Attached files
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| EX-99.1 - EX-99.1 - California Resources Corp | a20210113ex991.htm |
| 8-K - 8-K - California Resources Corp | crc-20210113.htm |
Exhibit 99.2
As of December 1, 2020, our proved reserves totaled an estimated 448 MMBoe based on preliminary SEC pricing and 489 MMBoe based on strip pricing. As of December 1, 2020, our estimated proved PV-10 was $2.4 billion based on preliminary SEC pricing and $3.4 billion based on strip pricing.
. . .
With approximately 65% remaining undeveloped as of December 1, 2020, our acreage position contains numerous development opportunities due to its varied geologic characteristics and thousands of feet of multiple stacked-pay reservoirs in many locations.
. . .
The table below summarizes certain information for the four oil and natural gas basins in which we operate:
| As of September 30, 2020 | As of December 1, 2020 | |||||||||||||||||||||||||||||||||||||||||||||||||
Total Acres (in thousands) | Average Gross Mineral Acreage Held in Fee (%) | Productive Wells, Gross | Average Net Revenue Interest (%)(4) | Total Proved Drilling Locations (1) | Estimated Future Capital Expenditures (in millions)(3) | |||||||||||||||||||||||||||||||||||||||||||||
| Basin | Gross | Net | Gross | Net | ||||||||||||||||||||||||||||||||||||||||||||||
| San Joaquin | 1,651 | 1,380 | 68% | 8,228 | 90% | 506 | 441 | $ | 777 | |||||||||||||||||||||||||||||||||||||||||
| Los Angeles(2) | 38 | 30 | 42% | 1,721 | 81% | 307 | 306 | 467 | ||||||||||||||||||||||||||||||||||||||||||
| Ventura | 264 | 226 | 75% | 764 | 89% | 0 | 0 | 39 | ||||||||||||||||||||||||||||||||||||||||||
| Sacramento | 595 | 511 | 37% | 831 | 79% | 12 | 5 | 29 | ||||||||||||||||||||||||||||||||||||||||||
| Total | 2,548 | 2,147 | 61% | 11,544 | 87% | 825 | 752 | $ | 1,312 | |||||||||||||||||||||||||||||||||||||||||
_______________
(1) Represents total proved drilling locations, excluding injection wells, by basin as of December 1, 2020 based on strip pricing. Please see “Business and Properties—Operations” and “Business and Properties—Drilling Locations” in our Annual Report on Form 10-K for more information regarding the processes and criteria through which we identified our drilling locations.
(2) Our Los Angeles basin operations are concentrated with pad drilling, primarily located on purpose-built man-made islands in the Wilmington field.
(3) Represents undiscounted estimated future capital expenditures associated with proved reserves by basin as of December 1, 2020 based on strip pricing.
(4) Represents our interest in production after considering royalties and similar burdens and third-party working interests.
. . .
Our large portfolio of lower-risk and lower-decline conventional opportunities comprises approximately 94% of our proved undeveloped reserves as of December 1, 2020 (using strip pricing) across the four oil and natural gas basins in which we operate.
. . .
Over the past five years, the average base decline rate across all of our assets was 14%.
. . .
Summary Reserve, Production and Operating Data
Reserves
The following table summarizes our preliminary estimate of proved oil, NGL and natural gas reserve volumes and the related PV-10 of cash flows as of December 1, 2020, based on preliminary SEC pricing and strip pricing at December 1, 2020. Our preliminary estimate of proved reserve volumes and the related PV-10 of cash flows as of December 1, 2020, based on preliminary SEC pricing and strip pricing at December 1, 2020, were prepared by our internal reserve engineers and have not been audited by our independent reserve engineers. There were material changes to our
December 1, 2020 reserve estimates when compared to our December 31, 2019 reserve estimates due to factors including (i) price-related impacts, (ii) the impact of reductions in 2020 capital budget and volumes shut in during 2020, (iii) our post-emergence rebooking of PUDs under the SEC’s five year rule and (iv) lower operating costs in 2020 compared to 2019. There could be further material changes to our 2020 estimated volumes as a result of our year-end annual reserve audit by our independent reserve engineers.
