date and accounting rules require that we adjust our obligation for unvested awards to the amount that would be paid using our stock price at the end of each reporting period.

Cash-settled awards, including executive awards partially settled in cash, account for over 60% of our total outstanding awards.

Equity-settled awards are not similarly adjusted for changes in our stock price.

Our ending stock price was as follows:

March 31, 2020

December 31, 2019

March 31, 2019

December 31, 2018

Stock-based compensation is included in both G&A expenses and production costs as shown in the table below:

Cash-settled awards, including executive awards partially settled in cash, account for approximately 40% of our total outstanding awards.

Our obligations for equity-settled awards are not similarly adjusted for changes in our stock price.

Stock-based compensation is included in both general and administrative (G&A) expense and production costs as shown in the table below:

Three months ended

June 30, Six months ended

2020 2019 Variance 2020 2019 Variance

(in millions, except per Boe amounts)

1 unchanged sentence

Equity-settled awards 1 4 (3) 4 7 (3)

Total in G&A $ 1 $ 7 $ (6) $ 2 $ 20 $ (18)

Total in G&A per Boe $ 0.10 $ 0.60 $ (0.50) $ 0.10 $ 0.84 $ (0.74)

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However, the total amount of compensation to be paid under the variable compensation programs at target for 2020 remains largely the same as the amounts that would have been paid at target prior to the changes.

Our second quarter 2020 results included an additional $4 million expense related to modifying our 2020 compensation program.

See Non-GAAP Financial Measures below for a reconciliation of G&A to adjusted G&A.

Non-GAAP Financial Measures

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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 to the non-GAAP financial measure of adjusted net income 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 per diluted share:

The following table presents a reconciliation of the GAAP financial measure of net (loss) income to the non-GAAP financial measure of adjusted net (loss) income and presents the GAAP financial measure of net (loss) income attributable to common stock per diluted share and the non-GAAP financial measure of adjusted net (loss) income per diluted share:

Three months ended

June 30, Six months ended

2020 2019 2020 2019

(in millions, except share data)

Net (loss) income $ (247) $ 41 $ (1,992) $ (3)

Net income attributable to noncontrolling interests (24) (29) (75) (52)

Net loss attributable to common stock

Net (loss) income attributable to common stock (271) 12 (2,067) (55)

Unusual, infrequent and other items:

Asset impairment — — 1,736 —

Non-cash derivative loss from commodities, excluding noncontrolling interest

Non-cash derivative loss from interest-rate contracts

Non-cash derivative (loss) gain from commodities, excluding noncontrolling interest — (4) 35 93

Severance costs — 2 — 2

Incentive and retention award modification 4 — 4 —

Net gain on early extinguishment of debt — (20) (5) (26)

Professional fees and costs related to our Chapter 11 Cases 42 — 49 —

Deficiency payment on a pipeline delivery contract 20 — 20 —

Other, net 3 (4) 18 3

Total unusual, infrequent and other items 69 (26) 1,857 72

Adjusted net (loss) income $ (202) $ (14) $ (210) $ 17

Net loss attributable to common stock per diluted share

Net (loss) income attributable to common stock per diluted share $ (5.47) $ 0.24 $ (41.84) $ (1.13)

Adjusted net (loss) income per diluted share $ (4.08) $ (0.29) $ (4.25) $ 0.35

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A version of adjusted EBITDAX is a material component of certain of our financial covenants under our 2014 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:

The following table presents a reconciliation of the GAAP financial measure of net (loss) income to the non-GAAP financial measure of adjusted EBITDAX:

Three months ended

June 30, Six months ended

2020 2019 2020 2019

(in millions)

Net (loss) income $ (247) $ 41 $ (1,992) $ (3)

Interest and debt expense, net 85 98 172 198

5 unchanged sentences

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:

Three months ended

Six months ended

(in millions)

4 unchanged sentences

Adjusted EBITDAX $ 270 $ 556

Adjusted G&A — Management uses a measure called adjusted general and administrative (adjusted G&A) expense to provide useful information to investors interested in comparing our costs between periods and performance to our peers.

We define adjusted G&A expenses as general and administrative expenses excluding severance and other non-recurring costs.

