Attached files
| file | filename |
|---|---|
| EX-99.1 - EXHIBIT 99.1 - California Resources Corp | a20200220ex991.htm |
| 8-K - 8-K - California Resources Corp | a20200220form8-k.htm |
Exhibit 99.2
EXCERPTS FROM OFFERING MEMORANDUM AND
SOLICITATION STATEMENT, DATED FEBRUARY 20, 2020
California Resources Corporation
California Resources Corporation (“CRC” or the “Company”) is an independent oil and natural gas exploration and production company incorporated under the laws of the State of Delaware operating properties exclusively within the State of California. CRC is the largest oil and gas producer in California on a gross operated basis, with average net daily production of 132 thousand barrels of oil equivalent per day (MBoe/d) in 2018. CRC has the largest privately held mineral acreage position in the state, consisting of approximately 2.2 million net mineral acres spanning four of California’s major oil and gas basins. CRC’s proved reserves totaled an estimated 644 million barrels of oil equivalent (MMBoe) at December 31, 2019. CRC’s internal estimate of PV-10 of cash flows from proved reserves as of December 31, 2019 based on SEC pricing and strip pricing at February 14, 2020 is $6.849 billion and $5.991 billion, respectively. PV-10 of cash flows of proved reserves based on SEC pricing is a non-GAAP financial measure. For a definition of PV-10 of cash flows and a reconciliation of PV-10 of cash flows to the GAAP financial measure of standardized measure, please see “Non-GAAP Financial Information.”
The following table summarizes CRC’s reserves of oil (including condensate), NGLs and natural gas at December 31, 2019 and related PV-10 of cash flows using SEC pricing and strip pricing at February 14, 2020:
Estimated Net Reserves at December 31, 2019 (MMBoe) | ||||||||
SEC Pricing(1) | Strip Pricing(2) | |||||||
Estimated Proved Reserves(3): | ||||||||
Oil (MMBbl) | 483 | 509 | ||||||
NGLs (MMBbl) | 52 | 53 | ||||||
Natural Gas (Bcf) | 654 | 667 | ||||||
Total equivalent proved reserves (MMBoe) | 644 | 673 | ||||||
Total equivalent proved developed (MMBoe)(4) | 493 | 520 | ||||||
Oil (MMBbl) | 357 | 382 | ||||||
NGLs (MMBbl) | 45 | 46 | ||||||
Natural Gas (Bcf) | 543 | 553 | ||||||
Percent proved developed | 77% | 77% | ||||||
Total equivalent proved undeveloped reserves (MMBoe) | 151 | 153 | ||||||
Oil (MMBbl) | 126 | 127 | ||||||
NGLs (MMBbl) | 7 | 7 | ||||||
Natural Gas (Bcf) | 111 | 114 | ||||||
Percent proved undeveloped | 23% | 23% | ||||||
PV-10 of cash flows of proved reserves (in millions)(5) | $ | 6,849 | $ | 5,991 | ||||
Standardized measure of proved reserves (in millions)(6) | $ | 5,231 | $ N/A | |||||
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(1) | The SEC pricing for CRC’s estimated proved reserves was estimated 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 arrangements. Oil, NGLs and natural gas prices used for this purpose were based on spot prices, adjusted for price differentials to account for gravity, quality and transportation costs, without giving effect to derivative transactions. For the December 31, 2019 SEC pricing estimated proved reserves attributable to the underlying properties, the average benchmark Brent oil price was $63.15 per barrel and the average NYMEX gas price was $2.58 per MMBtu. The average realized prices used for such December 31, 2019 reserves were $63.50 per barrel for oil, $30.91 per barrel for NGLs and $2.88 per Mcf for natural gas. |
(2) | The estimated proved reserves attributable to the underlying properties at strip pricing were prepared on the same basis as the SEC proved reserves attributable to the underlying properties, except for the use of pricing based on closing month futures prices as reported on the ICE Brent for oil and NGLs and NYMEX Henry Hub for natural gas on February 14, 2020, without giving effect to derivative transactions. The average strip prices used were $57.12 per barrel for oil for 2020, $56.21 for 2021, $55.54 for 2022, $55.51 for 2023, $55.84 for 2024 and $56.31 for 2025 and thereafter escalated at 2% per annum, and $2.11 per MMBtu for natural gas for 2020, $2.36 for 2021, $2.42 for 2022, $2.46 for 2023, $2.47 for 2024, $2.49 for 2025 and thereafter escalated at 2% per annum. 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 |
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about our reserves, as the forward prices are based on the market’s forward-looking expectations of oil, 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, when considering our proved reserves.
(3) | Please see “The Underlying Properties-Preparation of Reserve Estimates” for definitions of proved reserves and the technologies and economic data used in their estimation. CRC’s estimated proved reserve volumes as of December 31, 2019 based on SEC pricing were audited by CRC’s independent reserve engineers, Ryder Scott Company, L.P. (“Ryder Scott”) and Netherland, Sewell & Associates, Inc. (“NSAI”). Ryder Scott audited 42% of our total proved reserves, all of which were in Elk Hills. NSAI audited 38% of our total proved reserves, covering certain fields outside of Elk Hills. CRC’s estimated proved reserve volumes as of December 31, 2019 based on strip pricing, and the related PV-10 of cash flows as of December 31, 2019 based on SEC pricing and strip pricing as of February 14, 2020, have been estimated by CRC and have not been audited by Ryder Scott or NSAI. |
(4) | As of December 31, 2019, approximately 24% of proved developed oil reserves, 11% of proved developed NGLs reserves, 13% of proved developed natural gas reserves and, overall, 21% of total proved developed reserves are non-producing. A majority of our non-producing reserves relate to steamfloods and waterfloods where full peak production response has not yet occurred due to the nature of such projects. |
(5) | PV-10 of cash flows of proved reserves based on SEC pricing is a non-GAAP financial measure. For a definition of PV-10 of cash flows and a reconciliation of PV-10 of cash flows to the GAAP financial measure of standardized measure, please see “-Non-GAAP Financial Information.” |
(6) | 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 strip pricing has been provided. |
Elk Hills RoyaltyCo
Elk Hills RoyaltyCo Corporation (“Elk Hills RoyaltyCo”) will be formed as a bankruptcy remote special purpose Delaware corporation to hold a 20-year term non-participating royalty interest (the “Royalty Interest”) equal to 4.3% of 8/8ths (such percentage to be reduced proportionally based on the principal amount of Royalty Notes issued on the consummation of the Offers out of the maximum issuable amount, assuming maximum participation, of $340 million) in all of the oil, gas, NGLs, condensate, casinghead gas and other liquid or gaseous hydrocarbons (or any combinations or constituents thereof) (“Hydrocarbons”) that may be produced and saved from the Company’s underlying fee mineral interests in the Elk Hills unit (the “underlying properties”) prior to the termination of the Royalty Interest on January 31, 2040.
