UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
Date of Report (Date of Earliest Event Reported): July 19, 2024
(Exact Name of Registrant as Specified in its Charter)
| (State or Other Jurisdiction of Incorporation) | (Commission File Number) | (IRS Employer Identification No.) | ||||||
| (Address of Principal Executive Offices) | (Zip Code) | ||||
Registrant’s Telephone Number, Including Area Code: (713 ) 215-7000
Not Applicable
(Former Name or Former Address, if Changed Since Last Report)
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425) | |||||
Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12) | |||||
Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b)) | |||||
Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c)) | |||||
Securities registered pursuant to Section 12(b) of the Act:
| Title of Each Class | Trading Symbol(s) | Name of Each Exchange on Which Registered | ||||||
Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (17 CFR 230.405) or Rule 12b-2 of the Securities Exchange Act of 1934 (17 CFR 240.12b-2).
Emerging growth company ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Item 8.01 Other Events
CrownRock Acquisition
As previously disclosed, on December 10, 2023, Occidental Petroleum Corporation, a Delaware corporation (“Occidental”), entered into a Partnership Interest Purchase Agreement (the “Purchase Agreement”) with CrownRock Holdings, L.P., a Delaware limited partnership (“Limited Partner”), CrownRock GP, LLC, a Delaware limited liability company (“General Partner” and, together with the Limited Partner, the “Sellers”), Coral Holdings LP, LLC, a Delaware limited liability company and a wholly owned indirect subsidiary of Occidental (“LP Purchaser”), and Coral Holdings GP, LLC, a Delaware limited liability company and wholly owned indirect subsidiary of Occidental (“GP Purchaser” and, together with the LP Purchaser, the “Purchasers”). Subject to the terms and conditions of the Purchase Agreement, the Purchasers will purchase 100% of the issued and outstanding partner interests of CrownRock, L.P., a Delaware limited partnership (“CrownRock”), from the Sellers (such transaction, the “Acquisition” and, together with the other transactions contemplated by the Purchase Agreement, the “Transactions”).
The Acquisition is conditioned on, among other things, the expiration or termination of the waiting period (and any extensions thereof) under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (the “HSR Act”), which has occurred. With the expiration of the waiting period, the conditions to closing have been satisfied, other than those that are to be satisfied at closing. The Acquisition is expected to close in August 2024, after completion of the financing marketing period contemplated by the Purchase Agreement.
Ecopetrol Transaction
In 2019, Occidental Midland Basin, LLC, a Delaware limited liability company and Occidental’s wholly owned indirect subsidiary (“Occidental Midland Basin”), and Ecopetrol Permian LLC, a Delaware limited liability company (“Ecopetrol”), formed Rodeo Midland Basin, LLC, a Delaware limited liability company (the “Rodeo Midland Basin Joint Venture”), as a joint venture to develop and operate oil and gas properties in the Midland Basin. Under that joint venture, each of Occidental Midland Basin and Ecopetrol were given the right, subject to certain conditions, to participate in oil and gas interests acquired by the other and its affiliates in an area of mutual interest. On March 4, 2024, Occidental Midland Basin and Ecopetrol entered into a letter agreement regarding Ecopetrol’s evaluation of CrownRock’s assets. On May 31, 2024, Ecopetrol notified Occidental of its intent to acquire an undivided thirty percent (30%) interest in the CrownRock assets, subject to the negotiation of a mutually agreeable transaction structure.
Occidental and Ecopetrol are engaged in discussions regarding a structure for Ecopetrol’s potential acquisition of an undivided thirty percent (30%) interest in the CrownRock assets (the “Ecopetrol Transaction”). If consummated, Occidental expects the Ecopetrol Transaction purchase price to be approximately $3.6 billion (which equates to approximately thirty percent (30%) of the aggregate consideration to be paid by Occidental in connection with the Acquisition), subject to customary purchase price adjustments based on a January 1, 2024 effective date.
If a definitive agreement is entered into, Occidental expects it will be subject to the satisfaction or waiver of customary closing conditions, including, among other things, the expiration of the waiting
period under the HSR Act, the receipt of approval from the Committee on Foreign Investment in the United States and the closing of the Acquisition. However, there can be no certainty that Occidental and Ecopetrol will enter into a definitive agreement with respect to the Ecopetrol Transaction, about the timing, terms or conditions of any such definitive agreement or, if any such agreement is entered into, that the Ecopetrol Transaction would be completed.
If Occidental and Ecopetrol are unable to reach agreement regarding the structure of the Ecopetrol Transaction and the joint ownership, development and operation of the CrownRock assets related to such Ecopetrol Transaction in August 2024, then Ecopetrol will have an option to elect for the Rodeo Midland Basin Joint Venture to acquire the CrownRock assets, resulting in an indirect ownership by Ecopetrol of an undivided forty-nine percent (49%) interest in the CrownRock assets. This option expires in August 2024, and there is no assurance that Ecopetrol can or would exercise such an option.
Occidental expects to use any proceeds from the Ecopetrol Transaction to pay down a portion of its term loans.
Financial Statements
The following audited consolidated financial statements of CrownRock as of and for the year ended December 31, 2023 and the related notes thereto are filed as Exhibit 99.1 to this Current Report on Form 8-K and are incorporated herein by reference:
•Independent Auditor’s Report;
•Consolidated Balance Sheet at December 31, 2023;
•Consolidated Statement of Income and Comprehensive Income for the year ended December 31, 2023;
•Consolidated Statement of Partners’ Capital for the year ended December 31, 2023;
•Consolidated Statement of Cash Flows for the year ended December 31, 2023; and
•Notes to Consolidated Financial Statements.
Attached hereto as Exhibit 23.1 is the consent of BDO USA, P.C., the independent auditors to CrownRock, related to the above-referenced audited consolidated financial statements of CrownRock filed as Exhibit 99.1 to this Current Report on Form 8-K.
The report prepared by Cawley, Gillespie & Associates, Inc. relating to CrownRock’s estimated quantities of its proved natural gas, natural gas liquids and crude oil reserves as of December 31, 2023 is filed as Exhibit 99.2 to this Current Report on Form 8-K and is incorporated by reference herein.
Attached hereto as Exhibit 23.2 is the consent of Cawley, Gillespie & Associates, Inc., the independent petroleum engineers to CrownRock, related to the above-referenced report filed as Exhibit 99.2 to this Current Report on Form 8-K.
The following unaudited condensed consolidated financial statements of CrownRock as of and for the three months ended March 31, 2024 and the related notes thereto are filed as Exhibit 99.3 to this Current Report on Form 8-K and are incorporated herein by reference:
•Unaudited Condensed Consolidated Statement of Income for the Three Months Ended March 31, 2024;
•Unaudited Condensed Consolidated Balance Sheet at March 31, 2024;
•Unaudited Condensed Consolidated Statement of Partners' Capital for the Three Months Ended March 31, 2024;
•Unaudited Condensed Consolidated Statement of Cash Flows for the Three Months Ended March 31, 2024; and
•Notes to the Unaudited Condensed Consolidated Financial Statements
The following unaudited pro forma condensed combined financial statements combining the historical consolidated financial statements of Occidental and its subsidiaries and CrownRock and its majority-owned subsidiaries to give effect to the Transactions and adjusting for the Ecopetrol Transaction (which is subject to entry into definitive agreements and consummation of the transactions contemplated thereby), are filed as Exhibit 99.4 to this Current Report on Form 8-K and are incorporated herein by reference:
•Unaudited Pro Forma Condensed Combined Balance Sheet as of March 31, 2024;
•Unaudited Pro Forma Condensed Statement of Combined Operations for the year ended December 31, 2023 and the three months ended March 31, 2024; and
•Notes to Pro Forma Condensed Combined Financial Statements.
Cautionary Statement Regarding Forward-Looking Statements
This Current Report on Form 8-K (“Current Report”) contains forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act, including but not limited to statements about Occidental’s expectations, beliefs, plans or forecasts. All statements other than statements of historical fact are “forward-looking statements” for purposes of federal and state securities laws, including, but not limited to: any projections of revenue or other financial items or future financial position or sources of financing; any statements of the plans, strategies and objectives of management for future operations or business strategy; any statements regarding future economic conditions or performance; any statements of belief; and any statements of assumptions underlying any of the foregoing. Words such as “estimate,” “project,” “will,” “should,” “could,” “may,” “anticipate,” “plan,” “intend,” “believe,” “expect,” “target,” “commit,” “advance,” or similar expressions that convey the prospective nature of events or outcomes are generally indicative of forward-looking statements. You should not place undue reliance on these forward-looking statements, which speak only as of the date of this Current Report unless an earlier date is specified. Unless legally required, Occidental does not undertake any obligation to update, modify or withdraw any forward-looking statements as a result of new information, future events or otherwise.
Forward-looking statements involve estimates, expectations, projections, goals, forecasts, assumptions, risks and uncertainties. Actual outcomes or results may differ from anticipated results, sometimes materially. Factors that could cause results to differ from those projected or assumed in any forward-looking statement include, but are not limited to: general economic conditions, including slowdowns and recessions, domestically or internationally; Occidental’s indebtedness and other payment obligations, including the need to generate sufficient cash flows to fund operations; Occidental’s ability to successfully monetize select assets and repay or refinance debt and the impact of changes in Occidental’s credit ratings or future increases in interest rates; assumptions about energy markets; global and local commodity and commodity-futures pricing fluctuations and volatility; supply and demand considerations for, and the prices of, Occidental’s products and services; actions by the Organization of the Petroleum Exporting Countries (“OPEC”) and non-OPEC oil producing countries; results from operations and competitive conditions; future impairments of Occidental's proved and unproved oil and gas properties or equity investments, or write-downs of productive assets, causing charges to earnings;
unexpected changes in costs; inflation, its impact on markets and economic activity and related monetary policy actions by governments in response to inflation; availability of capital resources, levels of capital expenditures and contractual obligations; the regulatory approval environment, including Occidental's ability to timely obtain or maintain permits or other government approvals, including those necessary for drilling and/or development projects; Occidental's ability to successfully complete, or any material delay of, field developments, expansion projects, capital expenditures, efficiency projects, acquisitions or divestitures, including the Acquisition and the Ecopetrol Transaction; risks associated with acquisitions, mergers and joint ventures, such as difficulties integrating businesses, uncertainty associated with financial projections, projected synergies, restructuring, increased costs and adverse tax consequences; uncertainties and liabilities associated with acquired and divested properties and businesses; uncertainties about the estimated quantities of oil, natural gas liquids and natural gas reserves; lower-than-expected production from development projects or acquisitions; Occidental’s ability to realize the anticipated benefits from prior or future streamlining actions to reduce fixed costs, simplify or improve processes and improve Occidental’s competitiveness; exploration, drilling and other operational risks; disruptions to, capacity constraints in, or other limitations on the pipeline systems that deliver Occidental’s oil and natural gas and other processing and transportation considerations; volatility in the securities, capital or credit markets, including capital market disruptions and instability of financial institutions; government actions, war (including the Russia-Ukraine war and conflicts in the Middle East) and political conditions and events; health, safety and environmental (“HSE”) risks, costs and liability under existing or future federal, regional, state, provincial, tribal, local and international HSE laws, regulations and litigation (including related to climate change or remedial actions or assessments); legislative or regulatory changes, including changes relating to hydraulic fracturing or other oil and natural gas operations, retroactive royalty or production tax regimes, and deep-water and onshore drilling and permitting regulations; Occidental's ability to recognize intended benefits from its business strategies and initiatives, such as Occidental's low-carbon ventures businesses or announced greenhouse gas emissions reduction targets or net-zero goals; potential liability resulting from pending or future litigation, government investigations and other proceedings; disruption or interruption of production or manufacturing or facility damage due to accidents, chemical releases, labor unrest, weather, power outages, natural disasters, cyber-attacks, terrorist acts or insurgent activity; the scope and duration of global or regional health pandemics or epidemics, and actions taken by government authorities and other third parties in connection therewith; the creditworthiness and performance of Occidental's counterparties, including financial institutions, operating partners and other parties; failure of risk management; Occidental’s ability to retain and hire key personnel; supply, transportation, and labor constraints; reorganization or restructuring of Occidental’s operations; changes in state, federal or international tax rates; and actions by third parties that are beyond Occidental’s control.
Additional information concerning these and other factors that may cause Occidental’s results of operations and financial position to differ from expectations can be found in Occidental’s filings with the U.S. Securities and Exchange Commission, including Occidental’s 2023 Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K.
Item 9.01 Financial Statements and Exhibits.