The following table presents the reconciliation of our consolidated general and administrative expenses to the non-GAAP measure of adjusted G&A:

Three months ended June 30, Six months ended

2020 2019 2020 2019

(in millions) (in millions)

General and administrative expenses $ 69 $ 79 $ 129 $ 162

Incentive and retention award modification (4) — (4) —

Severance costs — (1) — (1)

Office consolidation — (1) — (1)

Adjusted G&A $ 65 $ 77 $ 125 $ 160

Liquidity and Capital Resources

Cash Flow Analysis

Three months ended

Six months ended

(in millions)

Net cash provided by operating activities

Net cash used (provided) by investing activities:

Cash flow from operating activities

Cash flow from investing activities:

Capital investments $ (33) $ (271)

1 unchanged sentence

Acquisitions, divestitures and other $ 34 $ 158

Net cash (used) provided by financing activities:

Cash flow from financing activities:

Net debt transactions $ 110 $ (74)

(Distributions) contributions with noncontrolling interest holders

Net distributions to noncontrolling interest holders $ (66) $ (16)

Issuance of common stock and other $ (1) $ (2)

1 unchanged sentence

Commodity price movements may also lead to changes in other variables in our business, including adjustments to our capital program.

Our operating cash flow increased 44% , or $70 million , to $228 million for the three months ended March 31, 2020 from $158 million in the same period of 2019 .

This increase includes $63 million of proceeds received in the first quarter of 2020 on the settlement of derivative contracts with counterparties prior to maturity.

Changes in operating assets and liabilities, net in the first quarter of 2020 increased our operating cash flow by $113 million compared to a reduction of $24 million in the first quarter of 2019.

Changes in working capital primarily related to a decrease in the balance of accounts receivable due to lower commodity prices between periods.

Cash flows from investing activities — Our net cash used in investing activities of $12 million for the three months ended March 31, 2020 primarily reflected $30 million of capital investments (excluding $19 million in negative capital-related accrual changes).

Cash used in investing activities also included proceeds of $41 million related to a sale of royalty interests and a non-core asset in the first quarter of 2020.

For the three months ended March 31, 2019 , our net cash used in investing activities of $182 million primarily included approximately $2 million related to an asset acquisition and $131 million of capital investments (excluding $47 million in positive capital-related accrual changes), of which $27 million was funded by BSP.

The amounts in the table below reflect our consolidated capital investment, excluding changes in capital investment accruals, for the three months ended March 31, 2020 and 2019 :

Three months ended

(in millions)

Oil and natural gas

Corporate and other

Total internally funded capital

BSP funded capital

Total consolidated capital investment

Cash flows from financing activities — Our net cash used in financing activities of $156 million for the three months ended March 31, 2020 primarily comprised $44 million of distributions to our noncontrolling interest holders, $3 million of debt repurchases on our Second Lien Notes, $100 million for the repayment of the 2020 Senior Notes at maturity and $10 million in net repayments on our 2014 Revolving Credit Facility, partially offset by $2 million in contributions from a noncontrolling interest holder.

For the three months ended March 31, 2019 , our net cash provided by financing activities of $50 million primarily comprised $49 million in a net contribution from a noncontrolling interest holder and partially offset by $14 million used for debt repurchases on our Senior Notes, $20 million of distributions paid to our noncontrolling interest holders and $36 million of net proceeds on our 2014 Revolving Credit Facility.

Our liquidity and ability to meet our debt obligations have been negatively impacted by the sharp decrease in commodity prices as a result of the COVID-19 pandemic and by the actions of foreign producers.

Our primary sources of liquidity and capital resources are cash flow from operations and available borrowing capacity under our 2014 Revolving Credit Facility.

As of March 31, 2020, we had available liquidity of $395 million, consisting of $67 million in unrestricted cash and $328 million of available borrowing capacity under our 2014 Revolving Credit Facility (before a $150 million month-end minimum liquidity requirement).

On April 30, 2020, we amended our 2014 Revolving Credit Facility to reduce the limit on our revolving credit facility from $1 billion to $900 million, among other things.

Our ability to borrow under our 2014 Revolving Credit Facility is limited by our ability to comply with its covenants, including quarterly financial covenants, and by our borrowing base.

Pursuant to a semi-annual borrowing base redetermination, our borrowing base was reduced from $2.3 billion to $1.2 billion effective as of May 18, 2020, with no further reduction in our ability to borrow under the 2014 Revolving Credit Facility.

As of May 31, 2020, we had available liquidity of $165 million, consisting of $148 million in unrestricted cash and $17 million of available borrowing capacity under our 2014 Revolving Credit Facility (before a $150 million month-end minimum liquidity requirement).