The information with respect to our estimated proved reserves presented below has been prepared in accordance with the rules and regulations of the SEC unless otherwise noted.
| Proved reserves as of | ||||||||||||||
| December 1, 2020 | ||||||||||||||
| SEC Pricing(1) | Strip Pricing(1)(2) | |||||||||||||
| Proved Developed Producing Reserves | ||||||||||||||
| Oil (MMBbl) | 192 | 206 | ||||||||||||
| NGLs (MMBbl) | 33 | 35 | ||||||||||||
| Natural gas (Bcf) | 386 | 424 | ||||||||||||
| Combined (MMBoe) | 289 | 312 | ||||||||||||
| PV-10 of cash flows of total proved developed producing reserves (in millions)(3) | $ | 1,523 | $ | 2,119 | ||||||||||
| Proved Developed Non-Producing Reserves | ||||||||||||||
| Oil (MMBbl) | 78 | 86 | ||||||||||||
| NGLs (MMBbl) | 5 | 5 | ||||||||||||
| Natural gas (Bcf) | 75 | 93 | ||||||||||||
| Combined (MMBoe) | 96 | 106 | ||||||||||||
| PV-10 of cash flows of total proved developed non-producing reserves (in millions)(3) | $ | 703 | $ | 930 | ||||||||||
| Proved Undeveloped Reserves | ||||||||||||||
| Oil (MMBbl) | 47 | 54 | ||||||||||||
| NGLs (MMBbl) | 3 | 3 | ||||||||||||
| Natural gas (Bcf) | 78 | 82 | ||||||||||||
| Combined (MMBoe) | 63 | 71 | ||||||||||||
| PV-10 of cash flows of total proved undeveloped reserves (in millions)(3) | $ | 174 | $ | 325 | ||||||||||
| Total Proved Reserves | ||||||||||||||
| Oil (MMBbl) | 317 | 346 | ||||||||||||
| NGLs (MMBbl) | 41 | 43 | ||||||||||||
| Natural gas (Bcf) | 539 | 599 | ||||||||||||
| Combined (MMBoe) | 448 | 489 | ||||||||||||
| PV-10 of cash flows of total proved reserves (in millions)(3) | $ | 2,400 | $ | 3,374 | ||||||||||
| Standardized measure of total proved reserves (in millions)(4) | N/A | N/A | ||||||||||||
_______________
(1) Our preliminary estimate of proved reserve volumes and PV-10 as of December 1, 2020 based on preliminary SEC pricing were calculated using oil and gas price parameters established by current SEC guidelines using average effective prices based on a 12-month unweighted arithmetic average of the first day of the month price for each month in the 12 months of 2020. For oil and NGL volumes, the average Brent spot price of $41.70 per barrel was adjusted for gravity, quality and transportation fees. For natural gas volumes, the average Henry Hub spot price of $1.98 per MMBtu was adjusted for energy content, transportation fees and market differentials. All prices are held constant throughout the lives of the properties.
(2) Our preliminary estimate of proved reserve volumes and PV-10 as of December 1, 2020 based on strip pricing were prepared on the same basis as the estimated reserves and PV-10 as of December 1, 2020 based on SEC pricing, except for the use of pricing based on futures prices as reported on the ICE Brent for oil and NGLs and NYMEX Henry Hub for natural gas on December 1, 2020, without giving effect to derivative transactions. The average strip prices used were: $47.00/Bbl for oil for December 2020, $47.37 for 2021, $47.34 for 2022, $47.68 for 2023, $48.10 for 2024, $48.43 for 2025, and $48.87 for 2026 and thereafter held flat; and $2.87/MMBtu for natural gas for December 2020, $2.83 for 2021, $2.69 for 2022, $2.52 for 2023, $2.54 for 2024, $2.56 for 2025, and $2.55 for 2026 and thereafter held flat. We have also
taken into account currently prevailing pricing differentials for purposes of realized prices. We believe that the use of forward prices provides investors with additional useful information about our reserves, as the forward prices are based on the market’s forward-looking expectations of oil prices, natural gas prices and NGL prices as of a certain date. Strip prices are not necessarily an accurate projection of future prices. Investors should be careful to consider strip prices as an addition to, and not as a substitute for, SEC prices (as defined below), when considering our estimated proved reserves.
(3) PV-10 of cash flows is a non-GAAP financial measure and represents the year-end present value of estimated future cash inflows from proved oil and natural gas reserves, less future development and production costs, discounted at 10% per annum to reflect the timing of future cash flows and using the unweighted arithmetic average of the first-day-of-the-month price for each month within the year, unless prices were defined by contractual arrangement (“SEC prices”). Our PV-10 is computed on the same basis as our standardized measure of future net cash flows, the most comparable measure under GAAP, but does not include the effects of future income taxes on future net cash flows.
PV-10 calculated using strip pricing was prepared on the same basis as described above except for the use of pricing based on futures prices as reported on the ICE Brent for oil and NGLs and NYMEX Henry Hub for natural gas on December 1, 2020. We have also taken into account currently prevailing pricing differentials for purposes of realized prices. We believe that the use of forward prices provides investors with additional useful information about our reserves, as the forward prices are based on the market’s forward-looking expectations of oil, natural gas and NGL prices as of a certain date.