(d) Exhibits.
| 23.1 | |||||
| 23.2 | |||||
| 99.1 | |||||
| 99.2 | |||||
| 99.3 | |||||
| 99.4 | |||||
| 104 | Cover Page Interactive Data File (embedded within the Inline XBRL document). | ||||
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
| OCCIDENTAL PETROLEUM CORPORATION | ||||||||
| By: | /s/ Christopher O. Champion | |||||||
| Name: | Christopher O. Champion | |||||||
| Title: | Vice President, Chief Accounting Officer and Controller | |||||||
Exhibit 23.1
Consent of Independent Auditor
We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (Nos. 333-55404, 333-266420 and 333-235445) and Form S-8 (Nos. 333-83124, 333-142705, 333-203801, 333-207413, 333-224691, 333-237414 and 333-239236) of Occidental Petroleum Corporation of our report dated March 8, 2024, relating to the consolidated financial statements of CrownRock, L.P., which appears in this Form 8-K.
/s/ BDO USA, P.C.
Houston, Texas
July 19, 2024
Exhibit 23.2
CAWLEY, GILLESPIE & ASSOCIATES, INC.
PETROLEUM CONSULTANTS
| 6500 RIVER PLACE BLVD, SUITE 3-200 | 306 WEST SEVENTH STREET, SUITE 302 | 1000 LOUISIANA STREET, SUITE 1900 | ||||||
| AUSTIN, TEXAS 78730-1111 | FORT WORTH, TEXAS 76102-4987 | HOUSTON, TEXAS 77002-5008 | ||||||
| 512-249-7000 | 817- 336-2461 | 713-651-9944 | ||||||
www.cgaus.com
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS
We hereby consent to the inclusion in the Form 8-K of Occidental Petroleum Corporation (“Occidental”) to be filed with the Securities and Exchange Commission on or around July 19, 2024, of our report dated January 24, 2024, with respect to our estimates of proved reserves and future net revenue to CrownRock, L.P. We also hereby consent to the incorporation by reference of said report in Occidental's registration statements (No. 333-55404, 333-83124, 333-142705, 333-203801, 333-207413, 333-224691, 333-266420, 333-235445, 333-237414 and 333-239236).
/s/ W. Todd Brooker
W. Todd Brooker, President
CAWLEY, GILLESPIE & ASSOCIATES, INC.
Texas Registered Engineering Firm F-693
Austin, Texas
July 19, 2024
Exhibit 99.1
Consolidated Financial Statements
of CrownRock, L.P. and Subsidiaries
As of and for the Year Ended December 31, 2023
TABLE OF CONTENTS
FINANCIAL INFORMATION
| Page | |||||
| Independent Auditor’s Report | 3 | ||||
| Consolidated Financial Statements: | |||||
| Consolidated Balance Sheet as of December 31, 2023 | 5 | ||||
Consolidated Statement of Income and Comprehensive Income for the Year Ended December 31, 2023 | 6 | ||||
| Consolidated Statement of Partners’ Capital for the Year Ended December 31, 2023 | 7 | ||||
| Consolidated Statement of Cash Flows for the Year Ended December 31, 2023 | 8 | ||||
| Notes to Consolidated Financial Statements | 9 | ||||
| Unaudited Supplementary Information | 29 | ||||
2
Independent Auditor’s Report
To the Partners
CrownRock, L.P.
Midland, Texas
CrownRock, L.P.
Midland, Texas
Opinion
We have audited the consolidated financial statements of CrownRock, L.P. and its subsidiaries (the “Partnership”), which comprise the consolidated balance sheet as of December 31, 2023, and the related consolidated statements of income and comprehensive income, partners’ capital, and cash flows for the year then ended, and the related notes to the consolidated financial statements.
In our opinion, the accompanying consolidated financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2023, and the results of its operations and its cash flows for the year then ended, in accordance with accounting principles generally accepted in the United States of America.
Basis for Opinion
We conducted our audit in accordance with auditing standards generally accepted in the United States of America (GAAS). Our responsibilities under those standards are further described in the Auditor’s Responsibilities for the Audit of the Financial Statements section of our report. We are required to be independent of the Partnership and to meet our other ethical responsibilities, in accordance with the relevant ethical requirements relating to our audit. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.
Emphasis of Matter
As described in Notes B, G and H, the Partnership engages in significant transactions with related parties. Our opinion is not modified with respect to this matter.
Responsibilities of Management for the Financial Statements
Management is responsible for the preparation and fair presentation of the consolidated financial statements in accordance with accounting principles generally accepted in the United States of America, and for the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.
In preparing the consolidated financial statements, management is required to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the Partnership’s ability to continue as a going concern within one year after the date that the consolidated financial statements are available to be issued.
Auditor’s Responsibilities for the Audit of the Financial Statements
Our objectives are to obtain reasonable assurance about whether the consolidated financial statements as a whole are free from material misstatement, whether due to fraud or error, and to issue an auditor’s report that includes our opinion. Reasonable assurance is a high level of assurance but is not absolute assurance and therefore is not a guarantee that an audit conducted in accordance with GAAS will always detect a material misstatement when it exists. The risk of not detecting a material misstatement resulting from fraud is higher than for one resulting from error, as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control. Misstatements are considered material if there is a substantial likelihood that, individually or in the aggregate, they would influence the judgment made by a reasonable user based on the consolidated financial statements.
In performing an audit in accordance with GAAS, we:
•Exercise professional judgment and maintain professional skepticism throughout the audit.
•Identify and assess the risks of material misstatement of the consolidated financial statements, whether due to fraud or error, and design and perform audit procedures responsive to those risks. Such procedures include examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements.
3
•Obtain an understanding of internal control relevant to the audit in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control. Accordingly, no such opinion is expressed.
•Evaluate the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluate the overall presentation of the consolidated financial statements.
•Conclude whether, in our judgment, there are conditions or events, considered in the aggregate, that raise substantial doubt about the Partnership’s ability to continue as a going concern for a reasonable period of time.
We are required to communicate with those charged with governance regarding, among other matters, the planned scope and timing of the audit, significant audit findings, and certain internal control-related matters that we identified during the audit.
/s/ BDO USA, P.C
Houston, Texas
March 8, 2024
March 8, 2024
4
CROWNROCK, L.P.
CONSOLIDATED BALANCE SHEET
December 31, 2023 | |||||
| (in thousands) | |||||
ASSETS | |||||
Current assets: | |||||
| Cash and cash equivalents | $ | 144,794 | |||
| Accounts receivable – related party: | |||||
| Oil and natural gas | 196,457 | ||||
| Other | 54,266 | ||||
| Prepaid costs and other current assets | 1,422 | ||||
| Total current assets | 396,939 | ||||
Oil and natural gas properties, net, successful efforts method of accounting | 3,879,137 | ||||
Other property and equipment, net | 156,600 | ||||
Deferred loan costs, net | 9,519 | ||||
| Other assets | 33 | ||||
| Total Assets | $ | 4,442,228 | |||
| LIABILITIES AND PARTNERS' CAPITAL | |||||
| Current liabilities: | |||||
| Accounts payable – related party | $ | 145 | |||
| Accrued drilling cost – related party | 75,739 | ||||
| Other accrued liabilities – related party | 14,121 | ||||
| Accrued interest payable | 13,307 | ||||
| Current portion of long-term debt | 751 | ||||
| Other current liabilities | 203 | ||||
| Asset retirement obligations, current portion | 691 | ||||
| Total current liabilities | 104,957 | ||||
Long-term debt, net | 1,237,249 | ||||
| Asset retirement obligations | 46,597 | ||||
| Total liabilities | 1,388,803 | ||||
Commitments and Contingencies (Note K) | |||||
| CrownRock, L.P. Partners' Capital | 3,053,580 | ||||
| Non-controlling interest in subsidiary | (155) | ||||
| Total Partners' Capital | 3,053,425 | ||||
| Total Liabilities and Partners' Capital | $ | 4,442,228 | |||
See accompanying notes to these consolidated financial statements.
5
CROWNROCK, L.P.
CONSOLIDATED STATEMENT OF INCOME AND COMPREHENSIVE INCOME
| Year Ended December 31, 2023 | |||||
| (in thousands) | |||||
| Statements of Income | |||||
| Revenues and gains: | |||||
| Oil and natural gas sales | $ | 2,381,947 | |||
| Gain on sales and exchanges of oil and natural gas properties | 2,124 | ||||
| Saltwater disposal | 66,939 | ||||
| Gathering system rent and transportation fees | 47,883 | ||||
| Fresh water supply | 20,024 | ||||
| Surface ownership | 4,071 | ||||
| Total revenues and gains | 2,522,988 | ||||
| Costs and expenses: | |||||
| Lease operating expense | 385,546 | ||||
| Production and ad valorem taxes | 138,803 | ||||
| Exploration costs | 5,849 | ||||
| Depreciation, depletion and amortization | 633,510 | ||||
| Accretion of discount on asset retirement obligation | 1,954 | ||||
| General and administrative | 24,227 | ||||
| Total costs and expenses | 1,189,889 | ||||
| Operating income | 1,333,099 | ||||
| Other income (expense): | |||||
| Gain on derivatives not designated as hedges | 186 | ||||
| Gain on extinguishment of debt | 1,473 | ||||
| Interest income | 4,811 | ||||
| Interest expense | (82,478) | ||||
| Other income (expense), net | 21,502 | ||||
| Total other income (expense) | (54,506) | ||||
| Net income | 1,278,593 | ||||
| Net loss attributable to non-controlling interest | 18 | ||||
| Net income attributable to CrownRock, L.P. | $ | 1,278,611 | |||
| Statement of Comprehensive Income | |||||
| Net income | $ | 1,278,593 | |||
| Less: Comprehensive loss attributable to the non-controlling interest | 18 | ||||
| Comprehensive income attributable to CrownRock, L.P. | $ | 1,278,611 | |||
See accompanying notes to these consolidated financial statements.
6
CROWNROCK, L.P.
CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL
| (in thousands, except units) | Limited Partner | Total CrownRock, LP Partners' Capital | Non- Controlling Interest | Total Partners' Capital | |||||||||||||
Units | Amount | ||||||||||||||||
| Balance, January 1, 2023 | 100 | $ | 2,375,151 | $ | 2,375,151 | $ | (137) | $ | 2,375,014 | ||||||||
| Net income (loss) | — | 1,278,611 | 1,278,611 | (18) | 1,278,593 | ||||||||||||
| Distributions to limited partner | — | (603,224) | (603,224) | — | (603,224) | ||||||||||||
| Capital contribution - unit based compensation | — | 3,042 | 3,042 | — | 3,042 | ||||||||||||
| Balance, December 31, 2023 | 100 | $ | 3,053,580 | $ | 3,053,580 | $ | (155) | $ | 3,053,425 | ||||||||
See accompanying notes to these consolidated financial statements.
7
CROWNROCK, L.P.
CONSOLIDATED STATEMENT OF CASH FLOWS
| Year Ended December 31, 2023 | |||||
| (in thousands) | |||||
| Cash flows from operating activities: | |||||
| Net income | $ | 1,278,593 | |||
| Adjustments to reconcile net income to net cash provided by operating activities: | |||||
| Depreciation, depletion and amortization | 633,510 | ||||
| Accretion of discount on asset retirement obligation | 1,954 | ||||
| Accretion of discount on long-term debt | 386 | ||||
| Amortization of deferred loan costs | 4,861 | ||||
| Unit-based compensation expense | 3,042 | ||||
| Exploration costs | 5,849 | ||||
| Settlements of asset retirement obligations | (485) | ||||
| Gain on derivative instruments | (36,196) | ||||
| Gain on extinguishment of debt | (1,473) | ||||
| Gain on sales and exchanges of oil and natural gas properties | (2,124) | ||||
| Gain on sale of equity investment | (21,769) | ||||
| Cash distributions from equity investments - return of capital | 1,148 | ||||
| Change in assets and liabilities: | |||||
| Accounts receivable – related party | (720) | ||||
| Prepaid costs and other current assets | (584) | ||||
| Accounts payable - related party | (898) | ||||
| Other accrued liabilities - related party | 2,927 | ||||
| Accrued interest payable | (1,902) | ||||
| Other liabilities | (10,655) | ||||
| Net cash flows provided by operating activities | 1,855,464 | ||||
| Cash flows from investing activities: | |||||
| Acquisition of leasehold and oil and natural gas properties | (3,429) | ||||
| Capital expenditures on oil and natural gas properties | (1,032,101) | ||||
| Additions to other property and equipment | (21,459) | ||||
| Proceeds from sale of oil and natural gas properties | 4,008 | ||||
| Distributions from equity investments - proceeds from sales | 21,769 | ||||
| Net cash flows used in investing activities | (1,031,212) | ||||
| Cash flows from financing activities: | |||||
| Distributions to limited partner | (603,509) | ||||
| Repurchase of 5.625% Senior Notes due 2025 | (160,012) | ||||
| Payments of repurchase costs on 5.625% Senior Notes due 2025 | (407) | ||||
| Repayments of long-term borrowings under construction loan | (1,963) | ||||
| Proceeds from long-term borrowings under credit facility | 334,500 | ||||
| Repayments of long-term borrowings under credit facility | (334,500) | ||||
| Payments for loan and debt issue costs | (10,808) | ||||
| Net cash flows used in financing activities | (776,699) | ||||
| Net increase in cash and cash equivalents | 47,553 | ||||
| Cash and cash equivalents, beginning of period | 97,241 | ||||
| Cash and cash equivalents, end of period | $ | 144,794 | |||
| Supplemental disclosure of cash flow information: | |||||
| Cash paid for interest | $ | 76,733 | |||
| Non-cash investing and financing activities: | |||||
| Oil and natural gas properties transferred to assets held for sale | $ | (1,975) | |||
| Change in accrued capital expenditures in accrued drilling cost and accrued liabilities | 48,579 | ||||
| Additions to asset retirement obligation | 4,173 | ||||
| Asset retirement obligation associated with properties exchanged or sold | (1,431) | ||||
| Change in accrued distributions to limited partner | (285) | ||||
See accompanying notes to these consolidated financial statements.