However, the Forbearance Agreements do not permit us to make any drawings under the 2014 Revolving Credit Facility until the expiration of the forbearance period described below.

We expect that operating cash flow and expected available credit capacity will not be sufficient to meet our commitments over the next twelve months.

In response to the significant and rapid decline in oil prices late in the first quarter of 2020 and in subsequent months, we initiated a series of financial and operational activities designed to reduce costs and preserve liquidity, including the following:

reducing our 2020 capital budget to a level that maintains the mechanical integrity of our facilities as described further below;

monetizing all of our crude oil hedges in place for April 2020 forward with our counterparties, except for certain hedges held by our BSP JV;

shutting in certain marginal wells to reduce operating costs;

and implementing reduced work hours for nearly all of our office employees to reduce costs and preserve liquidity.

We continuously evaluate our current and projected capital spending, operating activities and funding requirements, with consideration of realized commodity prices and the results of our operations and may make further adjustments as warranted.

Our spin–off from Occidental in December 2014 burdened us with significant debt which was used to pay a $6.0 billion cash dividend to Occidental.

Since then, we have engaged in a series of assets sales, joint ventures, debt exchanges, tenders and other financing transactions to reduce our overall debt and improve our balance sheet.

As of March 31, 2020, we had reduced outstanding debt to approximately $4.9 billion, a substantial portion of which will mature in 2021.

Our significant indebtedness, the unprecedented impact to our financial position resulting from commodity price decreases due to the COVID–19 pandemic and actions of foreign producers, and the continued challenging conditions in the credit and capital markets raise substantial doubt regarding our ability to continue as a going concern.

There can be no assurances that an agreement will be reached by the end of the forbearance period or at all or that we will be able to successfully restructure indebtedness.

In addition, no assurances can be given as to what value, if any, will be ascribed to each of our securities or what type or amounts of distributions, if any, our various stakeholders would receive in any restructuring.

Any restructuring could result in holders of certain liabilities and/or securities, including our common stock, receiving no distributions on account of their claims or interest.

See Part II, Item 1A – Risk Factors , below for further discussion regarding risks related to our ability to continue as a going concern.

As of March 31, 2020 , our long-term debt consisted of the following credit agreements, Second Lien Notes and Senior Notes:

Outstanding Principal

Interest Rate

Credit Agreements

(in millions)

2014 Revolving Credit Facility

LIBOR plus 3.25%-4.00%

ABR plus 2.25%-3.00%

June 30, 2021

Shared First-Priority Lien

2017 Credit Agreement

LIBOR plus 4.75%

ABR plus 3.75%

December 31, 2022 (a)

Shared First-Priority Lien

2016 Credit Agreement

LIBOR plus 10.375%

ABR plus 9.375%

December 31, 2021

First-Priority Lien

Second Lien Notes

December 15, 2022 (b)

Second-Priority Lien

5½% Senior Notes due 2021

September 15, 2021

6% Senior Notes due 2024

November 15, 2024

Total long-term debt

For a detailed description of our credit agreements, Second Lien Notes and Senior Notes, please see our most recent Form 10-K for the year ended December 31, 2019.

The 2017 Credit Agreement is subject to a springing maturity of 91 days prior to the maturity of our 2016 Credit Agreement if more than $100 million in principal of the 2016 Credit Agreement is outstanding at that time.

The Second Lien Notes require principal repayments of $286 million in June 2021, $57 million in December 2021, $60 million in June 2022 and $1,406 million in December 2022.

Interest Payment Deferrals and Forbearance Agreements

Our operating cash flow decreased 66%, or $179 million, to $93 million for the six months ended June 30, 2020 from $272 million in the same period of 2019.

Changes in operating assets and liabilities, net in the six months ended June 30, 2020 increased our operating cash flow by $130 million compared to a reduction of $52 million in the comparable six months of 2019.

This positive change primarily resulted from a decrease in accounts receivable due to lower commodity prices between periods partially offset by lower trade payables as a result of our reduced capital plan and cost saving initiatives.

Operating cash flow in the first six months of 2020 also reflected the positive contribution of the $63 million of proceeds from the early settlement of derivative contracts.

Cash flows from investing activities — Our net cash used in investing activities of $27 million for the six months ended June 30, 2020 primarily reflected $33 million of capital investments (excluding $28 million in capital-related accrual changes).