Calculation of PV-10 does not give effect to derivative transactions. If future settlement payments from derivative contracts were included, our PV-10 of cash flows as of December 1, 2020, based on strip pricing, would have been higher by $8 million. PV-10 of cash flows as of December 1, 2020 has been reduced by future cash flows attributable to BSP. Please see below for a reconciliation of PV-10 of cash flows to the GAAP financial measure of standardized measure as of December 31, 2019. Neither PV-10 nor standardized measure should be construed as the fair value of our oil and natural gas reserves. Standardized measure is prescribed by the SEC as an industry standard asset value measure to compare reserves with consistent pricing, costs and discount assumptions. PV-10 facilitates the comparisons to other companies as it is not dependent on the tax-paying status of the entity.
(4) GAAP does not prescribe a standardized measure of reserves on a basis other than SEC pricing. As such, no standardized measure of proved reserves using preliminary SEC prices or strip prices as of December 1, 2020 has been provided.
. . .
The following table sets forth by basin our estimated proved reserve volumes as of December 1, 2020 based on strip pricing on December 1, 2020, and average net daily production volumes of oil, NGLs and natural gas for the nine months ended September 30, 2020:
| Proved reserves as of December 1, 2020(1) | Average net daily production | |||||||||||||||||||||||||||||||||||||
| for the nine months ended September 30, 2020 | ||||||||||||||||||||||||||||||||||||||
| Basin | Oil | NGLs | Natural Gas | Total | (MBoe/d) | Oil (%) | ||||||||||||||||||||||||||||||||
| (MMBbl) | (MMBbl) | (Bcf) | (MMBoe) | |||||||||||||||||||||||||||||||||||
| San Joaquin | 215 | 42 | 498 | 340 | 81 | 52% | ||||||||||||||||||||||||||||||||
| Los Angeles | 117 | — | 9 | 119 | 25 | 100% | ||||||||||||||||||||||||||||||||
| Ventura | 14 | 1 | 9 | 16 | 4 | 75% | ||||||||||||||||||||||||||||||||
| Sacramento | — | — | 83 | 14 | 3 | —% | ||||||||||||||||||||||||||||||||
| Total operations | 346 | 43 | 599 | 489 | 113 | 62% | ||||||||||||||||||||||||||||||||
_______________
(1) Our preliminary estimated proved reserve volumes as of December 1, 2020 based on strip pricing were prepared by our internal reserve engineers and have not been audited by Ryder Scott or NSAI. These estimates were prepared on the same basis as the estimated reserves at December 1, 2020 based on preliminary SEC pricing, except for the use of pricing based on futures prices as reported on the ICE Brent for oil and NGLs and NYMEX Henry Hub for natural gas on December 1, 2020, without giving effect to derivative transactions. For further information about the strip pricing used to prepare our preliminary estimate of proved reserves, see “—Summary Reserve, Production and Operating Data—Reserves.”
. . .
Our Competitive Strengths
•Stable, low-decline and oil-weighted conventional asset base. Our operations are located in premier hydrocarbon rich basins in California, which is the seventh largest oil producing state in the nation. The properties have produced for decades. As a result, the geology and reservoir characteristics are well understood, and new development well results are generally more predictable, repeatable and lower risk than unconventional resource plays. The lower base decline of our conventional assets allows us to limit production declines with minimal investment. Over the past five years, the average base decline rate across
all of our assets was 14%. We have ownership or operational control over substantially all of our assets. This allows us to adapt our investments by selecting drilling locations, the timing of development and the drilling and completion techniques used in a manner designed to optimize returns in a wide range of commodity prices. The nature of our assets provides us with a high degree of capital flexibility through commodity cycles.
•Attractive, large scale, diverse portfolio provides flexibility through commodity cycles. Our operated asset base spans 135 distinct fields with approximately 12,000 operated wells, and we are the largest oil and natural gas producer in California with average net production for the nine months ended September 30, 2020 of approximately 113 MBoe/d (approximately 60% oil). Our total proved asset base had an estimated PV-10 of $3.4 billion as of December 1, 2020 based on strip pricing. This amount includes proved developed reserves with an estimated PV-10 of $3.1 billion, of which an estimated $930 million relates to proved developed non-producing reserves. We are able to access our significant reserves base (489 MMboe of proved reserves as of December 1, 2020 based on strip pricing) from multiple high oil-in-place reservoirs. We also have the largest privately held mineral acreage position in California with 2.1 million net mineral acres with a high average net revenue interest of approximately 87% as of September 30, 2020. Our large, diverse and high-quality footprint provides operational flexibility.