8
CROWNROCK, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A.Organization and Nature of Operations
CrownRock, L.P. (the “Partnership,” “we,” “us,” and “our”) is a Delaware limited partnership formed on February 14, 2007 by affiliates of CrownQuest Operating, LLC (“CrownQuest”), an independent oil and natural gas producer which is a wholly-owned subsidiary of one of the members of the Partnership’s ultimate general partner, CrownRock Holdings GP, LLC (“Holdings GP”), and Lime Rock Partners, a private equity firm focused on the oil and natural gas industry (“Lime Rock”). The Partnership’s principal business is the acquisition, development, exploration and production of oil and natural gas properties primarily located in the Permian Basin of West Texas.
On December 21, 2017, affiliates of CrownQuest’s management team and Lime Rock formed CrownRock Holdings, L.P., a Delaware limited partnership (“Holdings”). Effective January 1, 2018, the Partnership merged with a subsidiary of Holdings, and, as a result, Holdings is the sole limited partner of the Partnership and sole owner of the Partnership’s general partner, CrownRock GP, LLC (“CrownRock GP”). The Partnership admitted Holdings as its sole limited partner by issuing 100 new limited partnership units and cancelling all its other limited partner interests comprised of Class A, B, C, D and E limited partnership units. Holdings issued equivalent units of equivalent classes to the former limited partners of the Partnership.
On December 10, 2023, Holdings and CrownRock GP entered into a Partnership Interest Purchase Agreement (the “PIPA”), as amended, to sell their limited partner interests and general partner interests in the Partnership, respectively, to subsidiaries of Occidental Petroleum Corporation, a Delaware Corporation (“Occidental”), for total consideration of approximately $12.0 billion including the assumption of the Partnership’s existing debt (the “Partnership Sale Transaction”). See Note P – Agreement to Sell Partnership Interest to Occidental Petroleum Corporation.
B.Summary of Significant Accounting Policies
Organization and principles of consolidation. The Partnership is the sole member of Roddy Production Company, LLC (“Roddy”) and a 51% owner of Abajo Gas Transmission Company, LLC (“Abajo”).
On July 7, 2011, CrownRock Finance, Inc. (“CrownRock Finance”), a Delaware corporation and wholly-owned subsidiary of the Partnership, was organized for the sole purpose of serving as co-issuer of senior notes and it is currently a co-issuer of $868 million outstanding aggregate principal amount of 5.625% senior unsecured notes due 2025 (the “2025 Senior Notes”) and $376 million outstanding aggregate principal amount of 5.000% senior unsecured notes due 2029 issued at par (the “2029 Senior Notes” and, together with the 2025 Senior Notes, the “Senior Notes”). CrownRock Finance currently has, and will have, no operations, assets or liabilities other than with respect to the Partnership’s revolving credit facility, as amended (the “Credit Facility”), the Senior Notes or other debt securities the Partnership may issue in the future. See Note N – Long-term Debt.
On February 28, 2014, Canvasback Properties, LLC (“Canvasback”), a Texas corporation and wholly-owned subsidiary of the Partnership, was organized for the purpose of constructing, owning and managing an office building in Midland, Texas, which is the Partnership’s headquarters, and two field operations offices in Martin County, Texas.
On November 15, 2019, CR Royalties Management, LLC (“CR Management”), a Delaware limited liability company, and CR Royalties, L.P. (“CR Royalties”), a Delaware limited partnership, were organized for the purpose of owning oil and gas mineral interests and overriding royalty interests contributed by the Partnership. CR Management is a wholly-owned subsidiary of the Partnership. The Partnership owns 99% of CR Royalties and CR Management owns the remaining 1% of CR Royalties. The Partnership contributed the specified assets effective on January 1, 2020.
The Consolidated Financial Statements include the accounts of the Partnership and its majority owned subsidiaries. All intercompany accounts and transactions have been eliminated in consolidation.
Cash and cash equivalents. The Partnership considers all highly liquid instruments with original maturities of three months or less to be cash equivalents.
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B. Summary of Significant Accounting Policies (Continued)
Accounts receivable – related party and allowance for credit losses. CrownQuest operates 99% of the Partnership’s total wells and markets most of the Partnership’s oil and natural gas to various customers. In conjunction, CrownQuest has oil and natural gas sales receivables and joint interest receivables from third-party working interest owners. Oil and natural gas sales receivables are generally unsecured. CrownQuest monitors exposure to these customers primarily by reviewing credit ratings, financial statements and payment history. CrownQuest extends credit terms based on their evaluation of each customer’s creditworthiness. Receivables are considered past due if full payment is not received by the contractual due date. CrownQuest and the Partnership estimate uncollectible amounts based on the length of time that the accounts receivable has been outstanding, historical collection experience and current and future economic and market conditions, if failure to collect is expected to occur. CrownQuest records allowances for credit losses as reductions to the carrying values of the accounts receivables included in its financial statements if failure to collect an estimable portion is determined to be probable. The Partnership’s allowance for credit losses related to oil and natural gas sales receivables at December 31, 2023 is zero. CrownQuest bills the Partnership for such allowances related to joint interest receivables which are included in management fees and recorded by the Partnership in general and administrative costs in the consolidated statements of income and comprehensive income. CrownQuest had an allowance for joint interest receivable credit losses of $527 thousand at December 31, 2023. The Partnership does not have any off balance sheet credit exposure related to its customers.
Assets held for sale. Assets held for sale are valued at the lower of their carrying amount or estimated fair value, less costs to sell. If the carrying amount of the assets exceeds their estimated fair value, an impairment loss is recognized. Fair values are estimated using accepted valuation techniques, such as a discounted cash flow model, earnings multiples or indicative bids, when available. The Partnership considers historical experience and all available information at the time the estimates are made; however, the fair value that is ultimately realized upon the sale of the assets to be divested may differ from the estimated fair values reflected on the Consolidated Financial Statements. Depreciation, depletion and amortization expense is not recorded on assets once they are classified as held for sale. Assets classified as held for sale are expected to be disposed of within one year.
Oil and natural gas properties. The Partnership uses the successful efforts method of accounting for its investments in oil and natural gas properties. Under such method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil and natural gas lease acquisition costs are also capitalized.
Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and natural gas leases, are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities. If the unproved properties are determined to be productive, the related costs are transferred to proved oil and natural gas properties. If proved leasehold costs are determined to no longer be proved as a result of changes in the Partnership’s development plan, the related acreage costs are transferred to unproved oil and natural gas properties.
Capitalized costs of producing oil and natural gas properties and support infrastructure, including water-related wells, facilities and equipment, net of estimated salvage values, are depleted and depreciated by the units-of-production method. Acquisition and leasehold costs of proved properties are depleted on the basis of total proved reserves, and capitalized development costs (wells and related equipment and facilities) are depreciated on the basis of proved developed reserves.
On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depreciation, depletion, and amortization are eliminated from the property accounts, and the resulting gain or loss is recognized. On the sale or retirement of a partial unit of proved property, the costs, net of proceeds, are charged to accumulated depreciation, depletion, and amortization, unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized in the statement of income and comprehensive income. Proceeds from sales of partial interests in unproved leases are accounted for as a recovery of costs without recognizing any gain or loss. See Note O – Oil and Natural Gas Property Transactions for additional information.
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B. Summary of Significant Accounting Policies (Continued)
On exchanges of oil and natural gas assets with third parties, the Partnership reviews the transactions for certain key aspects that may have a significant impact on its accounting. Exchange transactions that only involve unproved properties are generally measured on recorded values rather than fair values. Thus, no gain or loss is recognized. Conversely, exchange transactions involving proved developed properties must be analyzed for possible business combinations and commercial substance. These aspects, along with others, dictate whether the Partnership records exchanges at recorded values or fair values and whether gains or losses should be recognized.
Oil and natural gas properties are reviewed for impairment when facts and circumstances indicate that their carrying value may not be recoverable. The Partnership reviews its oil and natural gas properties by amortization base or by individual well for those wells not constituting part of an amortization base. The Partnership assesses impairment of capitalized costs of proved oil and natural gas properties by comparing net capitalized costs to estimated undiscounted future net cash flows using management’s expectations of future oil and natural gas prices. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, which would consider estimated future discounted cash flows. Estimating future cash flows involves the use of judgments, including estimation of the proved oil and natural gas reserve quantities, timing of development and production, expected future commodity prices, capital expenditures and production costs. Unproved properties are assessed for impairment at least annually on a property-by-property basis, and any impairment is charged to expense.
The Partnership periodically reviews its proved and unproved oil and natural gas properties that are sensitive to oil and natural gas prices for impairment. Impairment expense is caused primarily due to declines in commodity prices and well performance.
Oil and natural gas reserve quantities. The determination of depreciation, depletion and amortization expense as well as impairments that are recognized on the Partnership’s crude oil and natural gas properties are highly dependent on the estimates of the proved crude oil and natural gas reserves attributable to the Partnership’s properties. The Partnership’s estimate of proved reserves is based on the quantities of crude oil and natural gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in the future years from known reservoirs under existing economic and operating conditions. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. For example, the Partnership must estimate the amount and timing of future production volumes, operating costs, severance taxes and development costs, all of which may in fact vary considerably from actual results.
In addition, as the prices of crude oil and natural gas and cost levels change from year to year, the economics of producing the Partnership’s reserves may change and therefore the estimate of proved reserves may also change. Any significant variance in these assumptions could materially affect the estimated quantity and value of the Partnership’s reserves.
Thus, such information includes revisions of certain reserve estimates attributable to the Partnership’s properties included in the prior year’s estimates. These revisions reflect additional information from subsequent activities, production history of the properties involved and any adjustments in the projected economic life of such properties resulting from changes in crude oil and natural gas prices. Any future downward revisions could adversely affect the Partnership’s financial condition, borrowing ability and future prospects and the value of the Partnership’s common units. The information regarding present value of the future net cash flows attributable to the Partnership’s proved crude oil and natural gas reserves are estimates only and should not be construed as the current market value of the estimated crude oil and natural gas reserves attributable to the Partnership’s properties.
Asset retirement obligations. The Partnership has obligations to plug and abandon oil and natural gas wells and related equipment at the end of oil and natural gas production operations. The fair value of a liability for an asset retirement obligation (“ARO”) is recorded when there is a legal obligation associated with the retirement of a tangible long-lived asset and the liability can be reasonably estimated. Over time, changes in the present value of the liability are accreted and expensed. The capitalized asset costs are depreciated over the useful lives of the corresponding asset. Recognized liability amounts are based upon future retirement cost estimates and incorporate many assumptions such as: (i) expected economic recoveries of crude oil and natural gas, (ii) time to abandonment, (iii) future inflation rates and (iv) the risk free rate of interest adjusted for the Partnership’s credit costs. Future revisions to ARO estimates will impact the present value of existing ARO liabilities and corresponding adjustments will be made to the capitalized asset retirement costs balance.