The Underlying Properties
Summary Overview
The underlying properties are located within the Elk Hills field in the San Joaquin basin. The Elk Hills field was discovered in 1911 and is one of the largest fields in the continental U.S. based on proved reserves. The Elk Hills field covers 74 square miles with cumulative production of approximately 2 billion Boe. The Elk Hills field is one of the top 15 most productive oil fields in the lower 48 states of the United States according to the U.S. Energy Information Administration.
The Elk Hills unit is the Company’s largest producing asset and covers approximately 47,000 contiguous acres within the Elk Hills field, or approximately 98% of the total acres in the Elk Hills field. The Elk Hills unit refers to that portion of the Elk Hills field that was formerly unitized prior to the Company’s acquisition of Chevron Corporation’s (“Chevron”) interest in April 2018. The Company now holds 100% of the working interests and 99.7% of the mineral interests in the Elk Hills unit, subject to the working interests on certain wells that are part of the Alpine JV (as defined below). Please see “-Alpine Joint Venture” for additional details regarding the Alpine JV.
At September 30, 2019, the Company had approximately 2,878 producing wells in the Elk Hills unit. This includes wells drilled pursuant to the Alpine JV, which were producing on average approximately 900 Boe/d from the underlying properties as of year-end 2019. Production from the Elk Hills unit represented 38% of the Company’s total average daily production for the nine months ended September 30, 2019. For the nine months ended September 30, 2019, the underlying properties contributed revenues of approximately $566 million, which the Company estimates would have provided royalty payments of approximately $23 million to Elk Hills RoyaltyCo if Elk Hills RoyaltyCo received a payment on the Royalty Interest with respect to the production for such period. Please see “-Selected Financial and Operating Data of the Elk Hills Unit” for an illustrative calculation of the payment on the Royalty Interest for the nine months ended September 30, 2019.
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The table below summarizes the reserves associated with the underlying properties in the Elk Hills unit, including those attributable to the Alpine JV as those reserves are also subject to the Royalty Interest, as of December 31, 2019.
Reserves Attributable to the Underlying Properties as of December 31, 2019(1) | ||||||||||||||||
Oil (MBbl) | NGLs (MBbl) | Natural Gas (Bcf) | Total (MMBoe) | Liquids (Oil and NGLs) (%) | Proved Developed (%) | PV-10 of Revenues(1)(2) (in millions) | ||||||||||
Total Proved Reserves (SEC pricing)(3) | 135 | 37 | 304 | 223 | 77% | 81% | $ | 5,158 | ||||||||
Total Proved Reserves (strip pricing)(4) | 137 | 39 | 313 | 228 | 77% | 81% | $ | 4,838 | ||||||||
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(1) | Please see “-Preparation of Reserve Estimates” for definitions of proved reserves and the technologies and economic data used in their estimation. The Company’s estimated proved reserve volumes associated with the Elk Hills unit as of December 31, 2019 based on SEC pricing were audited by the Company’s independent reserve engineers, Ryder Scott Company, L.P. (“Ryder Scott”). |
(2) | PV-10 of revenues is a non-GAAP financial measure. For additional information regarding PV-10 of revenues, please see “-Non-GAAP Financial Information.” The PV-10 values set forth above have been calculated by the Company and have not been reviewed or audited by the Company’s independent reserve engineers. |
(3) | The SEC pricing for estimated proved reserves attributable to the underlying properties was estimated using the unweighted arithmetic average of the first-day-of-the-month price for each month within the year (SEC Price), unless prices were defined by contractual arrangements. Oil, NGLs and natural gas prices used for this purpose were based on spot prices, adjusted for price differentials to account for gravity, quality and transportation costs, without giving effect to derivative transactions. For the December 31, 2019 SEC pricing estimated proved reserves attributable to the underlying properties, the average benchmark Brent oil price was $63.15 per barrel and the average NYMEX gas price was $2.58 per MMBtu. The average realized prices used for such December 31, 2019 reserves were $66.30 per barrel for oil, $31.58 per barrel for NGLs and $2.86 per Mcf for natural gas. |
(4) | The estimated proved reserves attributable to the underlying properties at strip pricing were prepared on the same basis as the SEC proved reserves attributable to the underlying properties, except for the use of pricing based on closing month futures prices as reported on the ICE Brent for oil and NGLs and NYMEX Henry Hub for natural gas on February 14, 2020, without giving effect to derivative transactions. The average strip prices used were $57.12 per barrel for oil for 2020, $56.21 for 2021, $55.54 for 2022, $55.51 for 2023, $55.84 for 2024 and $56.31 for 2025 and thereafter escalated at 2% per annum, and $2.11 per MMBtu for natural gas for 2020, $2.36 for 2021, $2.42 for 2022, $2.46 for 2023, $2.47 for 2024, $2.49 for 2025 and thereafter escalated at 2% per annum. 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 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, when considering our proved reserves. |
The table below summarizes the average daily production associated with the underlying properties for the periods indicated, which includes production associated with the Alpine JV working interests as the Royalty Interest also burdens the Alpine JV working interests.
Average Net Daily Production | ||||||||
Nine Months Ended September 30, 2019 | Year Ended December 31, 2019 | |||||||
(MBoe/d)(1) | Oil (%) | (MBoe/d)(1) | Oil (%) | |||||
Elk Hills unit | 49.2 | 43% | 48.5 | 43% | ||||
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(1) | Natural gas volumes have been converted to Boe based on the equivalence of energy content of six thousand cubic feet of natural gas (Mcf) to one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence. |
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The following table summarizes certain information concerning the Company’s acreage and drilling activities as of December 31, 2019 with respect to the underlying properties:
Acreage (in millions) | Gross Acreage Held in Fee (%)(2) | Producing Wells, gross | Average Working Interest Associated with Royalty (%)(2) | Identified Drilling Locations(1) | ||||||||||
Gross | Net | Gross | Net | |||||||||||
Elk Hills unit | 47,000 | 47,000 | 100% | 2,878 | 100% | 1,836 | 1,836 | |||||||
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(1) | The Company’s total identified drilling locations include 448 gross (448 net) locations associated with proved undeveloped reserves as of December 31, 2019. |
(2) | The Company owns all of the working interests in the underlying properties other than Alpine’s working interest in the Alpine JV wells, which wells are burdened by the Royalty Interest. Please see “-Alpine Joint Venture” for additional details regarding the Alpine JV. As a result of the sale of the Third Party Royalty Interest (as defined in “-Partial Sale Transaction of Similar Royalty Interest”), the Company has a 99.7% mineral interest in the Elk Hills unit. Please see “-Partial Sale Transaction of Similar Royalty Interest” for additional details regarding the sale of the Third Party Royalty Interest. |
Partial Sale Transaction of Similar Royalty Interest
In January 2020, the Company sold a perpetual non-participating royalty interest (the “Third Party Royalty Interest”) equal to 0.295% of 8/8ths in all of Hydrocarbons that may be produced and saved from the underlying properties in the Elk Hills unit for a purchase price of $27.3 million to a third party. The Third Party Royalty Interest is entitled to the production proceeds with respect thereto (calculated in a manner substantially similar to the Royalty Interest) from and after December 31, 2019, attributable to the production of Hydrocarbons occurring on or after such date. The Royalty Interest is separate from and not-burdened by the Third Party Royalty Interest.