•Substantial inventory of lower-cost, lower-risk and higher-return development opportunities. We expect to develop our assets to generate highly attractive rates of return. Our proved drilling inventory at December 1, 2020 consisted of approximately 825 gross (752 net) identified well locations, approximately 94% of which were lower-risk and lower-decline conventional opportunities. We have resource inventory that we estimated at December 1, 2020 could be developed with $2.5 billion of drilling and completion costs that meet our VCI threshold of 1.3x, the majority of which achieve full cycle-cost below $35 per Boe. In addition, we maintain a portfolio of workover projects that often deliver returns in excess of our stated VCI threshold.
•Premium pricing driven by deficit California energy market. We sell nearly all of our crude oil into the California refining markets at prices we believe are among the most favorable in the United States. California has the largest state economy in the United States and in 2019 imported approximately 72% of its oil and 90% of its natural gas from outside of the state. Nearly all of the imported oil arrives via supertanker, mostly from foreign locations. As a result, California refiners have typically purchased crude oil at international waterborne-based Brent prices that exceed WTI-based prices for comparable grades, resulting in California oil pricing that is the highest in the country. Our average realized oil price, before the effects of hedging, for the year ended December 31, 2019 and the nine months ended September 30, 2020 reflected a 14% and an 8% premium to WTI index prices, respectively. We believe that the limited crude transportation infrastructure from other parts of the U.S. into California will continue to contribute to higher realizations than most other U.S. oil markets for comparable grades and will allow us to continue to realize strong cash margins.
•Integrated business model that enhances margins and reliability. We own and control a network of strategically placed infrastructure that integrates with and complements our operations to maximize the value generated from our production. This infrastructure includes natural gas processing plants, power plants, oil and natural gas gathering systems and other related assets. We have the largest natural gas processing system in California. Our Elk Hills power plant is one of the largest natural gas fired power plants in the state and is expected to be the site of our innovative, early stage carbon capture and sequestration facility. We own an extensive network of more than 8,000 miles of oil and natural gas gathering lines that connect our producing wells and facilities to gathering networks, natural gas collection and compression systems and water and steam processing, injection and distribution systems. Through this vast network, we have the ability to access multiple delivery points to improve the prices we obtain for our oil and natural gas production. All of our steam needs and approximately 60% of our field electricity needs are self-sourced by our owned infrastructure. We sell excess electricity generated to the grid and local utilities, which provides incremental revenue. Our tank storage capacity throughout California allows us to continue production by avoiding or delaying any field shutdowns in the event of temporary power, pipeline or other shutdowns.
•Environmental, social and governance (“ESG”) focus with a proven track record of worker and community health and safety. We design, build and maintain our facilities throughout the state with our
neighbors, communities and the environment in mind. Since our formation in 2014, CRC’s operations have been recognized annually by the National Safety Council, including 24 awards for 2019, and we have undergone 57 consecutive federal and state pipeline safety audits and assessments with zero violations. CRC has been recognized by the CDP for the last two years as a climate disclosure leader, earning the highest ranking among all U.S. oil and gas companies.
•Strong balance sheet and ample liquidity. We have emerged from our reorganization with a strong balance sheet and low leverage. Further, we are continuing to focus on reducing costs and increasing efficiencies to generate additional cash flow from operations. We consider our liquidity, low leverage and ability to control costs to be a core strength and strategic advantage, which we are focused on maintaining.
Our Business Strategy
•Deliver value and drive free cash flow generation. With a right-sized balance sheet, a leaner organization and a lower cost base, we believe we are positioned to compete across a wide range of potential commodity price environments. Our asset base – with its leading low corporate decline rates and efficient capital requirements – provides significant advantages. Our internally funded capital program is designed to be funded from operating cash flow and improve margins. This capital program is supported by our track record of strong historical performance at managing finding and development expenditures and converting that into strong recycle profitability metrics. We are increasing the crude oil mix as a share of our total production, thus improving margins. We believe these factors, coupled with premium pricing on our products, as compared to U.S. pricing benchmarks, position us as a leading E&P company to deliver operationally and financially.
•Maintain our commitment to safety and sustainability and show leadership on ESG practices in the E&P space. We are focused on our ESG performance while improving overall corporate transparency and highlighting the positive impact we have on communities in which we operate. Our 2030 Sustainability Goals and our ongoing sustainability strategy are intended to align with the climate goals of California, which has committed to adhere to the Paris Agreement, which entered into force on November 4, 2016. We publish a sustainability report annually that documents our proven track record of safety, technological innovation and operational excellence and dedication to our ESG policies. As part of this strategy, our 2020 compensation metrics for our management team include specific ESG targets for safety, environmental stewardship, water conservation and sustainability project milestones.