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B. Summary of Significant Accounting Policies (Continued)
Other property and equipment. Other property and equipment is comprised of land, water rights, pipelines, gathering systems and office buildings. These items are recorded at cost. The pipelines, gathering systems and office buildings are depreciated when placed in service on a straight line basis over their estimated useful lives ranging from 15-30 years. Capitalized acquisition and leasehold costs of water rights are depleted by the units-of-production method on the basis of total proved reserves.
Maintenance and repairs are charged to expense as incurred. Renewals and betterments are capitalized to the appropriate property and equipment accounts.
Impairments of long-lived assets. The Partnership reviews its long-lived assets to be held and used, for impairment whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. An impairment loss is indicated if the sum of the expected undiscounted future net cash flows is less than the carrying amount of the assets. In this circumstance, the Partnership recognizes an impairment loss for the amount by which the carrying amount of the asset exceeds the estimated fair value of the asset.
Deferred loan costs. Costs incurred in connection with the issuance of debt are deferred and recorded on the balance sheet. Costs associated with the Credit Facility are included in noncurrent assets; costs associated with the Senior Notes and the Canvasback Construction Loan (as defined below) are included as direct deductions from the carrying amounts of the debt liabilities. Deferred loan costs are stated net of amortization, which is computed using the straight-line method and approximates the effective interest method. The deferred loan costs are amortized to interest expense over the life of the debt.
Future amortization expense of deferred loan costs at December 31, 2023 was as follows:
| in thousands | |||||
| 2024 | 4,405 | ||||
| 2025 | 4,140 | ||||
| 2026 | 2,990 | ||||
| 2027 | 2,990 | ||||
| 2028 | 1,085 | ||||
| Thereafter | 234 | ||||
| Total | $ | 15,844 | |||
Equity method investment. In August 2017, the Partnership executed a Limited Liability Company Agreement in which it became a voting equity member of a newly-formed oil and natural gas service company, Silvertip Completion Services, LLC (“Silvertip”), that provides wireline and pump down services to exploration and production companies operating in the Permian Basin. Through August 31, 2020, the expiration date of the Partnership’s capital commitment, the Partnership contributed $8.7 million in cash.
Effective November 1, 2022, Silvertip sold its wholly owned subsidiary, Silvertip Completions Services Operating, LLC, to ProPetro Holding Corp. (“ProPetro”), a publicly traded oilfield services company. This acquisition represented all of Silvertip’s wireline perforating units and pumpdown fleet. As transaction consideration, Silvertip received 10.1 million shares of ProPetro common stock, $30.0 million of cash, the payoff of approximately $7.0 million of assumed debt, and certain other transaction costs, subject to customary post-closing adjustments, which implied a value of $150.0 million based upon a 15-day volume weighted average price of ProPetro’s stock price as of October 27, 2022. In connection with this transaction, the surviving entity in which the Partnership owns its equity interest changed its name to SCS Spur, LLC (“Spur”). The Partnership has since received its share of the transaction proceeds through periodic cash distributions from Spur as Spur liquidated its investment in ProPetro.
On September 15, 2023, the Partnership received a distribution from Spur of $19.9 million which represented the Partnership’s share of the proceeds from Spur’s sale of its remaining ProPetro investment. On December 28, 2023, the Partnership received a final distribution from Spur of $118 thousand. Following such distribution, Spur had no remaining assets. On December 28, 2023, Spur requested to cancel the Certificate of Formation of the Company under the Delaware Limited Liability Company Act. Effective December 28, 2023, Spur was officially dissolved.
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B. Summary of Significant Accounting Policies (Continued)
During the period of its ownership of voting equity units of Spur, the Partnership accounted for the investment utilizing the equity method of accounting. The Partnership recorded distributions received from Spur as reductions in the carrying value of its investment in Spur and classified the distributions as cash inflows from operating activities on the statement of cash flows using the cumulative earnings approach. The carrying value of the Partnership’s investment in Spur was reduced to zero as of June 30, 2023. After such date, the Partnership recorded distributions received as cash inflows from investing activities on the statement of cash flows using the cumulative earnings approach. During the year ended December 31, 2023, the Partnership received distributions from Spur in the amount of $22.9 million comprised of $1.1 million classified as cash inflows from operating activities and $21.8 million classified as cash inflows from investing activities. During the year ended December 31, 2023, the Partnership did not recognize any income from continuing operations of Spur. The $21.8 million of income received during 2023 subsequent to the Partnership’s investment being reduced to zero is included in other income (expense), net in the consolidated statements of income and comprehensive income.
Environmental. The Partnership is subject to extensive federal, state and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment (including emissions into the ambient air), the generation, storage, transportation and disposal of waste materials, the protection of wildlife and natural resources and the development of emergency response and contingency plans. Failure to comply with these laws may result in administrative, civil or criminal penalties, strict joint and several liability for natural resources damages and operational, developmental or permitting restrictions, delays or cancellations. Compliance with these laws may also require the Partnership to investigate, monitor, remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. No amounts were accrued for environmental liabilities as of December 31, 2023.
Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a noncapital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated.
Derivative Instruments and Hedging Activities. The Partnership records all derivative instruments on the consolidated balance sheets at fair value. The Partnership nets derivative assets and liabilities for counterparties where the Partnership has a legal right of offset. Changes in the derivatives’ fair value are recognized currently in gain on derivatives not designated as hedges in the consolidated statements of income and comprehensive income.
Revenue Recognition. The Partnership recognizes revenues from the sales of oil and natural gas to its customers and aggregates them on the Partnership’s consolidated statement of income and comprehensive income. Disaggregated revenue from contracts with customers by product type is as follows:
| Year Ended December 31, 2023 | |||||
| (in thousands) | |||||
| Oil sales | $ | 2,069,579 | |||
| Natural gas sales | 42,525 | ||||
| Natural gas liquids sales | 269,843 | ||||
| Total oil and natural gas sales | $ | 2,381,947 | |||
CrownQuest markets the Partnership’s oil and natural gas and enters into contracts with customers to sell the Partnership’s oil and natural gas production. Revenue from these contracts is recognized by the Partnership in accordance with the five-step revenue recognition model prescribed in Accounting Standards Codification 606, “Revenue from Contracts with Customers” (“ASC 606”). Specifically, revenue is recognized when the Partnership’s performance obligations under these contracts are satisfied, which generally occur with the transfer of control of the oil and natural gas to the purchaser. Control is generally considered transferred when the following criteria are met: (i) transfer of physical custody; (ii) transfer of title; (iii) transfer of risk of loss; and (iv) relinquishment of any repurchase rights or other similar rights. Given the nature of the products sold, revenue is recognized at a point in time based on the amount of consideration the Partnership expects to receive in accordance with the price specified in the contract.
13
B. Summary of Significant Accounting Policies (Continued)
Consideration under the oil and natural gas marketing contracts is typically received from the purchaser one to two months after production. At December 31, 2023 and 2022, the Partnership had receivables related to contracts with customers of approximately $196.5 million and $225.6 million, respectively.
Oil Contracts. The majority of CrownQuest’s oil marketing contracts covering the Partnership’s oil production, transfer physical custody and title at or near the wellhead, which is generally when control of the oil has been transferred to the purchaser. The majority of the oil produced is sold under contracts using market-based pricing which is then adjusted for differentials based upon delivery location and oil quality. To the extent differentials are incurred after the transfer of control of the oil, the differentials are included in oil and natural gas sales on the consolidated statements of income and comprehensive income as they represent part of the transaction price of the contract. If the differentials, or other related costs, are incurred prior to the transfer of control of the oil, those costs are included in lease operating expenses on the Partnership’s consolidated statements of income and comprehensive income and are accounted for as costs incurred directly and not netted from the transaction price.
Natural Gas Contracts. The majority of the Partnership’s natural gas is sold at the lease location, which is generally when control of the natural gas has been transferred to the purchaser. The natural gas is sold under (i) percentage of proceeds processing contracts, (ii) fee-based contracts or (iii) a hybrid of percentage of proceeds and fee-based contracts. Under the majority of CrownQuest’s gas marketing contracts covering the Partnership’s gas production, the purchaser gathers the natural gas in the field where it is produced and transports it via pipeline to natural gas processing plants where natural gas liquid products are extracted. The natural gas liquid products and remaining residue gas are then sold by the purchaser. Under the percentage of proceeds and hybrid percentage of proceeds and fee-based contracts, the Partnership receives a percentage of the value for the extracted liquids and the residue gas. Under the fee-based contracts, the Partnership receives natural gas liquids and residue gas value, less the fee component. To the extent control of the natural gas transfers upstream of the transportation and processing activities, revenue is recognized at the net amount received from the purchaser. To the extent that control transfers downstream of those activities, revenue is recognized on a gross basis, and the related costs are classified as lease operating expenses on the Partnership’s consolidated statements of income and comprehensive income.
The Partnership does not disclose the value of unsatisfied performance obligations under its contracts with customers as it applies the practical exemption in accordance with ASC 606. The exemption, as described in ASC 606-10-50-14A, applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required.
Prepaid costs and other. The Partnership’s prepaid costs and other current assets consist of derivative settlement receivables, prepaid insurance and prepaid taxes. Prepaid insurance is amortized on a monthly basis based on the length of the commitment period.
Income taxes. The Partnership is structured as a limited liability partnership, which is a pass-through entity for U.S. income tax purposes. The Partnership is also classified as a passive entity for Texas Margin tax. Two of the Partnership’s subsidiaries, CrownRock Finance and CR Royalties Management, are taxed as corporations. The Partnership did not have income tax expense for the year ended December 31, 2023.
Items of income or loss are allocated to the members in accordance with their respective equity interest and reported on their individual federal and state income tax returns. Net income or loss for financial statement purposes may differ significantly from taxable income or loss reportable to partners as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income or loss allocation requirements under the partnership agreement. In addition, individual partners have different investment bases depending upon the timing and price of acquisition of their partnership units, and each partner’s tax accounting, which is partially dependent upon the partner’s tax position, differs from the accounting followed in the Consolidated Financial Statements. As a result, the aggregate difference in the basis of net assets for financial and tax reporting purposes cannot be readily determined as the Partnership does not have access to information about each partner’s tax attributes in the Partnership.
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B. Summary of Significant Accounting Policies (Continued)
Accounting principles generally accepted in the United States of America require the Partnership to evaluate tax positions taken and recognize a tax liability if it is more-likely-than-not that uncertain tax positions taken would not be sustained upon examination by taxing authorities. The Partnership has analyzed tax positions taken and has concluded that, as of December 31, 2023, there are no uncertain tax positions taken or expected to be taken that would require recognition of a liability or disclosure in the financial statements.
With few exceptions, the Partnership is no longer subject to U.S. federal income tax examinations by tax authorities for years before 2020.
Use of estimates. Preparing financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The financial statements are based on a number of significant estimates including oil and natural gas reserve quantities and values, which are the basis for oil and natural gas properties acquired or exchanged, calculation of depreciation, depletion and amortization, AROs, and impairment of oil and natural gas properties.
Fair value. Fair value is defined as the price that would be received upon the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are classified and disclosed in one of the following categories:
Level 1. Measured based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. The Partnership considers active markets to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Items included in this category are short term money market investments.
Level 2. Measured based on quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that the Partnership values using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data, or supported by observable levels at which transactions are executed in the marketplace. Instruments in this category are non-exchange traded derivatives such as over-the-counter commodity price swaps, collars and options. The Partnership’s valuation models are primarily industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures.
Level 3. Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e. supported by little or no market activity). Items included in this category are AROs, asset impairments and asset acquisitions and exchanges.
Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Partnership’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.
Unit-based compensation. From time to time, Holdings exchanges its equity instruments for services provided by the officers and employees of CrownQuest that are based on the fair value of Holdings’ equity instruments or that may be settled by the issuance of those equity instruments in exchange for the services. The cost of the services received in exchange for equity instruments is measured based on the grant-date fair value of those instruments. The compensation costs associated with the services provided is treated as a deemed capital contribution from Holdings to the Partnership. That cost is recognized by the Partnership as compensation expense over the requisite service period (generally the vesting period).
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B. Summary of Significant Accounting Policies (Continued)
Accounting pronouncements recently adopted.
Accounting pronouncements recently adopted.