Alpine Joint Venture
In July 2019, the Company entered into a development agreement with Alpine Energy Capital, LLC (“Alpine”) to develop portions of the Elk Hills unit (the “Alpine JV”). Alpine is a joint venture between Colony Capital, Inc. and Equity Group Investments. Alpine committed to invest $320 million to the development of certain Elk Hills well locations (the “JV wells”), which may be increased to a total investment of $500 million, subject to the mutual agreement of the parties. The initial $320 million commitment covers multiple development opportunities and is intended to be invested over a period of up to three years in accordance with a 275-well development plan. Alpine will fund 100% of the drilling and completion costs of the JV wells, in which they will earn a 90% working interest. If Alpine receives an agreed upon return, the Company’s working interest in those wells will increase from 10% to 82.5%. The Alpine JV development commenced in mid-2019 and Alpine has invested $134 million through December 31, 2019 and has drilled 108 wells (including drilled but uncompleted wells). The production from the JV wells is also subject to the Royalty Interest. The committed capital from Alpine will make up approximately 55% to 79% of the projected capital expenditures for Elk Hills unit in 2020. Please read “-Estimated 2020 Future Production and Capital Expenditures Associated with Elk Hills Unit” for a discussion of the Company’s projected capital investments for the Elk Hills unit in 2020.
Asset Overview
Located in the San Joaquin basin, the Elk Hills unit contains multiple stacked formations throughout its areal extent. The Company believes this unit provides an appealing inventory of existing re-development opportunities, as well as new play discovery potential. The complex stratigraphy and structure in the Elk Hills unit has provided continuing discoveries of stratigraphic and structural traps since the field was first discovered in 1911. In addition, the Company has an extensive proprietary 3D seismic library covering the entire Elk Hills unit that greatly enhances the Company’s ongoing development and future exploration activities.
The Company seeks to enhance production and increase the recovery factor in the Elk Hills unit by progressively implementing various production enhancement methods (such as well stimulation and artificial lift techniques), improved oil recovery methods (such as waterflooding and/or gas injection) and enhanced oil recovery methods (like CO2 and/or polymer flooding), while using both vertical and horizontal wellbores. Since 2018, the
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Company has implemented a horizontal drilling program targeting 15-foot intervals of bypassed pay in shallow oil zones. The horizontal wells drilled to date have a 2.9 Value Creation Index (“VCI”) compared to a 1.8 VCI on the vertical wells in the same formation. Additionally, initial production rate on those horizontal wells are five times greater than the vertical wells. Due to the nature of the multiple stacked pay zones at the Elk Hills unit, the Company typically deploys a portion of its annual operating and capital expenses to execute well workovers, such as adding additional uphole pay zones, performing well cleanout treatments or increasing lift capacity, resulting in incremental production and reserves and mitigating production decline. Capital workovers are some of the lowest risk investments in CRC’s portfolio while generating high VCI returns. In addition to conventional drilling and workover techniques, the Company also believes its undeveloped unconventional acreage in the Elk Hills unit has the potential to provide additional significant long-term production growth.
The Company is not dependent on any single production zone, drive mechanism or completion method with respect to its operations in the Elk Hills unit. The Company has not historically relied on well stimulation and less than 5% of its wells in the Elk Hills unit were completed using well stimulation over the past several years. Currently, the Company is operating a total of seven rigs on the Elk Hills unit and none of the wells which the Company is currently drilling require well stimulation. Future development efforts, however, may include a higher percentage of wells completed using stimulation techniques. The Company also does not utilize high-pressure cyclic steam injection at the Elk Hills unit and does not anticipate requiring this technique in the future due to the attributes of the reservoir stratigraphy and based on its past production experience successfully using other mechanisms. For this reason, the Company does not expect the recent moratorium by the California Department of Oil, Gas, and Geothermal Resource (now known as the California Geologic Energy Management Division) on permitting new wells that use high-pressure cyclic steaming processes to have a significant effect on its production, plans or reserves.
At the Elk Hills unit, the Company has also made significant investments in infrastructure, which increase the Company’s operational flexibility and ability to minimize costs thereby increasing returns and cash flow to the Company. The Elk Hills unit continues to have among the lowest unit operating costs in the Company’s entire portfolio at $12.67/Boe (exclusive of asset level taxes) for the nine months ended September 30, 2019. The Company operates large and efficient gas processing facilities with a combined capacity of 220 MMcf/d. The gas plant facilities are located adjacent to the Company’s 550 megawatt combined-cycle power plant that supplies sufficient electricity to power the unit. The Company believes that the Elk Hills power plant may also be a source of CO2 for future tertiary recovery. Please see “-Potential Additional Recovery at Elk Hills through CO2 Flooding” for a description of potential CO2 enhanced oil recovery techniques. The Company’s operations of the Elk Hills unit include a central control facility, remote monitoring of wells and field equipment and consolidated production facilities for economies of scale, all of which contribute to higher operational efficiencies.
The Company currently sells its crude oil production from the Elk Hills unit into the California refining markets, which offer favorable pricing for comparable grades relative to other U.S. regions. Although California state policies actively promote and subsidize renewable energy, the demand for oil and natural gas in California remains strong. In addition, California is heavily reliant on imported sources of energy, with approximately 73% of oil and 90% of natural gas consumed in 2018 imported from outside the state. Nearly all of the imported oil arrives via supertanker, mostly from foreign locations. As a result, California refiners have typically purchased crude oil at international waterborne-based Brent prices. The Company believes 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.