•Maintain dynamic capital allocation process to drive cash flow generation across a range of commodity price environments. In the current Brent oil price environment, a substantial portion of our expected capital expenditures will be allocated to workover and shallow drilling, which we expect to generate strong margins and cash flow. If Brent oil prices decrease, we retain the flexibility to reduce capital spending while benefiting from the downside protection from our hedging program in order to preserve free cash flow. If Brent oil prices increase, we would consider incremental investment to further enhance value and free cash flow generation.
•Continue to pursue a predictable, advantaged and integrated asset base. Our diverse, lower-decline and lower-risk production portfolio in prolific conventional basins with a high net revenue interest provides a high level of predictability. Our integrated and owned infrastructure assets further enhance margins and provide for operational control. Our asset characteristics and integrated operations exemplify our strategy of maintaining low business and execution risk. Our operations are further advantaged by our location in California, the leading economy within the United States. The deficit in California’s energy supply balance, combined with the local infrastructure and transportation systems, provides premium realizations on all of our products as compared to U.S. pricing benchmarks.
•Optimize our asset base and reduce our cost structure while maintaining operational excellence. We intend to undertake a strategic review to further streamline our organization and pursue asset divestitures to focus our operations in core fields that we expect will lower our costs and help enhance free cash flow. We also expect to further our track record of strong performance and execution by continuing to lower operating
costs and increase drilling, completion and related facilities efficiencies in our core assets. In the second half of 2020, we reduced our operating expenses to under $55 million per month. We have retooled our organization as we have steadily reduced general and administrative expenses from $290 million in 2019 to an estimated $255 million in the twelve months ended December 31, 2020, with a target of $200 million in 2021.
•Preserve balance sheet strength with a disciplined approach to capital allocation and a robust hedging program. Our capital allocation priorities are guided by our focus on maximizing the value of our assets while protecting our balance sheet, maintaining mechanical integrity of our infrastructure and maintaining or, in a higher commodity price environment, growing our base production while generating free cash flow. We target a capital budget that is less than expected cash flows and evaluate investment opportunities using VCI and payback metrics. As part of this strategy, we typically utilize a combination of derivative instruments to protect our cash flows. We intend to maintain low leverage going forward.
. . .
As of and for the nine months ended September 30, 2020, our subsidiaries that do not guarantee our Revolving Credit Facility accounted for approximately 14% of our property, plant and equipment, net, 19% of our net production volumes, 21% of our revenue and 28% of our adjusted EBITDAX. We do not expect the application of fresh start accounting to materially affect these percentages.
. . .
Recent Developments
Chief Executive Officer Departure and Replacement Search; Strategic Business Review
The board of directors appointed Mark A. McFarland, the Company’s Chairman, to act as interim Chief Executive Officer upon the departure of the Company’s prior Chief Executive Officer on December 31, 2020 and has initiated a search process for the Company’s next Chief Executive Officer. The board of directors appointed James N. Chapman, who is also the Chairman of the Company’s Compensation Committee, to serve as Lead Independent Director while Mr. McFarland serves in the interim Chief Executive Officer role. Concurrent with the Chief Executive Officer search, the Company has initiated a strategic review of its business led by Mr. McFarland and William B. Roby, the Chair of the Special Committee on Operation of the Board, with a focus on being a low cost producer, enhancing free cash flow yield and maintaining a strong balance sheet. As a result of this review, the Company expects to further streamline its organization and pursue asset divestitures to focus our operations in core fields that we expect will lower its costs and help enhance free cash flow.
Response to COVID-19 Pandemic and Industry Downturn
We have taken several steps and continue to actively work to mitigate the effects of the COVID-19 pandemic and the industry downturn on our operations, financial condition and liquidity.
In response to the rapid fall in commodity prices in March 2020, we reduced our 2020 capital budget to a level that maintains the mechanical integrity of our facilities to operate them in a safe and environmentally responsible manner and ceased all field development and growth projects. As a result, our internally funded capital expenditures were $7 million in the aggregate in the second and third quarters of 2020. We also monetized all of our crude oil hedges in March 2020, except for certain hedges held by our joint venture with Benefit Street Partners (“BSP” and such joint venture, the “BSP JV”), for approximately $63 million to enhance our liquidity. We began shutting in high-cost, negative margin wells in March 2020 to reduce operating costs and enhance cash flow which curtailed average net production volumes by approximately 5 MBoe/d and 3 MBoe/d for the second and third quarters of 2020, respectively. As part of our operational efficiency measures, we evaluated our diverse portfolio and our various production mechanisms with a focus on wells with higher operating costs. Our teams utilized our extensive automation controls, monitored weekly well margins, and made temporary adjustments to our producing wells to ensure our operations aligned with the commodity price environment. As a result of these actions, as well as further cost
rationalization and streamlining efforts coupled with lower activity levels, our third quarter 2020 average operating expense run rate fell below $50 million per month compared to the first quarter of 2020 average of $64 million per month.