Financial Instruments – Credit Losses (Topic 326): In June 2016, the FASB issued Accounting Standards Update (“ASU”) No. 2016-13 “Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financials Instruments” which requires the measurement of all expected credit losses for financial assets held at the reporting date based on historical experience, current conditions and reasonable and supportable forecasts. Organizations will now use forward-looking information to better inform their credit losses and estimates. In November 2019, the FASB issued ASU No. 2019-10, “Financial Instruments – Credit Losses (Topic 326), Derivatives and Hedging (Topic 815), and Leases (Topic 842) – Effective Dates”, which deferred the original effective date of ASU No. 2016-13 for the Partnership to annual periods beginning after December 15, 2022, including interim periods within those fiscal years.
On January 1, 2023, the Partnership adopted ASU No. 2016-13 prospectively. This ASU replaced the incurred loss impairment model with an expected credit loss impairment model for financial instruments, including trade receivables. The amendment requires the Partnership to consider forward-looking information to estimate expected credit losses, resulting in earlier recognition of losses for receivables that are current or not yet due, which were not considered under the previous accounting guidance. As a result of adopting ASU 2016-13, the Partnership, in consultation with CrownQuest, establishes allowances for credit losses equal to the estimable portions of accounts receivable for which failure to collect is expected to occur. The Partnership and CrownQuest estimate uncollectible amounts based on the length of time that the accounts receivables have been outstanding, historical collection experience and current and future economic and market conditions. Allowances for credit losses are recorded as reductions to the carrying values of the receivables in the accounting periods during which failure to collect an estimable portion is determined to be probable.
Reference Rate Reform (Topic 840): In March 2020, the FASB issued ASU No. 2020-04, “Reference Rate Reform (Topic 840): Facilitation of the Effects of Reference Rate Reform on Financial Reporting” (“ASU 2020-04”), which provides companies with optional guidance to ease the potential accounting burden associated with transitioning away from reference rates (e.g., London Interbank Offered Rate (“LIBOR”)) that are expected to be discontinued. ASU 2020-04 allows, among other things, certain contract modifications, such as those within the scope of Topic 470 on debt, to be accounted for as a continuation of the existing contract. This ASU was effective upon the issuance and its optional relief can be applied through December 31, 2022. On January 1, 2023, the Partnership adopted ASU No. 2020-04. This had no effect on the Partnership’s consolidated financial statements.
In January 2021, the FASB issued ASU No. 2021-01, “Reference Rate Reform (Topic 848) Scope”, which clarifies that certain optional expedients and exceptions in Topic 848 for contract modifications and hedge accounting apply to derivative instruments that use an interest rate for margining, discounting, or contract price alignment that is modified as a result of reference rate reform. ASU No. 2021-01 shall be effective for all entities as of March 12, 2020 through December 31, 2022. On January 1, 2023, the Partnership adopted ASU No. 2021-01. This had no effect on the Partnership’s consolidated financial statements.
In December 2022, the FASB issued ASU No. 2022-06, “Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848,” which extends the period of time preparers can utilize the reference rate reform relief guidance. The amendments in ASU 2022-06 are effective for all entities upon issuance. The ASU defers the sunset date of Topic 848 from December 31, 2022 to December 31, 2024, after which entities will no longer be permitted to apply the relief of Topic 848. On January 1, 2023, the Partnership adopted ASU No. 2022-06. This had no effect on the Partnership’s consolidated financial statements.
Subsequent events. The Partnership performed an evaluation of subsequent events through March 8, 2024, which is the date the Consolidated Financial Statements were available to be issued.
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C.Oil and Natural Gas Properties
The following table sets forth information concerning the Partnership’s oil and natural gas properties as of December 31, 2023:
December 31, 2023 | |||||
(in thousands) | |||||
| Proved oil and natural gas properties | $ | 6,736,683 | |||
| Unproved oil and natural gas properties | 351,244 | ||||
Less accumulated depreciation, depletion, amortization and impairment | (3,208,790) | ||||
| Net oil and natural gas properties | $ | 3,879,137 | |||
During the year ended December 31, 2023, the Partnership recognized exploration costs of approximately $5.8 million primarily comprised of $5.4 million of dry hole expense of oil and natural gas wells on the Spade Ranch property located in the Eastern Shelf of the Permian Basin of Texas and $0.4 million of drilling preparatory costs incurred on properties that were not drilled.
During the year ended December 31, 2023, the Partnership did not recognize any non-cash charges against earnings nor a corresponding allowance for expiring acreage.
See Note J – Fair Value for discussion of proved property impairments recorded during the year ended December 31, 2023.
The Partnership capitalizes horizontal and vertical well costs as exploratory until a determination is made that the well has either found proved reserves or that it is impaired. The capitalized exploratory well costs are carried in unproved oil and natural gas properties. If the exploratory well is determined to be impaired, the well costs are charged to exploration and abandonments in the consolidated statements of income and comprehensive income. The capitalized exploratory horizontal well costs included in unproved oil and natural gas properties pending the determination of proved reserves at December 31, 2023 were $4.7 million. Of these costs, $3.8 million are from wells drilled during the year ended December 31, 2023 and such costs were not subject to depletion in 2023. During the year ended December 31, 2023, the Partnership reclassified $1.7 million of previously capitalized exploratory costs to wells, equipment and facilities based on the determination of proved reserves.
D.Other Property and Equipment
The following table sets forth the Partnership’s other property and equipment as of December 31, 2023:
| December 31, 2023 | |||||
| (in thousands) | |||||
| Land | $ | 24,907 | |||
| Water rights | 11,872 | ||||
| Construction in progress - gathering systems | 7,079 | ||||
| Office buildings | 26,050 | ||||
| Equipment | 91 | ||||
| Gathering systems | 112,400 | ||||
| Compressor stations | 18,930 | ||||
| Abajo pipeline and gathering facilities | 11,714 | ||||
| Less accumulated depletion, depreciation and impairment | (56,443) | ||||
| Net other property and equipment | $ | 156,600 | |||
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D.Other Property and Equipment (Continued)
Land and water rights. The Partnership owns surface acreage located in various portions of the Partnership’s core northern Midland Basin leasehold acreage. The Partnership’s purchase of surface acreage is part of its ongoing strategy to cost-effectively support its horizontal drilling program in the Midland Basin. The Partnership also owns the water rights attached to certain portions of the surface acreage. The ownership of these water rights allows the Partnership to drill water wells and construct water storage facilities on the surface that will support the drilling and completion of its future horizontal oil and natural gas wells on or in close proximity to the surface acreage. As a result of reduced water production and sales during 2022, which was partially due to the increased amount of produced water recycling in the oil and gas industry, during the year ended December 31, 2022, the Partnership recognized a non-cash charge against earnings of approximately $7.3 million to fully impair its capitalized water rights. In periods prior to this impairment the Partnership depleted its capitalized water rights using the units-of-production method on the basis of estimated water reserves.
Office buildings. Canvasback owns an office building in Midland, Texas which is the Partnership’s headquarters. Canvasback also owns a field operations office and an extension of the field operations office in Martin County, Texas.
Gathering systems. The Partnership owns a low-pressure gas gathering system in eastern Martin, western Howard and northern Glasscock Counties, Texas. It is designed to gather casinghead gas from CrownQuest operated and non-operated oil and natural gas wells in close proximity. It connects to a large midstream company’s gathering system at four compressor sites.
The Partnership owns a gas, oil, and produced water gathering system in Midland County, Texas. The gas gathering system is designed to gather casinghead gas from CrownQuest operated wells near its proximity, while the oil and produced water gathering systems, which parallel the gas system, are designed to gather produced liquids. The three systems connect CrownQuest operated leases to a large midstream company’s gas pipeline, oil purchasers, and salt water disposal systems in the area.
E.Asset Retirement Obligations
The Partnership records a liability for the present value of all legal obligations associated with the retirement of tangible long-lived assets and capitalizes an equal amount as part of the cost of their related oil and natural gas properties. AROs are initially recorded at fair value and assessed for revisions periodically thereafter. The significant unobservable inputs to this fair value measurement include estimates of plugging, abandonment and remediation costs and well life. The inputs are calculated based on historical data as well as current estimated costs.
The following table summarizes the changes in the Partnership’s ARO for the year ended December 31, 2023:
Year Ended December 31, 2023 | |||||
| (in thousands) | |||||
| Balance, beginning of period | $ | 43,077 | |||
| Liabilities incurred during the period | 4,173 | ||||
| Liabilities settled during the period | (485) | ||||
| Liabilities associated with properties exchanged or sold | (1,431) | ||||
| Accretion expense | 1,954 | ||||
| Balance, end of period | 47,288 | ||||
| Less current portion | (691) | ||||
| Non-current portion | $ | 46,597 | |||
AROs for natural gas pipeline facilities generally become firm at the time the facilities are permanently shut down and dismantled. These obligations may include the costs of asset disposal and additional soil remediation. However, these sites have indeterminate lives based on plans for continued operations and as such, the fair value of the conditional legal obligations cannot be measured since it is impossible to estimate the future settlement dates of such obligations.
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F.Credit and Counterparty Risk
Cash and cash equivalents are maintained at financial institutions and, at times, balances may exceed federally insured limits. Amounts on deposit at financial institutions at December 31, 2023 were approximately $3.2 million, of which approximately $2.1 million was in excess of federally insured limits. In addition to funds maintained at financial institutions, at December 31, 2023, the Partnership had approximately $141.6 million invested in an institutional fund that invests at least 99.5% of its total assets in cash, U.S. Treasury Bills, notes or other obligations issued or guaranteed as to principal and interest by the U.S. Treasury, and repurchase agreements secured by such obligations or cash. The Partnership classifies investment securities with original maturities of three months or less as cash equivalents.
At December 31, 2023, the Partnership had no commodity derivatives. The Partnership routinely monitors the creditworthiness of its counterparties but does not require collateral or other security to support derivative instruments. However, agreements with the counterparties contain netting provisions such that if a default occurs, the non-defaulting party can offset the amount payable to the defaulting party under derivative contracts with the amount due from the defaulting party under derivative contracts. As a result of the netting provisions, the Partnership’s maximum amount of loss due to credit risk is limited to the net amounts due to and from the counterparty under the derivative contracts.
G.Related Party Transactions
Related party operator of oil and natural gas properties. Most of the Partnership’s properties are operated by CrownQuest. As of December 31, 2023, aggregate related party accounts payable and accrued liabilities owed to CrownQuest in the normal course of the Partnership’s oil and natural gas property operations were $90.0 million, related specifically to accrued drilling costs on wells being drilled and completed as of period end, accrued ad valorem taxes, accrued infrastructure costs on facilities being constructed and accrued management fees as of period end. Further, with respect to the properties operated by CrownQuest, at December 31, 2023, related party accounts receivable outstanding in the normal course of business related primarily to accrued oil and natural gas sales, fresh water sales and water disposal fees were $250.7 million.
As a result of its ownership of surface acreage, water rights and infrastructure, the Partnership recognizes amounts due from CrownQuest for surface damages, fresh water purchases and water disposal. During the year ended December 31, 2023, the Partnership recognized receivables from CrownQuest of $70.1 million, for these transactions. The unpaid portion of these amounts due are included in the related party accounts receivable listed above.
Management fees paid to related party. Pursuant to an administrative support agreement, the Partnership pays CrownQuest a monthly management fee based upon an annual budget approved by the Partnership. The Partnership is required to reimburse CrownQuest for substantially all costs, which include employee expense, rent expense, license fees, insurance cost, general office expenses, depreciation expense related to capitalized equipment, third party charges incurred for the benefit of the Partnership, and any and all expenses incurred by CrownQuest in providing support to the Partnership net of any amounts received under any operating agreements. During the year ended December 31, 2023, the Partnership recorded management fees of $19.7 million in general and administrative expenses.
Royalty and other payments to affiliates. CrownQuest, as the operator of the Partnership’s properties, periodically makes various types of payments to companies affiliated with CrownQuest and the Partnership in connection with its role as operator of properties in which the Partnership owns a working interest. During the year ended December 31, 2023 payments of $169.3 million were made by CrownQuest to affiliates for royalty interests, lease bonuses and extensions, surface acquisitions, surface damages, water purchases and water disposal with respect to such properties. Payments during the years ended December 31, 2023 include amounts paid to a CrownQuest-affiliated royalty partnership formed in July 2018 (the “2018 Royalty Partnership”) and a CrownQuest-affiliated royalty partnership formed in March 2016 (the “2016 Royalty Partnership”). These royalty partnerships acquired royalty interests from third parties on properties operated by CrownQuest and in which the Partnership owns working interests. Payments to the 2018 Royalty Partnership during the year ended December 31, 2023 were $37.9 million, primarily for royalty interests on properties operated by CrownQuest in which the Partnership owns a working interest. Payments to the 2016 Royalty Partnership during the years ended December 31, 2023 were $125.2 million, primarily for royalty interests on properties operated by CrownQuest.