Investing activities also included proceeds of $41 million related to a sale of royalty interests and a non-core asset in the first half of 2020.

For the six months ended June 30, 2019, our net cash used in investing activities of $170 million primarily included approximately $271 million of capital investments (excluding $57 million in capital-related accrual changes), of which $43 million was funded by BSP, partially offset by $165 million of proceeds related to our Lost Hills sale.

Cash flows from financing activities — Our net cash provided by financing activities of $43 million for the six months ended June 30, 2020 primarily included $213 million in net proceeds on our 2014 Revolving Credit Facility partially offset by $100 million for the repayment of the 2020 Senior Notes at maturity, $68 million of distributions to our noncontrolling interest holders and $3 million for debt repurchases of our Second Lien Notes.

We also had an additional $2 million in contributions from a noncontrolling interest holder.

For the six months ended June 30, 2019, our net cash used in financing activities of $92 million was primarily comprised of $59 million used for debt repurchases of our Senior Notes, $65 million of distributions paid to our non-controlling interest holders, and $15 million of net repayments on our 2014 Revolving Credit Facility partially offset by $49 million in a net contribution from a noncontrolling interest holder.

Our spin–off from Occidental on November 30, 2014 burdened us with significant debt which was used to pay a $6.0 billion cash dividend to Occidental.

As of June 30, 2020, we had reduced our outstanding debt to approximately $5.1 billion, a substantial portion of which would have matured in 2021.

The commencement of the Chapter 11 Cases constituted an immediate event of default that automatically accelerated our obligations under the 2014 Revolving Credit Facility and our other debt agreements.

Any efforts to enforce payment obligations related to the acceleration of our obligations under these debt agreements were automatically stayed immediately upon filing the Chapter 11 Cases, and the creditors’ rights of enforcement are subject to the applicable provisions of the Bankruptcy Code.

As of June 30, 2020, we had available cash of $105 million and no ability to borrow under our 2014 Revolving Credit Facility due to the missed interest payments and forbearance described below.

As of June 30, 2020 and December 31, 2019, we had letters of credit outstanding of $152 million and $165 million, respectively.

These letters of credit were issued to support ordinary course marketing, insurance, regulatory and other matters.

For more information on our debt, see Part I, Item 1 – Financial Statements, Note 5 Debt and for more information on the Chapter 11 Cases, see Part I, Item 1 – Financial Statements, Note 1 Basis of Presentation.

Debtor-in-Possession Credit Agreements

On July 23, 2020, we entered into the Senior DIP Credit Agreement which provides for a Senior DIP Facility in an aggregate principal amount of up to approximately $483 million.

The Senior DIP Facility includes a $250 million revolving facility which will be primarily used by us to (i) fund working capital needs and capital expenditures and additional letters of credit during the pendency of the Chapter 11 Cases and (ii) pay certain costs, fees and expenses related to the Chapter 11 Cases and the Senior DIP Facility.

Until the Bankruptcy Court enters a final order with respect to our DIP credit agreements, only $85 million of revolving borrowings are available.

If the Bankruptcy Court enters a final order approving the Senior DIP Facility in its current form following a hearing on August 14, 2020, we expect the full remaining amount of the $250 million revolving facility to become available.

The Senior DIP Facility also includes (a) a $150 million letter of credit facility which was used to deem letters of credit outstanding under the 2014 Revolving Credit Facility as issued under the Senior DIP Facility, and (b) $83 million of term loans borrowings which were used to repay a portion of the 2014 Revolving Credit Facility.

On July 23, 2020, we also entered into a Junior DIP Credit Agreement which provides for a Junior DIP Facility in an aggregate principal amount of $650 million.

The proceeds of the Junior DIP Facility were used to (i) refinance in full all remaining obligations under the 2014 Revolving Credit Facility and (ii) pay certain costs, fees and expenses related to the Chapter 11 Cases and the Junior DIP Facility.

The Senior DIP Credit Agreement and Junior DIP Credit Agreement include conditions precedent, representations and warranties, affirmative and negative covenants and events of default customary for financings of their type and size.

The Senior DIP Facility and the Junior DIP Facility both mature on January 15, 2021.

See Part I, Item 1 – Financial Statements, Note 5 Debt for additional details about our DIP credit agreements.