Underlying Properties Reserve Data
The Company’s estimated proved reserves associated with the Elk Hills unit as of December 31, 2019 based on SEC pricing and strip pricing as of February 14, 2020, each as described below, are based on evaluations prepared by the Company’s internal reserve engineers. At least 95% of the Company’s estimated proved reserves based on SEC pricing associated with the Elk Hills unit as of December 31, 2019, were audited by the Company’s independent reserve engineers, Ryder Scott. See “-Preparation of Reserve Estimates” below for definitions of proved reserves and the technologies and economic data used in their estimation. The PV-10 of cash flows as of December 31, 2019 based on SEC pricing and strip pricing as of February 14, 2020 have been estimated by the Company and have not been audited by Ryder Scott. The information with respect to the Company’s estimated reserves presented below has been prepared in accordance with the rules and regulations of the SEC unless otherwise noted.
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The following table summarizes the reserves of oil (including condensate), NGLs and natural gas attributable to the underlying properties at December 31, 2019, including reserves attributable to the Alpine JV, and related PV-10 of cash flows using SEC pricing and strip pricing at February 14, 2020:
Estimated Net Reserves at December 31, 2019 (MMBoe) | ||||||||
SEC Pricing(1) | Strip Pricing(2) | |||||||
Estimated Proved Reserves(3): | ||||||||
Oil (MMBbl) | 135 | 137 | ||||||
NGLs (MMBbl) | 37 | 39 | ||||||
Natural Gas (Bcf) | 304 | 313 | ||||||
Total equivalent proved reserves (MMBoe) | 223 | 228 | ||||||
Total equivalent proved developed producing reserves (MMBoe) | 155 | 158 | ||||||
Oil (MMBbl) | 83 | 84 | ||||||
NGLs (MMBbl) | 30 | 32 | ||||||
Natural Gas (Bcf) | 247 | 254 | ||||||
Percent proved developed producing | 70% | 69% | ||||||
Total equivalent proved developed non-producing reserves (MMBoe) | 26 | 28 | ||||||
Oil (MMBbl) | 19 | 20 | ||||||
NGLs (MMBbl) | 3 | 3 | ||||||
Natural Gas (Bcf) | 28 | 29 | ||||||
Percent proved developed non-producing | 11% | 12% | ||||||
Total equivalent proved undeveloped reserves (MMBoe) | 42 | 42 | ||||||
Oil (MMBbl) | 33 | 33 | ||||||
NGLs (MMBbl) | 4 | 4 | ||||||
Natural Gas (Bcf) | 29 | 30 | ||||||
Percent proved undeveloped | 19% | 19% | ||||||
PV-10 of cash flows of proved reserves (in millions)(4) | $ | 2,977 | $ | 2,646 | ||||
Standardized measure of proved reserves (in millions)(5) | $ | 2,258 | $ N/A | |||||
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(1) | The SEC pricing for estimated proved reserves attributable to the underlying properties was estimated 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 arrangements. Oil, NGLs and natural gas prices used for this purpose were based on spot prices, adjusted for price differentials to account for gravity, quality and transportation costs, without giving effect to derivative transactions. For the December 31, 2019 SEC pricing estimated proved reserves attributable to the underlying properties, the average benchmark Brent oil price was $63.15 per barrel and the average NYMEX gas price was $2.58 per MMBtu. The average realized prices used for such December 31, 2019 reserves were $66.30 per barrel for oil, $31.58 per barrel for NGLs and $2.86 per Mcf for natural gas. |
(2) | The estimated proved reserves attributable to the underlying properties at strip pricing were prepared on the same basis as the SEC proved reserves attributable to the underlying properties, except for the use of pricing based on closing month futures prices as reported on the ICE (Brent) for oil and NGLs and NYMEX Henry Hub for natural gas on February 14, 2020, without giving effect to derivative transactions. The average strip prices used were $57.12 per barrel for oil for 2020, $56.21 for 2021, $55.54 for 2022, $55.51 for 2023, $55.84 for 2024 and $56.31 for 2025 and thereafter escalated at 2% per annum, and $2.11 per MMBtu for natural gas for 2020, $2.36 for 2021, $2.42 for 2022, $2.46 for 2023, $2.47 for 2024, $2.49 for 2025 and thereafter escalated at 2% per annum. 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 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, when considering our proved reserves. |
(3) | Please see “-Preparation of Reserve Estimates” for definitions of proved reserves and the technologies and economic data used in their estimation. The Company’s estimated proved reserve volumes associated with the Elk Hills unit as of December 31, 2019 based on SEC pricing were audited by the Company’s independent reserve engineers, Ryder Scott. The Company’s estimated proved reserve volumes associated with the Elk Hills unit as of December 31, 2019 based on strip pricing, and the related PV-10 of cash flows as of December 31, 2019 based on SEC pricing and strip pricing as of February 14, 2020, have been estimated by the Company and have not been audited by Ryder Scott. |
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(4) | PV-10 of cash flows of proved reserves based on SEC pricing is a non-GAAP financial measure. For a definition of PV-10 of cash flows and a reconciliation of PV-10 of cash flows to the GAAP financial measure of standardized measure, please see “-Non-GAAP Financial Information.” |
(5) | 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 strip pricing has been provided. |
Preparation of Reserve Estimates
The Company’s estimates of reserves and associated discounted future net cash flows for the Elk Hills unit and for the Company’s total reserves, each as of December 31, 2019, were made by the Company’s technical personnel, such as reservoir engineers and geoscientists, with the assistance of operational and financial personnel and are the responsibility of management. The estimation of proved reserves is based on the requirement of reasonable certainty of economic producibility and management’s funding commitments to develop the reserves. Reserves volumes are estimated by forecasts of production rates, operating costs and capital investments. Price differentials between specified benchmark prices and realized prices and specifics of each operating agreement are then applied against the SEC price to estimate the net reserves. Production rate forecasts are derived using a number of methods, including estimates from decline-curve analysis, type-curve analysis, material balance calculations, which take into account the volumes of substances replacing the volumes produced and associated reservoir pressure changes, seismic analysis and computer simulations of reservoir performance. These field-tested technologies have demonstrated reasonably certain results with consistency and repeatability in the formations being evaluated or in analogous formations. Operating and capital costs are forecast using the current cost environment (without accounting for possible cost changes) applied to expectations of future operating and development activities related to the proved reserves.
Net proved developed reserves are those volumes that are expected to be recovered through existing wells with existing equipment and operating methods, for which the incremental cost of any additional required investment is relatively minor. Net proved undeveloped reserves are those volumes that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required.
The Company’s Vice President, Reserves and Corporate Development has primary responsibility for overseeing the preparation of the Company’s reserves estimates. She has over 15 years of experience as an energy sector engineer including as a Senior Reservoir Engineer with Ryder Scott. She is a member of the Society of Petroleum Engineers for which she served as past chair of the U.S. Registration Committee. She holds a Master of Business Administration from the Massachusetts Institute of Technology, a Master of Engineering in Petroleum Engineering from the University of Houston and a Bachelor of Science from the University of Florida. She is also a registered Professional Engineer in the state of Texas.