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G.Related Party Transactions (Continued)
Oil and natural gas property lease from an officer of CrownQuest. A family partnership controlled by Mr. Robert W. Floyd, President of CrownQuest and Director of Holdings GP, and his wife has royalty interests in certain properties that the Partnership is developing in the Permian Basin. During the year ended December 31, 2023, CrownQuest paid $10 thousand for royalty interests on properties operated by CrownQuest.
In a series of transactions beginning in August 2013, the Partnership entered into oil and natural gas property lease agreements with several relatives of Mr. Floyd and a family limited liability company in which Mr. Floyd owns a 33 1/3% interest. The leases are for unproved acreage in the Midland Basin in West Texas. The Partnership is currently developing this acreage. During year ended December 31, 2023, CrownQuest paid $70.2 million, primarily for royalty interests on properties operated by CrownQuest, to Mr. Floyd’s relatives and the family limited liability company mentioned above.
Related party owner and operator of aircraft used by CrownQuest. Mr. Floyd and EnerQuest Oil & Gas Ltd., an entity affiliated with the Partnership, own an entity named EnerQuest Aviation Partners, LLC which owns 60% of an aircraft with the other 40% belonging to a third party individual. The aircraft is managed by Crown Eye Partners, LLC (“Crown Eye”) which is owned 60% by Aviation Partners and 40% by the same third-party individual. This aircraft is available for use by CrownQuest employees when conducting business on behalf of the Partnership. The Partnership pays CrownQuest’s usage of the aircraft under the terms of the administrative support agreement. For the year ended December 31, 2023, CrownQuest paid Crown Eye $83 thousand for usage of the aircraft for 20.5 hours at an average cost of $4,030 per hour.
Equity investment provider of oilfield services to CrownQuest. From its formation in 2017 until its sale of all its equipment effective November 1, 2022, as described in “Equity method investment” in Note B – Summary of Significant Accounting Policies, Spur provided wireline and pump down services to companies operating in the Permian Basin, including CrownQuest. Prior to the sale transaction, CrownQuest procured these services for wells in which the Partnership had working interests. The Partnership eliminated all intra-entity income and losses related to these services. Subsequent to the sale transaction, CrownQuest is procuring these services from third-party providers.
H.Major Customers
The Partnership operates exclusively within the United States in onshore exploration for and production of oil and natural gas. All of the Partnership’s assets are employed in, and all of its revenues and operating income are derived from this industry. Most revenues from the sale of oil and natural gas production are collected and disbursed on behalf of the partnership by CrownQuest, a related party.
The following customers accounted for 10% or more of the Partnership’s revenues for the year ended December 31, 2023:
| 2023 | |||||
| Customer A | 76% | ||||
Although there are numerous other parties available to purchase the Partnership’s production, and the Partnership believes the loss of these purchasers would not significantly affect its ability to sell crude oil and natural gas, CrownQuest’s marketing of oil and natural gas can be affected by factors beyond CrownQuest’s control, the effects of which cannot be accurately predicted.
I.Derivative Financial Instruments
Through 2023, the Partnership entered into derivative contracts with counterparties to manage its exposure to commodity price fluctuations associated with a portion of the Partnership’s oil and natural gas production.
The Partnership does not designate its derivative instruments to qualify for hedge accounting. Accordingly, the Partnership records all derivative instruments on the consolidated balance sheets at fair value. The Partnership nets derivative assets and liabilities for counterparties where the Partnership has a legal right of offset. Further, the Partnership reflects changes in the fair value of its derivative instruments currently in its consolidated statements of income and comprehensive income as they occur.
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I.Derivative Financial Instruments (Continued)
Termination of commodity derivative contracts during the year ended December 31, 2023. See Note P – Agreement to Sell Partnership Interest to Occidental Petroleum Corporation for a discussion of restrictive operating covenants of the PIPA which include the restriction of entering into any additional commodity hedging transactions from January 1, 2024 through the closing date of the Partnership Sale Transaction. Further as required by the PIPA, the Partnership terminated all its commodity derivative contracts in December 2023. This resulted in a net cash payment to counterparties of $251 thousand, which is included in gain (loss) on derivatives not designated as hedges in the consolidated statements of income and comprehensive income.
New commodity derivative contracts during the year ended December 31, 2023. During the year ended December 31, 2023, the Partnership entered into additional commodity derivative contracts to hedge a portion of its estimated future production. The following table summarizes information about these commodity derivative contracts added during the year ended December 31, 2023. When aggregating multiple contracts the weighted average contract price is disclosed. The Partnership had no commodity derivatives as of December 31, 2023.
| Aggregate | Price | Contract | |||||||||
| Volume | Per MMBtu | Period | |||||||||
| Natural Gas (volumes in MMBtus): | |||||||||||
| Price Swaps (a) | 1,820,000 | $ | 3.85 | 1/1/24 - 3/31/24 | |||||||
(a) The index prices for the natural gas price swaps are based on the NYMEX last trading day of the first nearby futures contract. | |||||||||||
The following table summarizes the activity in the Partnership’s derivative instruments, for each of the year indicated:
December 31, 2023 | |||||
| (in thousands) | |||||
| Net liability, beginning of period | $ | (36,196) | |||
| Cash settlement payments | 36,010 | ||||
| Changes in fair value of derivatives | 186 | ||||
| Net liability end of period | $ | — | |||
The Partnership’s commodity derivatives are presented on a net basis in “derivative instruments” on the Consolidated Balance Sheets. The following table summarizes the gross fair values of the Partnership’s derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on the Partnership’s Consolidated Balance Sheets for the period indicated. The Partnership had no commodity derivatives as of December 31, 2023.
J.Fair Value
Assets and Liabilities Measured at Fair Value on a Recurring Basis. The following table sets forth by level within the fair value hierarchy the Partnership’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2023.
Fair value measurements using | ||||||||||||||
| Quoted prices in active markets | Other observable inputs | Unobservable inputs | ||||||||||||
| Description | (Level 1) | (Level 2) | (Level 3) | Fair Value | ||||||||||
| (in thousands) | ||||||||||||||
| Money market funds | $ | 141,605 | $ | — | $ | — | $ | 141,605 | ||||||
| Total as of December 31, 2023 | $ | 141,605 | $ | — | $ | — | $ | 141,605 | ||||||
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J.Fair Value (Continued)
The Partnership estimates, with the assistance of third-party pricing experts, the fair values of the swaps based on published forward commodity price curves for the underlying commodities as of the date of the estimate for those commodities for which published forward pricing is readily available. For those commodity derivatives for which forward commodity price curves are not readily available, the Partnership estimates, with the assistance of third-party pricing experts, the forward curves as of the date of the estimate. Using a discounted cash flow model, the determination of the fair values above incorporates various factors including the impact of the Partnership’s non-performance risk, the credit standing of the counterparties involved in the Partnership’s derivative contracts, NYMEX future prices and interest rates.
The following table represents the carrying amounts and fair values of the Partnership’s financial instruments at December 31, 2023.
December 31, 2023 | ||||||||
| Carrying | Fair | |||||||
| Value | Value | |||||||
(in thousands) | ||||||||
Assets: | ||||||||
| Money market funds | $ | 141,605 | $ | 141,605 | ||||
Credit Facility. The fair value of the revolving Credit Facility borrowings approximate the carrying amounts based upon interest rates currently available to the Partnership for borrowings with similar terms (Level 2).
Senior Notes. The fair value of the Partnership’s 2025 Senior Notes was $863.8 million at December 31, 2023. The fair value of the Partnership’s 2029 Senior Notes was $362.9 million at December 31, 2023. Such fair value was determined using Level 2 inputs including quoted period end market prices.
Other financial assets and liabilities. The Partnership has other financial instruments consisting primarily of receivables, payables and other current assets and liabilities. The carrying amounts approximate fair value due to the short maturity of these instruments.
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis. Non-recurring fair value measurements include certain nonfinancial assets and liabilities as may be acquired in a business combination or property exchange and thereby measured at fair value; impaired oil and natural gas property assessments; and the initial recognition of AROs for which fair value is used. These estimates are derived from historical costs as well as management’s expectation of future cost and commodity price environments. As there is no corroborating market activity to support the assumptions used, the Partnership has designated these estimates as Level 3.
Impairments of long-lived assets. The Partnership reviews its long-lived assets to be held and used, including proved oil and natural gas properties accounted for under the successful efforts method of accounting, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable, for instance when there are declines in commodity prices or well performance. The Partnership performed such a review at December 31, 2023 and determined there was no impairment of its proved and unproved oil and natural gas properties.
K.Commitments and Contingencies
As part of the administrative support agreement between the Partnership and CrownQuest, the Partnership reimburses CrownQuest for rent expense. At December 31, 2023, CrownQuest was party to two operating leases for office space:
(a)Lease agreement dated June 19, 2014 with Canvasback as lessor on the headquarters office in Midland County, Texas. The lease agreement was effective December 1, 2015 and terminates on June 30, 2026.
(b)Lease agreement dated August 28, 2023 with Canvasback as lessor on the field operations office and barn in Martin County, Texas and the extension of the field operations office in Martin County, Texas. The lease agreement was effective September 1, 2023 and terminates on August 31, 2024.
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K.Commitments and Contingencies (Continued)
For the year ended December 31, 2023, the Partnership reimbursed CrownQuest for rent expense for office space of $2.0 million, included in the monthly management fee. The rent expense relates to the Canvasback leases which are eliminated in consolidation.
CrownQuest has entered into contracts to secure the availability of drilling rigs and are subject to payments in accordance with the contracts based on the utilization of the drilling rigs.
From time to time, the Partnership is party to ordinary routine litigation incidental to the business. The Partnership believes that the results of such proceedings will not have a material adverse effect on its Consolidated Financial Statements.
L.Partners’ Capital
CrownRock, L.P. is a privately held limited partnership formed in the State of Delaware on February 14, 2007. Holdings GP has the exclusive right to manage the business of the Partnership and has all powers and rights necessary or advisable to effectuate and carry out the purposes and business of the Partnership.
Effective January 1, 2018, the Partnership merged with a subsidiary of Holdings. As a result of this merger, the Partnership and CrownRock GP became wholly-owned subsidiaries of Holdings. The Partnership admitted Holdings as its sole limited partner by issuing 100 new limited partnership units and cancelling all its other limited partner interests comprised of Class A, B, C, D and E limited partnership units. Holdings issued equivalent units of equivalent classes to the former limited partners of the Partnership. The only outstanding units of the Partnership at December 31, 2023 are the 100 limited partnership units held by Holdings. Additionally, effective January 1, 2018, the Partnership executed its Second Amended and Restated Limited Partnership Agreement to provide for sole control and management of the Partnership by CrownRock GP and the simplification of the governance of the Partnership.
Distributions are made solely to Holdings as the Partnership’s sole limited partner and in turn, Holdings has made distributions to its limited partners.
The Partnership’s Credit Facility, the indentures governing its 2025 Senior Notes and 2029 Senior Notes and the PIPA have restrictive covenants limiting dividends and distributions (See Note N – Long-term Debt and Note P – Agreement to Sell Partnership Interests to Occidental Petroleum Corporation). The Partnership makes distributions to Holdings within the limits of these agreements.
During the year ended December 31, 2023, the Partnership distributed $597.4 million, to provide Holdings with funds to pay its holders of Class A, B, C, D and E limited partnership units comprised of $311.3 million of estimated tax and $286.1 million of discretionary.
Based upon the provisions of the Partnership’s more restrictive indenture which governs the 2025 Senior Notes, as of December 31, 2023, the Partnership is allowed to make additional discretionary distributions to Holdings of approximately $1.03 billion (See Note N – Long-term Debt). However, discretionary distributions are restricted by the PIPA from January 1, 2024 to the closing date of the Partnership Sale Transaction (See Note P – Agreement to Sell Partnership Interest to Occidental Petroleum Corporation).
M.Incentive Plans
Defined contribution plan. CrownQuest sponsors a 401(k) defined contribution plan for the benefit of substantially all employees. Currently, CrownQuest matches 100% of employee contributions, not to exceed 10% of the employee’s annual base salary. The Partnership’s contributions to the plan, through its reimbursement to CrownQuest pursuant to the terms of an administrative support agreement, were approximately $3.5 million for the year ended December 31, 2023.