We have also implemented various measures to protect the health of our workforce and to support the prevention of COVID-19 at our plants, rigs, fields and administrative offices. These initiatives were implemented in accordance with the orders, regulations and guidance of federal, state and local authorities to mitigate the risks of the disease and included restricting non-essential travel and temporarily closing our administrative offices during periods of higher incidence of community spread from mid-March until mid-June 2020 and resuming again in mid-November 2020 by implementing remote work for our management team and substantially all of our office personnel, with limited return to the office in accordance with applicable protocols and restrictions on occupancy for those employees for whom remote work was not feasible. In addition, in April 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. In August 2020, we implemented organizational and operational efficiencies that resulted in a reduction of our headcount to approximately 1,100 employees. These actions were made in an effort to preserve liquidity after the deterioration of commodity prices following the outbreak of COVID-19. Our operational employees and contractors, and certain support personnel, have been classified as an essential critical infrastructure workforce by government authorities. Accordingly, these essential personnel have been authorized to continue to work in their plant, rig, field and office locations under our COVID-19 Health and Safety Plan, which includes, among other things, protocols for employee training, health self-assessment screening by workers and visitors entering Company locations, reporting of illness, notification of workers and contact tracing associated with positive COVID-19 cases, self-quarantine or isolation, hygiene, wearing facial coverings, applying social distancing to minimize close contact between workers, cleaning or disinfecting workspaces and protection of emergency response personnel. We have not experienced any operational slowdowns due to COVID-19 among our workforce.
Selected Preliminary Operating and Financial Fourth Quarter Results
Our unaudited condensed consolidated financial statements for the three months ended December 31, 2020 and our audited consolidated financial statements for the year ended December 31, 2020 are not yet available. The following estimates are based on our preliminary operating and financial results for the three months ended December 31, 2020 and, as of today, have not been finalized. These preliminary estimates are derived from our internal records and are based on the most current information available to management. We have prepared these estimates on a basis materially consistent with our historical financial results. Our independent auditor has not reviewed, audited, compiled or performed any procedures in respect of these preliminary results and accordingly does not express any opinion or other form of assurance with respect thereto. These preliminary financial estimates are not reviewed and are unaudited, and our normal reporting processes with respect to the following preliminary operational and financial results have not been fully completed. During the course of our review process on, and the audit of, our operating and financial results for the three months ended December 31, 2020, we could identify items that would require us to make adjustments and could affect our final results. Any such adjustments could be material. The audit of our results for the year ended December 31, 2020 will not be completed until immediately prior to the filing of our annual report on Form 10-K for the year ended December 31, 2020. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Forward-Looking Statements” in our Annual Report on Form 10-K for the year ended December 31, 2019 and our subsequently filed Quarterly Reports on Form 10-Q for additional information regarding factors that could result in differences between the preliminary operating and financial results that are presented below and the actual results for the three months ended December 31, 2020.
This summary is not intended to be a comprehensive statement of our unaudited financial results for the three months ended December 31, 2020. The results of operations for an interim period, including the summary preliminary financial results provided below, may not give a true indication of the results to be expected for a full year or any future period. In addition, the preliminary financial results set forth below should not be viewed as a substitute for full financial statements prepared in accordance with GAAP.
Three Months Ended December 31, 2020 | ||||||||||||||
| Low Estimate | High Estimate | |||||||||||||
| Production Data: | ||||||||||||||
| Total production (MBoe/d) | 100 | 105 | ||||||||||||
| Oil production (Mbo/d) | 60 | 65 | ||||||||||||
| Other Financial Data (in millions): | ||||||||||||||
| Total revenues | $ | 285 | $ | 315 | ||||||||||
| Total revenues (excluding non-cash derivative losses) | $ | 400 | $ | 450 | ||||||||||
| Adjusted EBITDAX(1) | $ | 93 | $ | 103 | ||||||||||
| Cash used for asset retirement obligations and idle well testing | $ | 8 | $ | 9 | ||||||||||
| Adjusted free cash flow(1) | $ | (30) | $ | (33) | ||||||||||
| Discretionary cash flow(1) | $ | 33 | $ | 37 | ||||||||||
| Capital expenditures | $ | 9 | $ | 10 | ||||||||||
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Note: MBoe/d refers to thousands of barrels of oil equivalent (Boe) per day. Mbo/d refers to thousands of barrels of oil per day. Natural gas volumes have been converted to Boe based on the equivalence of energy content of six thousand cubic feet of natural gas to one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence.