The Company has an Oil and Gas Reserves Review Committee (“Reserves Committee”), consisting of senior corporate officers. The Reserves Committee reports its findings to the Audit Committee during the year.
Ryder Scott and Netherland, Sewell & Associates, Inc. (“NSAI”) were engaged to provide independent audits of the Company’s reserves estimates for its fields. Ryder Scott audited 42% of the Company’s total proved reserves, all of which were in Elk Hills, including the Elk Hills unit. The audit comprised at least 95% of the total proved reserves in the Elk Hills unit. The primary technical engineer from Ryder Scott who was responsible for the audit has 42 years of petroleum engineering experience, the majority of which has been in the estimation and evaluation of reserves. He serves on the Ryder Scott Board of Directors and is a registered Professional Engineer in the state of Texas. NSAI audited 38% of the Company’s total proved reserves, covering certain fields outside of Elk Hills. Over 95% of the Company’s total 2019 proved reserves were audited by independent auditors at some time during 2015 through 2019. The technical persons from NSAI primarily responsible for the Company’s audit have over 14 years and 31 years of petroleum engineering experience, respectively. Both individuals have the education, training and experience to perform oil and gas reservoir studies and reserves evaluations.
Potential Additional Recovery at Elk Hills through CO2 Flooding
The Company believes significant additional value may be created in the underlying properties through tertiary recovery operations using CO2 flooding at its Elk Hills unit, as well as help the Company meet its sustainable growth goals. CO2 used in enhanced oil recovery (“EOR”) operations is one of the most efficient and proven tertiary recovery mechanisms for producing crude oil. While EOR projects utilizing CO2 have been
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successfully performed by numerous oil and gas companies in a wide range of oil-bearing reservoirs in different oil-producing basins, the Company believes its infrastructure, existing areas of operation and experience provides a significant advantage in tertiary recovery in the Elk Hills unit. The Company’s existing infrastructure will be able to provide a local source of CO2 once a carbon capture and storage facility has been constructed at the Company’s Elk Hills power plant. As part of its 2030 Sustainability Goals, the Company has established a dedicated EOR team that is designing a system to collect CO2 from its 550-megawatt Elk Hills power plant and inject it into underground oil and natural gas formations at Elk Hills for EOR and long-term carbon sequestration. Under this process, the CO2 mixes with oil in the pore space and displaces it to producing wells, while permanently sequestering a significant quantity of the injected CO2 in the pore space. At the surface, the oil production containing some residual CO2 is separated from the oil and recycled for injection in a closed loop, supplemented by additional CO2 from the power plant. This project would not only improve recovery from suitable formations, but also put the Elk Hills power plant on a path toward essentially becoming carbon neutral. Several oil and gas formations with extensive production history in the Elk Hills unit have already been identified as likely candidates for CO2 EOR. In addition, prior to the Company’s spin-off from Occidental Petroleum Corporation (“Occidental”), many of the Company’s employees had significant experience developing and operating Occidental’s CO2 EOR projects in the Permian basin. The Company completed a successful CO2 flood pilot in the Elk Hills unit in 2005. In addition, the Company is currently in the process of completing a front end engineering and design study for the retrofit of the Elk Hills power plant to capture CO2. The Company currently estimates that it will cost approximately $400 to $500 million to retrofit the Elk Hills power plant.
Selected Financial and Operating Data of the Elk Hills Unit
The following table sets forth information regarding the Company’s production, realized and benchmark prices for oil, NGLs and natural gas produced from the Elk Hills unit, and certain other financial metrics for the Elk Hills unit for the periods indicated. The years ended December 31, 2017 and 2018 are presented on a pro forma basis as though the Company’s acquisition of Chevron’s interest in the Elk Hills unit occurred on January 1, 2017. The nine months ended September 30, 2019 includes results with respect to the Alpine JV working interests in the Elk Hills unit, as the Royalty Interest also burdens production from the Alpine JV working interest. An illustrative calculation of production proceeds associated with the Royalty Interest is also presented for each of the applicable periods.
Pro Forma(1) Year Ended December 31, | Nine Months Ended September 30, 2019 | |||||||||||
2017 | 2018 | |||||||||||
Benchmark Pricing: | ||||||||||||
Brent ($/Bbl) | $ | 54.82 | $ | 71.53 | $ | 64.74 | ||||||
NYMEX Henry Hub ($/MMBtu) | $ | 3.09 | $ | 2.97 | $ | 2.72 | ||||||
NGL SoCal border monthly index (Average) ($/MMBtu) | $ | 2.93 | $ | 2.92 | $ | 2.72 | ||||||
Elk Hills Unit Realized Pricing: | ||||||||||||
Oil ($/Bbl) | $ | 55.27 | $ | 73.73 | $ | 68.51 | ||||||
NGLs ($/Bbl) | $ | 36.39 | $ | 43.53 | $ | 30.79 | ||||||
Natural gas ($/MMBtu) | $ | 2.83 | $ | 2.9 | $ | 2.61 | ||||||
Elk Hills Unit Production Summary: | ||||||||||||
Oil (MBbl) | 8,835 | 8,265 | 5,772 | |||||||||
NGLs (MBbl) | 5,179 | 4,359 | 3,122 | |||||||||
Natural gas (MMcf) | 42,345 | 39,478 | 27,175 | |||||||||
Total Elk Hills unit (MBoe)(3)(4) | 21,071 | 19,204 | 13,423 | |||||||||
Elk Hills Unit Financial Summary: | ||||||||||||
Revenue (millions)(8) | $ | 797 | $ | 928 | $ | 566 | ||||||
Operating costs (millions) | $ | 256 | $ | 237 | $ | 170 | ||||||
Production and ad valorem taxes (millions)(5) | $ | 33 | $ | 33 | $ | 23 | ||||||
Capital investment (millions) | $ | 60 | $ | 59 | $ | 135 | ||||||
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Pro Forma(1) Year Ended December 31, | Nine Months Ended September 30, 2019 | |||||||||||
2,017 | 2,018 | |||||||||||
Elk Hills Unit $/Boe Analysis: | ||||||||||||
Revenue ($/Boe) | $ | 37.81 | $ | 48.30 | $ | 42.19 | ||||||
Operating costs ($/Boe) | $ | 12.15 | $ | 12.32 | $ | 12.67 | ||||||
Production and ad valorem taxes ($/Boe)(4)(5) | $ | 1.58 | $ | 1.72 | $ | 1.74 | ||||||
Illustrative Elk Hills RoyaltyCo Financial Summary: | ||||||||||||
Elk Hills Unit Revenue (millions) (2) | $ | 801 | $ | 913 | $ | 565 | ||||||
Production and ad valorem taxes (millions) (7) | 23 | 18 | 16 | |||||||||
Marketing and transportation costs (millions) | 10 | 10 | 8 | |||||||||
Illustrative Elk Hills RoyaltyCo Production Proceeds (millions)(6) | $ | 768 | $ | 885 | $ | 541 | ||||||
Percentage Allocable to Elk Hills RoyaltyCo(6) | 4.3 | % | 4.3 | % | 4.3 | % | ||||||
Total Cash to Elk Hills RoyaltyCo (millions) (6) | $ | 33 | $ | 38 | $ | 23 | ||||||
_______________
Note: | MBbl refers to one thousand barrels; MMBtu refers to Million British Thermal Units; MMcf refers to one million cubic feet. |
(1) | Presented on a pro forma basis as though the Company’s acquisition of Chevron’s interest in the Elk Hills unit occurred on January 1, 2017. |
(2) | Includes adjustments to Elk Hills unit revenue to reflect pricing contemplated for the Royalty Interest and excludes third party processing revenues. |
(3) | Includes production associated with the Alpine JV working interests. |
(4) | Natural gas volumes have been converted to Boe based on the equivalence of energy content of six thousand cubic feet of natural gas (Mcf) to one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence. |