Missed Interest Payments and Forbearance

On May 15, 2020, we did not make an interest payment of approximately $4 million on our 2024 Notes.

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On June 2, 2020, we entered into Forbearance Agreements with (i) certain lenders of a majority of the outstanding principal amount of the loans under the 2014 Revolving Credit Facility, (ii) certain lenders of a majority of the outstanding principal amount of the loans under the 2016 Credit Agreement, and (iii) certain lenders of a majority of the outstanding principal amount of the loans under the 2017 Credit Agreement.

On June 12, 2020, we amended the Forbearance Agreements to extend the forbearance period to June 30, 2020.

The Forbearance Agreements include a requirement that we maintain an aggregate book cash balance of not less than $40 million for more than three consecutive business days.

Pursuant to the Forbearance Agreements, the lenders who are parties to the Forbearance Agreements agreed to forbear from exercising any remedies under the 2014 Revolving Credit Facility, 2016 Credit Agreement and 2017 Credit Agreement with respect to our failure to make the aforementioned interest payments, initially through June 14, 2020 and subsequently through July 15, 2020.

On June 15, 2020, we did not make an interest payment of approximately $72 million on our Second Lien Notes.

The indenture governing the Second Lien Notes provides for a 30-day grace period, which will expire on July 15, 2020.

A failure to pay the interest within the 30-day grace period would constitute an event of default under this indenture and cross defaults under our other debt instruments and agreements.

Debt Exchange Offer

On February 20, 2020, we launched offers to exchange a significant portion of our Second Lien Notes and our Senior Notes into interests in an entity that would hold a term royalty interest in certain of our oil and gas assets or new term loans and warrants to purchase our common stock.

If the offers were fully subscribed, we expected that the transactions would have reduced our net debt by approximately $1 billion if successfully completed.

On March 16, 2020, we announced the termination of the offers as a result of developments in the commodity and financial markets at that time that rendered the offers inadvisable and impractical.

Note Repurchases

In January 2020, we repurchased $7 million in face value of our 8% Second Lien Notes for $3 million in cash resulting in a pre-tax gain of $5 million , including the write-off of unamortized deferred gain and issuance costs.

The indenture governing the Second Lien Notes provides for a 30-day grace period, which expired on July 15, 2020.

Significant changes in oil and natural gas prices may have a material impact on our liquidity.

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As a result, we did not have any commodity hedges that we would benefit from after the end of the first quarter.

We currently have Brent-based crude oil contracts for insignificant volumes through May 2021 all of which were entered into by our BSP JV and are included in our consolidated results.

As of June 30, 2020, we did not have any commodity hedges covering our share of production.

The Senior DIP Credit Agreement requires us to enter into hedging arrangements covering at least 25% of our share of expected crude oil production for the next twelve months.

On July 24, 2020, we entered into various derivative instruments through July 2021 to satisfy this requirement.

We currently have the following Brent-based crude oil contracts:

August-September 2020 Q4

2021 July 2021

Barrels per day 4,950 4,800 4,500 4,500 4,200

Weighted-average price per barrel $ 48.05 $ 48.05 $ 48.05 $ 48.05 $ 48.05

Purchased Puts:

Barrels per day 9,900 9,600 9,000 9,000 8,400

Weighted-average price per barrel $ 40.00 $ 40.00 $ 40.00 $ 40.00 $ 40.00

Barrels per day 4,950 4,800 4,500 4,500 4,200

Weighted-average price per barrel $ 30.00 $ 30.00 $ 30.00 $ 30.00 $ 30.00

Barrels per day 6,600 6,400 6,000 6,000 5,600

Weighted-average price per barrel $ 44.75 $ 44.75 $ 44.75 $ 44.75 $ 44.75

The outcomes of the derivative positions are as follows:

• Sold calls – we make settlement payments for prices above the indicated weighted-average price per barrel.

• Purchased puts – we receive settlement payments for prices below the indicated weighted-average price per barrel.

• Sold puts – we make settlement payments for prices below the indicated weighted-average price per barrel.

We also currently have Brent-based crude oil contracts for insignificant volumes through May 2021 which were entered into by our BSP JV and 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 through May 2021.

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In March 2020, we reduced our capital investment to a level that maintains the mechanical integrity of our facilities to operate in a safe and environmentally responsible manner in response to the collapse in crude oil prices.

We made $30 million of internally funded capital investments in the first quarter of 2020 and expect to invest up to an additional $20 million through the end of 2020.