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N. Long-term Debt
The Partnership’s debt consists of the following at December 31, 2023:
| December 31, 2023 | |||||
| (in thousands) | |||||
| 5.625% unsecured senior notes due 2025 | $ | 868,132 | |||
| 5.000% unsecured senior notes due 2029 | 376,084 | ||||
| Unamortized original issue discount | (642) | ||||
| Unamortized deferred loan costs - senior notes | (6,291) | ||||
| Construction loan - Canvasback office building | 751 | ||||
| Unamortized deferred loan costs - construction loan | (34) | ||||
| Total debt | 1,238,000 | ||||
| Less current portion | (751) | ||||
| Long-term debt | $ | 1,237,249 | |||
Credit facility. The Partnership’s Credit Facility has a maturity date of March 7, 2028. In conjunction with its regular semi-annual borrowing base redetermination done in conjunction with its amendment and syndication, effective November 9, 2023, the Partnership’s lenders reaffirmed the borrowing base at $2.0 billion. The Partnership also elected to maintain its elected commitment amount of $1.0 billion. Commitments from the Partnership’s bank group total $3.5 billion. As of December 31, 2023, the Partnership had no advances outstanding against the Credit Facility.
Between scheduled semi-annual borrowing base redeterminations in May and November, the Partnership and lenders, if requested by 66 2/3% of the lenders, may each request one special redetermination.
Advances on the Credit Facility bear interest, at the Partnership’s option, based on (i) Secured Overnight Financing Rate (“SOFR”) or (ii) the prime rate as quoted by The Wall Street Journal (“Prime Rate”) (8.50% at December 31, 2023). The Credit Facility’s interest rates on SOFR rate advances and Prime Rate advances vary, with interest margins ranging from 175 to 275 basis points and 75 to 175 basis points, respectively, per annum depending on the debt balance outstanding. Additionally, SOFR rate advances include a 10 basis points credit spread adjustment. The Partnership pays commitment fees on the unused portion of the available commitment of 50 basis points per annum. Total interest expense on the Credit Facility, including commitment fees paid on the unused portion, was $6.1 million for the year ended December 31, 2023. The weighted average cash interest rate on the Credit Facility for the year ended December 31, 2023 7.39%.
The Partnership’s obligations under the Credit Facility are secured by a first lien on substantially all of its oil and natural gas properties. In addition, all of the Partnership’s subsidiaries (excluding Abajo until such time as the Partnership owns 100% of the equity of Abajo) are guarantors, and the equity interests in such subsidiaries have been pledged to secure borrowings under the Credit Facility.
If the outstanding principal balance under the Credit Facility exceeds the aggregate available commitment amount at any time, the Partnership must make a lump sum payment curing the deficiency within three business days. If the outstanding principal balance of the loans under the Credit Facility exceeds the borrowing base at any time, the Partnership has the option to take any of the following actions, either individually or in combination: (1) make a lump sum payment curing the deficiency within 30 days; (2) pledge additional collateral sufficient in the lenders’ opinion to increase the borrowing base and cure the deficiency; or (3) begin making equal monthly principal payments that will cure the deficiency within the ensuing six-month period.
The Credit Facility contains various restrictive covenants and compliance requirements, which include:
•maintenance of certain financial ratios, including:
(i) maintenance of a quarterly ratio of current assets to current liabilities to be not less than 1.0 to 1.0, excluding noncash assets and liabilities related to financial derivatives and AROs and including all letter of credit obligations as liabilities but excluding current maturities of indebtedness, and including any unused availability under the Credit Facility as a current asset, and
24
N. Long-term Debt (Continued)
(ii) maintenance of a quarterly ratio of total funded indebtedness, net of unrestricted cash up to $125 million, to 12-month consolidated earnings before interest expense, income taxes, depletion, depreciation, and amortization, exploration expense and noncash income and expenses to be no greater than 3.5 to 1.0.
•delivery to the lender and maintenance of satisfactory title opinions covering not less than 80% and 85% of the present value of proved oil and natural gas reserves and proved developed producing oil and natural gas reserves, respectively;
•limits on the incurrence of additional indebtedness and certain types of liens;
•restrictions as to investments, mergers, acquisitions and dispositions of assets;
•restrictions on hedging contracts and transactions with affiliates; and
•limits on dividends and distributions. The agreement allows permitted tax distributions. It also allows periodic cash distributions if the unused availability on the Credit Facility, plus unrestricted cash, is greater than or equal to 20% of the elected commitment amount, and the Partnership’s funded indebtedness to 12-month consolidated earnings before interest expense, income taxes, depletion, depreciation and amortization, exploration expense and non-cash income and expenses is no more than 3.00 to 1.00 calculated on a pro forma basis after giving effect to such cash payment.
At December 31, 2023, the Partnership was in compliance with all of the covenants under the Credit Facility.
5.625% Senior Notes due 2025. On October 11, 2017, the Partnership and CrownRock Finance issued $1.0 billion aggregate principal amount of the 2025 Senior Notes at par. On May 22, 2018, the Partnership and CrownRock Finance issued an additional $185 million aggregate principal amount of 2025 Senior Notes at 98.26% of par. These additional notes were fungible with the original notes and are governed by the same indenture and thus contain the same terms and conditions.
The 2025 Senior Notes mature on October 15, 2025, and interest is paid in arrears semi-annually on April 15 and October 15. The 2025 Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by Roddy, Canvasback, CR Management and CR Royalties. The notes may be redeemed on or after October 15, 2023 at the redemption price of 100.00%, expressed as a percentage of principal amount plus accrued and unpaid interest if any.
The 2025 Senior Notes are general, unsecured senior obligations and are subordinated to all existing and future secured indebtedness, including the Credit Facility. The indenture to the 2025 Senior Notes dated as of October 11, 2017, as supplemented (“2025 Senior Note Indenture”) contains various restrictive covenants which include:
•limits on the incurrence of additional indebtedness and certain types of liens;
•restrictions as to mergers and disposition of assets;
•limits on transactions with affiliates; and
•limits on dividends and distributions. The 2025 Senior Note Indenture allows permitted tax distributions. The 2025 Senior Notes Indenture also allows periodic cash distributions up to $150 million plus 50% of consolidated net income as adjusted for certain non-cash items from July 1, 2017 to the end of the Partnership’s most recently ended fiscal quarter. Based on this provision, as of December 31, 2023, the Partnership is allowed to make discretionary distributions of approximately $1.03 billion. However, discretionary distributions are restricted by the PIPA from January 1, 2024 to the closing date of the Partnership Sale Transaction (See Note P – Agreement to Sell Partnership Interest to Occidental Petroleum Corporation).
At December 31, 2023, the Partnership was in compliance with all of the covenants under the 2025 Senior Note Indenture.
Open Market Repurchases. For the year ended December 31, 2023, the Partnership repurchased $162.7 million of the 2025 Senior Notes outstanding on the open market for an aggregate purchase price of $160.4 million, excluding accrued interest, with cash on hand. As a result of these transactions, the Partnership recognized a gain of $1.5 million, net of repurchase costs, included in gain (loss) on extinguishment of debt in the consolidated statements of income and comprehensive income.
25
N. Long-term Debt (Continued)
5.000% Senior Notes due 2029. On April 20, 2021, the Partnership and CrownRock Finance issued $400.0 million aggregate principal amount of the 2029 Senior Notes at par. The Partnership issued the 2029 Senior Notes to fund distributions to Holdings. Holdings utilized the net proceeds in the amount of $396 million to redeem a portion of its Series A Preferred Units. The 2029 Senior Notes mature on May 1, 2029, and interest is paid in arrears semi-annually on May 1 and November 1. The 2029 Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by Roddy, Canvasback, CR Management and CR Royalties. The 2029 Senior Notes may be redeemed on or after the following dates and at the following redemption prices, expressed as a percentage of principal amount plus accrued and unpaid interest if any, during the twelve-month periods beginning on the dates indicated: May 1, 2024, 102.500%; May 1, 2025, 101.667%; May 1, 2026, 100.833%; May 1, 2027 and thereafter, 100.00%.
The 2029 Senior Notes are general, unsecured senior obligations and are subordinated to all existing and future secured indebtedness, including the Credit Facility. The indenture to the 2029 Senior Notes dated as of April 20, 2021 (“2029 Senior Note Indenture”) contains various restrictive covenants which include:
•limits on the incurrence of additional indebtedness and certain types of liens;
•restrictions as to mergers and disposition of assets;
•limits on transactions with affiliates; and
•limits on dividends and distributions. The 2029 Senior Note Indenture allows permitted tax distributions. The 2029 Senior Note Indenture also allows periodic cash distributions up to 50 % of consolidated net income as adjusted for certain non-cash items from July 1, 2017 to the end of the Partnership’s most recently ended fiscal quarter. Based on this provision, as of December 31, 2023, the Partnership is allowed to make discretionary distributions of approximately $1.11 billion. Notwithstanding this limit based on consolidated net income, the 2029 Senior Note Indenture provides for unlimited periodic cash discretionary distributions if the Partnership’s leverage ratio, as defined, is less than 1.5 to 1.0, determined on a pro forma basis giving effect to any such distribution payments. However, discretionary distributions are restricted by the PIPA from January 1, 2024 to the closing date of the Partnership Sale Transaction (See Note P – Agreement to Sell Partnership Interest to Occidental Petroleum Corporation).
At December 31, 2023, the Partnership was in compliance with all of the covenants under the 2029 Senior Note Indenture.
Construction loan - Canvasback office building. On June 19, 2014, Canvasback entered into a construction loan agreement with a bank (the “Construction Loan”) to partially finance the cost of the construction of an office building in Midland, Texas that became the Partnership’s headquarters. Advances were made during the period of February 2015 through December 2015 when the final advance was made, and the balance outstanding was at its maximum amount available of $12.0 million. Construction was completed and the certain conditions of the loan agreement were satisfied in December 2015 to effect the extension of the loan to June 30, 2026. Payments of principal and interest are due on the first of each month in an amount necessary to fully amortize the loan over its remaining term. Advances on the Construction Loan bear interest at a fixed rate equal to the Wall Street Journal published Prime Rate in effect on July 1st of each year plus 100 basis points, but in no event shall the interest rate be less than 4.25% nor more than 4.75%.
On July 6, 2023, Canvasback and the bank modified the Construction Loan amortization schedule and maturity date to facilitate the full amortization of the loan on June 1, 2024. In conjunction with this modification, Canvasback made a principal prepayment on June 30, 2023 in the amount of $1.0 million. The interest rate for the period of July 1, 2023 through June 1, 2024 was determined at 4.75%.
The Construction Loan is secured by a mortgage on the office building. The Partnership unconditionally guarantees Canvasback’s payments and performance on the loan.
On January 19, 2024, Canvasback fully prepaid the remaining principal balance and accrued interest on the Construction Loan. As a result of this repayment, the bank released all security instruments including the mortgage and the Partnership’s guaranty.
Principal maturities of debt. The Credit Facility expires in 2028. The 2025 Senior Notes are due in 2025. The 2029 Senior Notes are due in 2029.
26
N. Long-term Debt (Continued)
Interest expense. The following amounts have been incurred and charged to interest expense for the year ended December 31, 2023:
Year Ended December 31, 2023 | |||||
| (in thousands) | |||||
| Cash payments for interest | $ | 76,733 | |||
| Amortization of original issue discount | 386 | ||||
| Amortization of deferred loan costs | 4,861 | ||||
| Net changes in accrued interest expense | 498 | ||||
| Total interest expense | $ | 82,478 | |||
O.Oil and Natural Gas Property Transactions
Divestitures. In the fourth quarter of 2022, the Partnership conducted a marketing process to sell all its non-core assets in the San Juan Basin of New Mexico. A buyer was identified prior to December 31, 2022, and the Partnership executed the purchase and sale agreement on February 13, 2023. The revenues and expenses associated with these assets for the year ended December 31, 2022 were $2.3 million and $1.3 million, respectively.
On March 31, 2023, the transaction closed and the Partnership received cash proceeds of $2.8 million, which resulted in the recognition of a gain on the sale of $2.2 million. Following this transaction, the Partnership no longer own any assets in the San Juan Basin of New Mexico.
Exchanges. If it is deemed value-adding, the Partnership will enter into exchange agreements with third parties to exchange proved and unproved oil and natural gas properties as part of its strategy to consistently pursue financially viable deals to further block-up its acreage and thereby enhance its horizontal well drilling inventory in the Permian Basin.
During the year ended December 31, 2023, the Partnership did not complete any material exchanges.