(5) | Excludes greenhouse gas taxes. |
(6) | Presented on a pro forma basis as though the Royalty Interest had been conveyed to Elk Hills RoyaltyCo on January 1, 2017. Percentage allocable to Elk Hills RoyaltyCo to be reduced proportionally based on the principal amount of Royalty Notes issued on the consummation of the Offers out of the maximum issuable amount, assuming maximum participation, of $340 million. |
(7) | Represents portion attributable to minerals in place. |
(8) | Prior to allocation to Elk Hills RoyaltyCo. |
Estimated 2020 Future Production and Capital Expenditures Associated with Elk Hills Unit
The Company’s low decline rates compared to its industry peers together with its high level of operational control gives it the flexibility to adjust the level of its capital investments as circumstances warrant. The Company develops its capital program by prioritizing life-of-project returns to grow its net asset value over the long term, while balancing the short- and long-term growth potential of each of its assets, including the Elk Hills unit. The Company regularly monitors internal performance and external factors and adjust its capital investment program with the objective of creating the most value from its asset portfolio, including the Elk Hills unit.
The following table sets forth the Company’s production estimates for oil, NGLs and natural gas expected to be produced from the Elk Hills unit based on low- and high-end capital investment scenarios, the estimated production achieved based on each capital investment scenario and an estimated calculation of the net production proceeds expected to be paid to Elk Hills RoyaltyCo with respect to the Royalty Interest for the year ending December 31, 2020. The Company currently estimates that it would take approximately $150 million per year of capital investments to maintain current levels of production from the Elk Hills unit.
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Year Ending December 31, 2020 | ||||||||
Low-End | High-End | |||||||
Estimated Total Elk Hills Unit Capital Investments (millions)(3) | $ | 236 | $ | 336 | ||||
Estimated Total Elk Hills Unit Production (MBoe)(1)(2) | 17,600 | 18,000 | ||||||
Estimated Realized Prices(4): | ||||||||
Oil ($/Bbl) | $ | 67 | $ | 67 | ||||
NGLs ($/Bbl) | $ | 32 | $ | 32 | ||||
Natural gas ($/Mcf) | $ | 2.5 | $ | 2.5 | ||||
Estimated Elk Hills RoyaltyCo Financial Summary(5): | ||||||||
Estimated Elk Hills Unit Revenue (millions) | $ | 779 | $ | 815 | ||||
Estimated production and ad valorem taxes (millions) | 17 | 18 | ||||||
Estimated marketing and transportation costs (millions) | 8 | 10 | ||||||
Estimated Elk Hills RoyaltyCo Production Proceeds (millions) | $ | 754 | $ | 787 | ||||
Percentage Allocable to Elk Hills RoyaltyCo(6) | 4.30% | 4.30% | ||||||
Estimated Total Cash to Elk Hills RoyaltyCo (millions)(7) | $ | 32 | $ | 34 | ||||
_______________
(1) | Production estimates for 2020 include 50%, 20% and 30% of oil, NGLs and natural gas volumes, respectively, that are based on the December 31, 2019 reserve report, with remaining volumes relating to unproved resources. |
(2) | Natural gas volumes have been converted to Boe based on the equivalence of energy content of six thousand cubic feet of natural gas (Mcf) to one barrel of oil. Barrels of oil equivalence does not necessarily result in price equivalence. |
(3) | Includes $186 million of capital investments expected to be funded by Alpine pursuant to the Alpine JV. Please see “-Alpine Joint Venture” for additional details regarding the Alpine JV. |
(4) | Price estimates for 2020 were based on the December 31, 2019 strip prices of $63.38/Bbl for Brent and $2.29/MMBtu for NYMEX Henry Hub. Elk Hills oil realizations were estimated at 106% of Brent and gas realizations were estimated at 109% of NYMEX Henry Hub. Elk Hills RoyaltyCo has not entered into hedging arrangements with respect to the oil, natural gas and NGLs production from the underlying properties, and the Company has not entered into any hedging arrangements for the benefit of Elk Hills RoyaltyCo. |
(5) | Calculated based on the terms of the conveyance creating the Royalty Interest using the assumptions described in this table and accompanying footnotes. |
(6) | Percentage allocable to Elk Hills RoyaltyCo to be reduced proportionally based on the principal amount of Royalty Notes issued on the consummation of the Offers out of the maximum issuable amount, assuming maximum participation, of $340 million. |
(7) | A $1.00 change in the price of Brent changes the estimated total cash to Elk Hills RoyaltyCo in 2020 by approximately $400,000. |
The Company believes the projected operational and financial information set forth above was prepared on a reasonable basis and are not fact and should not be relied upon as being necessarily indicative of future results. Neither the Company nor Elk Hills RoyaltyCo undertakes any obligation to update the financial forecast to reflect events or circumstances after the date hereof and readers are cautioned not to place undue reliance on the projected financial information. Neither the Company’s independent auditors, nor any other independent accountants, have compiled, examined, or performed any procedures with respect to the projected financial information contained herein, nor have they expressed any opinion or any other form of assurance on such information or its achievability, and assume no responsibility for, and disclaim any association with, the projected financial information. The amount of production proceeds to ultimately be paid on the Royalty Interest in the future will depend on many factors, some of which are beyond the Company’s control, including:
• | the amount of capital ultimately deployed by the Company and its JV partners developing the Elk Hills unit; |
• | the success of the Company’s development plan; |
• | oil, NGLs and natural gas prices; and |
• | the amount of marketing and transportation costs and production and ad valorem taxes. |
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In addition, amounts ultimately available for the Elk Hills RoyaltyCo to make interest and principal payments on the Royalty Notes and dividends on the Class B Shares will be subject to the administrative expenses incurred by Elk Hills RoyaltyCo, including amounts owed to the Company pursuant to the Administrative Services Agreement. Actual cash distributions paid on the Royalty Interest and amounts available to make interest and principal payments on the Royalty Notes and dividends on the Class B Shares, therefore, could vary significantly based upon events or conditions occurring that are different from the events or conditions assumed to occur for purposes of these projections. Cash distributions paid on the Royalty Interest will be particularly sensitive to fluctuations in commodity prices. In addition, as a result of typical production declines for the Company’s properties in the Elk Hills unit, production estimates generally decrease from year to year with respect to the existing wells in the Elk Hills unit. However, the production estimates above reflect that these declines are expected to be offset by additional production from new wells as they come on line. The timing of the completion of, and the amount of production attributable to, the new wells in the Company’s 2020 capital plan are substantially dependent on the Company executing its drilling plans with respect to the drilling and completion of the wells, including funding the capital necessary to execute its drilling plan other than the amounts expected to be funded pursuant to the Alpine JV.