(1) Adjusted EBITDAX, adjusted free cash flow and discretionary cash flow are not measures calculated in accordance with GAAP. We define adjusted EBITDAX as net (loss) income before interest and debt expense, net; income taxes; depreciation, depletion and amortization; exploration expense; other unusual, out-of-period and infrequent items; and other non-cash items. We believe this measure provides useful information in assessing our financial condition, results of operations and cash flows and is widely used by the industry, the investment community and our lenders. We define “adjusted free cash flow” as net cash provided by (used in) operating activities minus capital investments plus or minus significant, unusual or non-recurring items. For 2020, such items included legal, professional and other fees primarily related to our restructuring. We define “discretionary cash flow” as adjusted EBITDAX minus cash interest, distributions paid to noncontrolling interest holders and cash used for asset retirement obligations and idle well testing. Management uses adjusted free cash flow and discretionary cash flow as supplemental measures of liquidity.
In addition, as of December 31, 2020, we had total indebtedness of $599 million, including $99 million of borrowings outstanding under our Revolving Credit Facility, net debt (defined as the face value of our debt less cash used to collateralize letters of credit outstanding and available cash) of $571 million, and $335 million of liquidity, consisting of $28 million of unrestricted cash and $307 million available for borrowing under the Revolving Credit Facility (after taking into account $134 million of outstanding letters of credit).
For the three months ended December 31, 2020, we have included a reconciliation of adjusted EBITDAX, adjusted free cash flow, discretionary cash flow and net debt to their directly comparable GAAP financial measure.
| Three Months Ended December 31, 2020 | ||||||||||||||
| ($ millions) | Low Estimate | High Estimate | ||||||||||||
| Net income | $ | 3,520 | $ | 3,890 | ||||||||||
Interest and debt expense, net | 16 | 18 | ||||||||||||
| Depreciation, depletion and amortization | 42 | 46 | ||||||||||||
| Exploration expense | 1 | 1 | ||||||||||||
Unusual, infrequent and other items(a) | (3,498) | (3,866) | ||||||||||||
Other non-cash items(b) | 12 | 14 | ||||||||||||
| Adjusted EBITDAX | $ | 93 | $ | 103 | ||||||||||
| Net cash used in operating activities | (35) | (39) | ||||||||||||
| Cash interest | 14 | 16 | ||||||||||||
| Exploration expenditures | 1 | 1 | ||||||||||||
| Working capital changes | 113 | 125 | ||||||||||||
| Adjusted EBITDAX | $ | 93 | $ | 103 | ||||||||||
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(a) Our results of operations, which are presented in accordance with GAAP, can include the effects of unusual, out-of-period and infrequent transactions and events affecting earnings that vary widely and unpredictably (in particular, certain non-cash items such as derivative gains and losses) in nature, timing, amount and frequency.
(b) Other non-cash items primarily include accretion on our asset retirement obligations and compensation expense on non-cash stock-based compensation awards.
| Three Months Ended December 31, 2020 | Nine Months Ended September 30, 2020 | ||||||||||||||||
| ($ millions) | Low Estimate | High Estimate | |||||||||||||||
| Net cash (used in) provided by operating activities | $ | (35) | $ | (39) | $ | 141 | |||||||||||
| Capital investments | (10) | (11) | (37) | ||||||||||||||
| Transaction related costs | 15 | 17 | 71 | ||||||||||||||
| Adjusted free cash flow | $ | (30) | $ | (33) | $ | 175 | |||||||||||
| Three Months Ended December 31, 2020 | Nine Months Ended September 30, 2020 | ||||||||||||||||
| ($ millions) | Low Estimate | High Estimate | |||||||||||||||
| Adjusted EBITDAX | $ | 93 | $ | 103 | $ | 373 | |||||||||||
| Cash interest | (14) | (16) | (80) | ||||||||||||||
| Distributions paid to noncontrolling interest holders: | |||||||||||||||||
| BSP | (29) | (32) | (34) | ||||||||||||||
| Ares | (9) | (9) | (61) | ||||||||||||||
| Cash used for asset retirement obligations and idle well testing | (9) | (9) | — | ||||||||||||||
| Discretionary cash flow | $ | 33 | $ | 37 | $ | 198 | |||||||||||
| ($ millions) | As of December 31, 2020 | ||||
| Face value of debt | $ | 599 | |||
| Unrestricted cash | (28) | ||||
| Net debt | $ | 571 | |||
Our Capital Budget
Our 2021 capital program is anticipated to be between $175 million and $225 million, including approximately $40 million of mechanical integrity and midstream turnaround deferred from 2020 to 2021. Our capital program will be dynamic in response to oil market volatility while focusing on maintaining low leverage and generating free cash flow. The current plan anticipates investing $25 million to $30 million in the first quarter of 2021 and ramping up to approximately $50 million to $75 million in the fourth quarter of 2021, subject to commodity prices. The table below sets forth our expected allocation of the 2021 capital budget by category.