In order to meet this level of investment, we have suspended all internally funded drilling and capital workovers for the second quarter and significantly reduced other activities.

Our JV partners invested $91 million in the first quarter of 2020 and an additional $10 million of capital has been invested in the second quarter of 2020 for completion costs.

We made $33 million of internally funded capital investments in the first half of 2020 and expect to invest up to an additional $20 million through the end of 2020.

In order to meet this level of investment, we suspended all internally funded drilling and capital workovers for the second quarter and significantly reduced other activities.

Our JV partners invested $98 million in the first half of 2020.

On March 27, 2020, Alpine elected to suspend its funding obligations under the Alpine JV.

For further information, regarding the Alpine JV and its funding obligations, see the Development Joint Ventures section above.

The curtailment of the development of our properties will lead to a decline in our production and possibly reserves.

A continued decline in our production and reserves would reduce our liquidity and ability to satisfy our debt obligations by negatively impacting our cash flow from operations and the value of our assets.

The amounts in the table below reflect our consolidated capital investment, excluding changes in capital investment accruals, for the six months ended June 30, 2020 and 2019:

Six months ended

(in millions)

Oil and natural gas $ 32 $ 212

Exploration — 9

Corporate and other 1 7

Total internally funded capital 33 228

BSP funded capital — 43

Total consolidated capital investment $ 33 $ 271

The curtailment of the development of our properties will lead to a decline in our production and may lower our reserves.

A continued decline in our production and reserves would negatively impact our cash flow from operations and the value of our assets.

While certain aspects of our operations are affected by seasonal factors, such as energy costs, seasonality has not been a material driver of changes in our quarterly results.

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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 March 31, 2020 and December 31, 2019 were not material to our condensed consolidated balance sheets as of such dates.

Reserve balances at June 30, 2020 and December 31, 2019 were not material to our condensed consolidated balance sheets as of such dates.

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 accrued would not be material to our consolidated financial position or results of operations.

Subject to certain exceptions under the Bankruptcy Code, the filing of the Chapter 11 Cases automatically stayed, among other things, the continuation of most judicial or administrative proceedings or the filing of other actions against or on behalf of us or our property to recover on, collect or secure a claim arising prior to July 15, 2020 or to exercise control over property of our bankruptcy estates, unless and until the Bankruptcy Court modifies or lifts the automatic stay as to any such action, or judicial or administrative proceeding.

Notwithstanding the general application of the automatic stay described above, governmental authorities may determine to continue actions brought under regulatory powers.

Significant Accounting and Disclosure Changes

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• budgets and maintenance capital requirements

• type curves

• expected synergies from acquisitions and joint ventures

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Factors (but not necessarily all the factors) that could cause results to differ include:

commodity price changes, including extended periods of low oil, NGL, or natural gas prices

• risks and uncertainties relating to the Chapter 11 Cases filed in the Bankruptcy Court, including our ability to obtain the Bankruptcy Court’s approval with respect to our motions, our ability to develop, confirm and consummate a Chapter 11 plan or an alternative restructuring transaction, risks associated with third-party motions, Bankruptcy Court rulings and the outcome of the Chapter 11 Cases in general, and the length of time we will operate under the Chapter 11 Cases

• the potential adverse effects of disruption from the Chapter 11 Cases on us, our liquidity and/or results of operations, and on the interests of our various constituents making it more difficult to maintain business and operational relationships, retain key executives and maintain various licenses and approvals necessary for us to conduct our business

• our ability to obtain sufficient financing to allow us to emerge from bankruptcy and execute our business plan post-emergence;

• risk and uncertainties relating to our ability to obtain requisite support for our Chapter 11 plan from various stakeholders and confirm and consummate that plan

• increased advisory costs to execute a reorganization

• risks associated with our ability to continue as a going concern

• the impact of the NYSE’s delisting of our common stock on the liquidity and market price of our common stock and on our ability to access the public capital markets;

• risks related to the trading of our securities on the OTC Pink Market

• the volatility of and potential for sustained low oil, natural gas and NGL prices

• commodity price changes, including extended periods of low oil, natural gas or NGL prices

• debt limitations on our financial flexibility

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• joint ventures and acquisitions and our ability to achieve expected synergies

the recoverability of resources and

• the recoverability of resources

• unexpected geologic conditions

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-Q

Item 2. Management’s Discussion and Analysis