Our Debt and Certain Credit Metrics
The following table sets forth our debt (as of September 30, 2019) and certain credit metrics (for the last twelve-months ended September 30, 2019), in each case (i) on an actual basis and (ii) as adjusted to give effect to the consummation of the Offers, the Supporting Subscription Agreements and certain other items.
Actual September 30, 2019 | Exchange Offer Adjustments(1) | Other Adjustments | Pro Forma | ||||||||||||||||
Debt | |||||||||||||||||||
2014 FLFO Revolving Credit Facility | $ | 514 | — | $ | 105 | (4) | $ | 619 | (4) | ||||||||||
2017 First Lien Term Loan | 1,300 | — | — | 1,300 | |||||||||||||||
2016 1.5 Lien Term Loan | 1,000 | — | — | 1,000 | |||||||||||||||
2020 1.75L Term Loan | — | 700 | (2) | — | 700 | ||||||||||||||
First Lien Debt | $ | 2,814 | $ | 700 | $ | 105 | $ | 3,619 | |||||||||||
8.00% 2L Notes due 2022 | 1,838 | (1,650 | ) | (3) | (30 | ) | (5) | 158 | |||||||||||
Total Secured Debt | $ | 4,652 | $ | (950 | ) | $ | 75 | $ | 3,777 | ||||||||||
5.00% Senior Notes due 2020 | 100 | — | (100 | ) | (4) | — | |||||||||||||
5.50% Senior Notes due 2021 | 100 | (26 | ) | (3) | — | 74 | |||||||||||||
6.00% Senior Notes due 2024 | 144 | (7 | ) | (3) | — | 137 | |||||||||||||
Total Debt | $ | 4,996 | $ | (983 | ) | $ | (25 | ) | $ | 3,988 | |||||||||
Unrestricted Cash | 20 | — | — | 20 | |||||||||||||||
Net Debt | $ | 4,976 | $ | (983 | ) | $ | (25 | ) | $ | 3,968 | |||||||||
Mezzanine Equity | $ | 789 | $ | — | $ | — | $ | 789 | |||||||||||
Credit Metrics LTM 3Q19 | |||||||||||||||||||
Cash Interest(9) | $ | 457 | $ | (64 | ) | (6) | $ | (1 | ) | (8) | $ | 392 | |||||||
Adjusted EBITDAX(9) | $ | 1,148 | $ | (32 | ) | (7) | $ | — | $ | 1,116 | |||||||||
Net Debt / Adjusted EBITDAX(9) | 4.3x | (0.7x) | (0.0x) | 3.6x | |||||||||||||||
_______________
(1) | Assumes maximum participation by holders of the 8% Notes, in addition to giving effect to the Supporting Subscription Agreements. Also assumes all holders whose Notes were tendered and accepted for exchange receive the Early Participation Premium. The actual aggregate principal amount of 8% Notes, 5½% Notes and 6% Notes exchanged may differ. It is not a condition to the Exchange Offers that any minimum aggregate principal amount of Notes, or minimum aggregate principal amount of Notes of a particular series, be exchanged. To the extent that the Exchange Offers are not fully subscribed, the aggregate Exchange Consideration, including the aggregate principal amount of New Term Loans, will be reduced proportionally. |
(2) | Represents the face value of 1.75L Term Loan. |
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(3) | Represents the face value of the 2L, 2021 and 2024 Notes being exchanged, including pre-committed amounts. Accounting for $26 million of pre-committed 2021 Notes and $7 million of pre-committed 2024 Notes, the maximum amount of 2L reduction is $1,650 million inclusive of $452 million of pre-committed 2L Notes. |
(4) | Represents $100 million of borrowing to repay the 2020 Notes, $10 million of borrowing to pay for the open market purchases of debt from October 1, 2019 through January 10, 2020 and a preliminary estimate of transaction and debt issue costs, partially offset by approximately $40 million proceeds from asset sales since October 1, 2019. After the repayment of the Company’s 5% senior notes due 2020, there was $495 million outstanding under our 2014 Revolving Credit Facility as of January 31, 2020. |
(5) | Represents open market purchases since October 1, 2019. |
(6) | Reflects net interest savings resulting from the Exchange Offers assuming the Exchange Offers were consummated on October 1, 2018. |
(7) | Reflects the cash paid to Elk Hills RoyaltyCo assuming the Exchange Offers were consummated on October 1, 2018. |
(8) | Reflects the net interest savings from post-September 30, 2019 open market purchases, assuming such purchases were consummated on October 1, 2018. |
(9) | Cash Interest and Adjusted EBITDAX are non-GAAP financial measures. For definitions of these measures and reconciliations to the nearest financial measures calculated in accordance with GAAP, please see “-Non-GAAP Financial Information.” |
Non-GAAP Financial Information
PV-10 of revenues represents the year-end present value of estimated future cash inflows from proved oil and natural gas reserves, discounted at 10% per annum to reflect the timing of future cash flows and using SEC-prescribed pricing assumptions for the period. PV-10 of cash flows represents the year-end present value of estimated future cash inflows from proved oil and natural gas reserves, less future operating and capital costs, discounted at 10% per annum to reflect the timing of future cash flows and using SEC-prescribed pricing assumptions for the period. PV-10 of cash flows differ from standardized measure because standardized measure includes the effects of future income taxes on future net cash flows. Neither PV-10 of revenues, PV-10 of cash flows nor standardized measure should be construed as the fair value of the oil and natural gas reserves attributable to the underlying properties. 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 of revenues and PV-10 of cash flows facilitate the comparisons to other companies as it is not dependent on the tax-paying status of the entity.