| 2021 Budget Range | ||||||||
| (in millions) | ||||||||
| Drilling | $ | 95 to 135 | ||||||
| Capital workovers | 35 to 40 | |||||||
| Infrastructure, corporate and other | 45 to 50 | |||||||
| Total | $ | 175 to 225 | ||||||
Because we own or control substantially all of our assets, the amount and timing of capital expenditures is within our control, subject to our discretion and may be adjusted during the year depending on commodity prices and other factors. We retain the flexibility to defer planned capital expenditures depending on a variety of factors, including, but not limited to, prevailing and anticipated prices for oil, natural gas and NGLs, the success of our drilling program, operating costs and other general market conditions. We focus our capital program on oil projects that provide high margins and low decline rates. We believe investing in these projects will generate positive cash flow allowing us to re-invest and grow production over the longer term in a higher commodity price environment. Our low decline rates
compared to our industry peers, together with our high level of operational control, give us the flexibility to adjust the level of our capital expenditures as circumstances warrant.
In addition to capital expenditures, we also incur costs associated with retiring assets and remediating property at the end of its useful life, both due to regulatory obligations and our focus on health, environmental and safety matters as we develop existing fields. These obligations and activities are regulated by governmental agencies. In 2021, we expect to spend approximately $45 million to $50 million fulfilling these obligations. A significant portion of these costs is a result of California’s idle well management regulations enacted in 2019 which accelerated the timing of cash flows and added costs for periodic testing.
Our Commodity Hedging Program
We continue to maintain a commodity hedging program primarily focused on crude oil to help protect our cash flows, margins and capital program from the volatility of commodity prices. The Revolving Credit Facility requires that we hedge a significant amount of crude oil production for a period of 36 months from the effective date of the facility. In addition, the Revolving Credit Facility requires that we maintain hedges on production for not less than two years from the date of each hedging report that we deliver to our lenders under that facility, which occurs twice annually. We have met our hedging obligation under our Revolving Credit Facility. The table below summarizes our Brent-based crude oil hedge positions as of January 12, 2020:
| 2021 | 2022 | January – October 2023 | ||||||||||||||||||
| Sold Calls(1): | ||||||||||||||||||||
| Barrels per day | 24,568 | 30,783 | 17,758 | |||||||||||||||||
| Weighted average price per barrel ($/Bbl) | $ | 49.73 | $ | 59.37 | $ | 58.01 | ||||||||||||||
| Purchased Puts(2): | ||||||||||||||||||||
| Barrels per day | 37,268 | 30,783 | 17,758 | |||||||||||||||||
| Weighted average price per barrel ($/Bbl) | $ | 40.49 | $ | 40.00 | $ | 40.00 | ||||||||||||||
| Sold Puts(3): | ||||||||||||||||||||
| Barrels per day | 14,907 | 3,042 | — | |||||||||||||||||
| Weighted average price per barrel ($/Bbl) | $ | 32.38 | $ | 32.00 | $ | — | ||||||||||||||
| Swaps(4): | ||||||||||||||||||||
| Barrels per day | 8,078 | 6,576 | 5,919 | |||||||||||||||||
| Weighted average price per barrel ($/Bbl) | $ | 44.96 | $ | 46.29 | $ | 47.57 | ||||||||||||||
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(1) For sold calls, we make settlement payments for prices above the indicated weighted-average price per barrel.
(2) For purchased puts, we receive settlement payments for prices below the indicated weighted-average price per barrel.
(3) For sold puts, we make settlement payments for prices below the indicated weighted-average price per barrel.
(4) For swaps, we make settlement payments for prices above the indicated weighted-average price per barrel and receive settlement payments for prices below the indicated weighted-average price per barrel.
. . .
The combined net acreage covered by leases expiring in the next three years represented approximately 15% of our total net undeveloped acreage at December 1, 2020.
. . .
At December 31, 2020, we had a cash balance of $28 million, all of which was unrestricted. As of December 31, 2020, we had total outstanding borrowings of $99 million and available borrowing capacity of $307 million under the Revolving Credit Facility after taking into account $134 million of outstanding letters of credit, which reflects the transition of all outstanding letters of credit to our new Revolving Credit Facility.