The following table provides a reconciliation of PV-10 of revenues and PV-10 of cash flows of the proved reserves attributable to the underlying properties to the standardized measure of discounted future net cash flows using SEC pricing at December 31, 2019 (in millions):
December 31, 2019 | |||
PV-10 of revenues | $ | 5,158 | |
Less: present value of future operating costs discounted at 10% | $ | 1,622 | |
Less: present value of future capital costs discounted at 10% | $ | 559 | |
PV-10 of cash flows | $ | 2,977 | |
Less: present value of future income taxes discounted at 10% | $ | 719 | |
Standardized measure of discounted future net cash flows | $ | 2,258 | |
The following table provides a reconciliation of PV-10 of cash flows of the Company’s proved reserves to the standardized measure of discounted future net cash flows using SEC pricing at December 31, 2019 (in millions):
December 31, 2019 | |||
PV-10 of cash flows | $ | 6,849 | |
Less: present value of future income taxes discounted at 10% | $ | 1,618 | |
Standardized measure of discounted future net cash flows | $ | 5,231 | |
GAAP does not prescribe any corresponding measure for PV-10 of reserves as of an interim date or on any basis other than SEC prices. As a result, it is not practicable for us to reconcile PV-10 of revenues or PV-10 of cash flows using strip pricing as of December 31, 2019 to GAAP standardized measure.
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Cash Interest represents interest and debt expense, net, plus amortization of deferred gain, capitalized interest and working capital adjustments, less amortization of deferred financing costs. The following table provides a reconciliation of Cash Interest to interest and debt expenses, net, on a quarterly basis for twelve-months ended September 30, 2019 (in millions):
4Q 2018 | 1Q 2019 | 2Q 2019 | 3Q 2019 | LTM 3Q 2019 | ||||||||||||||||
Interest and debt expense, net | $ | 98 | $ | 100 | $ | 98 | $ | 95 | $ | 391 | ||||||||||
Amortization of deferred gain | 18 | 18 | 18 | 18 | 72 | |||||||||||||||
Amortization of deferred financing costs | (7) | (7) | (8) | (6) | (28) | |||||||||||||||
Capitalized interest | 2 | 3 | 3 | 4 | 12 | |||||||||||||||
Working capital adjustments | 46 | (42) | 42 | (36) | 10 | |||||||||||||||
Cash Interest | $ | 157 | $ | 72 | $ | 153 | $ | 75 | $ | 457 | ||||||||||
Adjusted EBITDAX is defined as earnings before interest expense; income taxes; depreciation, depletion and amortization; exploration expense; other unusual, out-of-period and infrequent items; and other non-cash items. The Company believes this measure provides useful information in assessing its financial condition, results of operations and cash flows and is widely used by the industry, the investment community and the Company’s lenders. Although this is a non-GAAP measure, the amounts included in the calculation were computed in accordance with GAAP. Certain items excluded from this non-GAAP measure are significant components in understanding and assessing our financial performance, such as the Company’s cost of capital and tax structure, as well as the historic cost of depreciable and depletable assets. This measure should be read in conjunction with the information contained in the Company’s financial statements prepared in accordance with GAAP. A version of Adjusted EBITDAX and Cash Interest are material components of certain of our financial covenants under our 2014 Revolving Credit Facility and is provided in addition to, and not as an alternative for, financial measures calculated in accordance with GAAP.
The following table presents a reconciliation of Adjusted EBITDAX to net income (loss) on a quarterly basis for the twelve-months ended September 30, 2019 (in millions):
4Q 2018 | 1Q 2019 | 2Q 2019 | 3Q 2019 | LTM 3Q 2019 | ||||||||||||||||
Net income (loss) | $ | 392 | $ | (44 | ) | $ | 41 | $ | 127 | $ | 516 | |||||||||
Interest expense, net | 98 | 100 | 98 | 95 | 391 | |||||||||||||||
Depreciation, depletion and amortization | 130 | 118 | 121 | 118 | 487 | |||||||||||||||
Exploration expense | 16 | 10 | 10 | 5 | 41 | |||||||||||||||
Unusual infrequent and other items | (320) | 98 | (26) | (77) | (325) | |||||||||||||||
Other non-cash items | (2) | 19 | 11 | 10 | 38 | |||||||||||||||
Adjusted EBITDAX | $ | 314 | $ | 301 | $ | 255 | $ | 278 | $ | 1,148 | ||||||||||
The following table presents a reconciliation of Adjusted EBITDAX to net cash provided by operating activities on a quarterly basis for the twelve-months ended September 30, 2019 (in millions):
4Q 2018 | 1Q 2019 | 2Q 2019 | 3Q 2019 | LTM 3Q 2019 | ||||||||||||||||
Net cash provided by operating activities | $ | 68 | $ | 158 | $ | 114 | $ | 268 | $ | 608 | ||||||||||
Cash interest | 157 | 72 | 153 | 75 | 457 | |||||||||||||||
Exploration expenditures | 3 | 4 | 6 | 5 | 18 | |||||||||||||||
Working capital changes | 86 | 67 | (18) | (70) | 65 | |||||||||||||||
Other, net | 0 | 0 | 0 | 0 | 0 | |||||||||||||||
Adjusted EBITDAX | $ | 314 | $ | 301 | $ | 255 | $ | 278 | $ | 1,148 | ||||||||||
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ADDITIONAL INFORMATION
In addition to the information excerpted above, CRC provided the following additional information to the holders of its 8% Second Lien Secured Notes due 2022, 6% Senior Unsecured Notes due 2024 and 5 ½% Senior Unsecured Notes due 2021 regarding its Value Creation Index and the returns associated with the identified drilling locations in Elk Hills inventory:
Average before-tax IRR of 52% and VCI of 1.9 for proved undeveloped locations in Elk Hills inventory as of December 31, 2019 and based on SEC prices. This includes proved reserves for CRC and Alpine JV. Capital costs includes drilling, completion and tie-ins. IRR and VCI to CRC are presented on a pro forma basis, net of the contemplated 4.3% royalty conveyance (such percentage to be reduced proportionally based on the principal amount of Royalty Notes issued on the consummation of the Offers out of the maximum issuable amount, assuming maximum participation, of $340 million).
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