P.Agreement to Sell Partnership Interest to Occidental Petroleum Corporation
On December 10, 2023, Holdings and CrownRock GP entered into the PIPA governing the Partnership Sale Transaction. This transaction is expected to close in the second half of 2024, subject to customary closing conditions and the receipt of regulatory approvals.
See Note Q – Subsequent Events for discussion of Federal Trade Commission request for additional information and documentation material.
The PIPA contains various restrictive operating covenants for the period from January 1, 2024 to the closing date of the Partnership Sale Transaction which include:
•limits on variances from the approved 2024 capital expenditure plan;
•limits on indebtedness including limits on amounts which can be borrowed on the Partnership’s Credit Facility;
•limits on the acquisition and sales of properties, assets and entities;
•limits on distributions to Holdings; and
•restriction on entering into any additional commodity hedging transactions.
27
Q. Subsequent Events
Federal Trade Commission issuance of Second Request. On January 19, 2024, Holdings and Occidental each received a request for additional information and documentation material (each, a “Second Request”) from the Federal Trade Commission (“FTC”) in connection with the FTC’s review of the Partnership Sale Transaction. A Second Request extends the waiting period imposed by the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (the “HSR Act”) until 30 days after each of Holdings and Occidental have substantially complied with the Second Request issued to them, unless that period is extended voluntarily by Holdings and Occidental or terminated sooner by the FTC. Holdings and Occidental continue to work constructively with the FTC in its review of the Partnership Sale Transaction.
Entity restructurings and asset conveyances. The Partnership conducted several transactions effective January 31, 2024 to distribute certain Partnership assets to newly formed entities which are wholly owned by Holdings. These include:
•the Partnership distributed its Eastern Shelf properties in Mitchell County, Texas and associated obligations to Eastern Shelf Holdco, LLC (“Eastern Shelf”), a wholly-owned subsidiary of Holdings; and
•Canvasback distributed the office building and land in Midland, Texas, which is the Partnership’s headquarters, to 18 Desta Holdco, LLC (“18 Desta”), a wholly-owned subsidiary of Holdings.
Additionally, the Partnership conducted the following:
•the Partnership distributed all its interest in Roddy to Holdings;
•the Partnership distributed all its interest in Abajo to Holdings. Also, the Partnership resigned as manager of Abajo and assigned such role to Holdings; and
•the Partnership conveyed its ownership in remaining Lea County, New Mexico and San Juan County, Utah assets and associated obligations to Holdings.
Additionally, as a result of these restructuring transactions, the following changes were made relative to existing debt agreements as follows:
•Roddy was released in its capacity as guarantor of the Credit Facility; and
•Roddy, Eastern Shelf and 18 Desta were designated as unrestricted subsidiaries under the indenture governing the 2025 Senior Notes and the indenture governing the 2029 Senior Notes. This resulted in Roddy being released as a guarantor on the 2025 Senior Notes and the 2029 Senior Notes.
28
Supplemental Information on Oil and Natural Gas Exploration and Production Activities (Unaudited)
Costs Incurred in Oil and Natural Gas Property Acquisition and Development Activities
Costs incurred in oil and natural gas property acquisition and development activities are as follows for the periods indicated:
| Year Ended | |||||
| December 31, 2023 | |||||
(in thousands) | |||||
| Property acquisition costs: | |||||
| Proved | $ | (43) | |||
| Unproved | 3,408 | ||||
| Development Costs | 719,204 | ||||
| Exploration Costs | 354,514 | ||||
| Total costs incurred for oil and natural gas properties | $ | 1,077,083 | |||
Oil and Natural Gas Reserves
The Partnership has presented the reserve estimates utilizing an oil price of $74.70 per Bbl and a natural gas price of $2.64 per Mcf as of December 31, 2023.
The proved oil and natural gas reserve estimates of the Partnership have been prepared in compliance with the Securities and Exchange Commission rules and accounting standards based on the 12-month un-weighted first-day-of-the-month average price.
The reserve disclosures that follow reflect estimates of proved reserves, proved developed reserves and proved undeveloped reserves, net of third-party royalty interests, of natural gas, crude oil and condensate, and NGLs owned at each year end and changes in proved reserves during each of the last three years. Natural gas volumes are in millions of cubic feet (MMcf) at a pressure base of 14.73 pounds per square inch and volumes for oil are in thousands of barrels (MBbls).
The Partnership’s estimates of proved reserves are made using available production performance data, as well as pertinent geologic and reservoir data. These estimates are reviewed annually by internal reservoir engineers and revised, either upward or downward as warranted by additional data. Revisions are necessary due to changes in, among other things, reservoir performance, prices, economic conditions and governmental restrictions, as well as changes in the expected recovery associated with infill drilling.
29
The Partnership’s oil and natural gas properties and associated reserves are located in the continental United States. The following table provides a rollforward of the total proved reserves for the year ended December 31, 2023 as well as proved developed and proved undeveloped reserves at the beginning and end of each respective year. Oil volumes are expressed in MBbls, natural gas volumes are expressed in MMcf and natural gas liquid volumes are expressed in MBbls. The Partnership’s estimated reserves at December 31, 2023 were based on reserve reports prepared by the Partnership’s internal petroleum engineers and staff which were audited by Cawley, Gillespie & Associates, Inc., independent petroleum engineers.
| Total Proved Reserves: | 2023 | |||||||||||||
Oil (MBbls) | Gas (MMcf) | NGL (MBbls) | Total (MBoe) | |||||||||||
| Balance, beginning of year | 249,455 | 864,660 | 180,849 | 574,414 | ||||||||||
Acquisitions of minerals-in-place (1) | — | — | — | — | ||||||||||
Sales of minerals-in-place (1) | (163) | (238) | (49) | (252) | ||||||||||
| Extensions and discoveries (2) | 63,820 | 202,636 | 40,651 | 138,245 | ||||||||||
| Revisions of previous estimates (2) | (14,217) | 79,944 | 8,708 | 7,815 | ||||||||||
| Production | (26,862) | (72,861) | (14,674) | (53,680) | ||||||||||
| Balance, end of year | 272,033 | 1,074,141 | 215,485 | 666,542 | ||||||||||
| Proved developed reserves, end of year | 121,729 | 557,509 | 111,843 | 326,491 | ||||||||||
| Proved undeveloped reserves, end of year | 150,304 | 516,632 | 103,642 | 340,051 | ||||||||||
(1)For the year ended December 31, 2023, the Partnership’s sales of minerals-in-place is composed of approximately 0.3 MMBoe for properties surrendered in various exchanges and divestitures throughout the year.
(2)For the year ended December 31, 2023, the Partnership continued its methodology of recording horizontal PUDs by aligning the recognition of the PUDs with the Partnership’s five-year operating plan. These volume revisions include removal of undeveloped reserves that are no longer in our five-year development plan, or have already been in our development plan for more than five years (and thereby must be removed by SEC guidelines). In many cases, these volumes are offset by undeveloped volumes added to extensions and discoveries. Some portion of these downward revisions in 2023 are also related to individual well estimates now reflecting our current full field development plan. Although our tighter spacing results in lower volumes per well, we believe it adds significantly to the total value of our assets, by maximizing our drilling inventory and providing strong incremental economics for increased density wells.
Offsetting such negative revision, the Partnership recorded new PUDs in accordance with further asset development and the timing of the five-year operating plan and development strategy reconfigurations. These are included as extensions and discoveries. Additionally, as a result of spacing guidelines for recognizing PUDs, not all planned wells can be categorized as proved reserves.
The total positive revision of 7,815 MBoe is comprised of 105,710 MBoe from increases in the proved developed producing forecast and adjustments to forecasted well performance offset by (27,122) MBoe from five-year operating plan and development strategy adjustments paired with negative revisions of (70,773) MBoe from commodity price increases.
30
Standardized Measure of Discounted Future Net Cash Flows
Reserve estimates and discounted future net cash flows are based on the un-weighted average market prices for sales of oil and natural gas on the first calendar day of each month during the year. Cash flows are adjusted for transportation fees and regional price differentials, and applied to the estimated future production of proved oil and natural gas reserves less estimated future expenditures to be incurred in developing and producing the proved reserves, discounted using an annual rate of 10% to reflect the estimated timing of the future cash flows. Income taxes are excluded because the Partnership is a non-taxable entity. Generally, all taxable income and losses of the Partnership are reported on the income tax returns of the partners, and therefore, no provision for income taxes has been recorded in the Partnership’s accompanying Consolidated Financial Statements. Extensive judgments are involved in estimating the timing of production and the costs that will be incurred throughout the remaining lives of the properties.
Accordingly, the estimates of future net cash flows from proved reserves and the present value may be materially different from subsequent actual results. The standardized measure of discounted net cash flows does not purport to present, nor should it be interpreted to present, the fair value of the properties’ oil and natural gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, and anticipated future changes in prices and costs.
The table below reflects the standardized measure of discounted future net cash flows related to the Partnership’s interest in proved reserves at December 31, 2023.
| December 31, 2023 | |||||
| (in thousands) | |||||
| Future cash inflows | $ | 25,759,291 | |||
| Future costs: | |||||
| Development | (3,348,772) | ||||
| Production | (7,646,347) | ||||
| Future net cash flows | 14,764,172 | ||||
| 10 % discount to reflect timing of cash flows | (6,390,254) | ||||
| Standardized measure of discounted future net cash flows | $ | 8,373,918 | |||
Changes in Standardized Measure of Discounted Future Net Cash Flows
The following table provides a rollforward of the standardized measure of discounted future net cash flows for the year ended December 31, 2023.
| Oil and natural gas producing activities: | Year Ended December 31, 2023 | ||||
| Balance, beginning of year | $ | 12,263,306 | |||
| Sales of minerals-in-place | (3,757) | ||||
Extensions, discoveries, and improved recoveries, net of future developmental costs | 1,552,607 | ||||
| Revisions of quantity estimates | (588,847) | ||||
| Changes in estimated future development costs, net | 964,594 | ||||
| Net changes in prices | (4,255,345) | ||||
| Oil and natural gas sales, net of production costs | (1,857,600) | ||||
| Changes of production rates and other | (927,371) | ||||
| Accretion of discount | 1,226,331 | ||||
| Balance, end of year | $ | 8,373,918 | |||
31
Exhibit 99.2
CAWLEY, GILLESPIE & ASSOCIATES, INC.
PETROLEUM CONSULTANTS
| 6500 RIVER PLACE BLVD, SUITE 3-200 | 306 WEST SEVENTH STREET, SUITE 302 | 1000 LOUISIANA STREET, SUITE 1900 | ||||||
| AUSTIN, TEXAS 78730-1111 | FORT WORTH, TEXAS 76102-4987 | HOUSTON, TEXAS 77002-5008 | ||||||
| 512-249-7000 | 817- 336-2461 | 713-651-9944 | ||||||
www.cgaus.com
January 24, 2024
Mr. Ken Beattie
Chief Operating Officer & Senior Vice President
CrownQuest Operating, LLC
18 Desta Drive
Midland, TX 79710
| Re: | Reserve Audit — SEC Pricing | ||||
| CrownRock LP Interests | |||||
| Total Proved Reserves | |||||
| As of December 31, 2023 | |||||
| Pursuant to the Guidelines of the | |||||
| Securities and Exchange Commission for | |||||
| Reporting Corporate Reserves and | |||||
| Future Net Revenue | |||||
Dear Mr. Beattie:
As requested, this report was prepared January 24, 2024 for CrownRock LP (“CrownRock”) for the purpose of public disclosure by CrownRock or its affiliates in filings made with the Securities and Exchange Commission (the “SEC”) in accordance with the disclosure requirements set forth in the SEC regulations. We audited 100% of CrownRock reserves, which are made up of oil and gas properties in New Mexico and Texas. Cawley, Gillespie & Associates, Inc. (“CG&A”) has examined the CrownQuest Operating, LLC (CrownQuest) in-house estimates as of December 31, 2023, prepared using constant prices and costs, and conforms to Item 1202(a)(8) of Regulation S-K and other rules of the SEC. The estimates as prepared by CrownQuest are summarized as follows:
| Net Reserves | Proved Developed Producing | Proved Developed Non- Producing | Proved Developed | Proved Undeveloped | Total Proved | |||||||||||||||
| Oil | - Mbbl | 104,906.5 | 16,823.0 | 121,729.5 | 150,303.3 | 272,032.8 | ||||||||||||||
| Gas | - MMcf | 503,436.7 | 54,071.8 | 557,508.5 | 516,632.6 | 1,074,141.1 | ||||||||||||||
| NGL | - Mgal | 4,241,801.3 | 455,592.3 | 4,697,393.6 | 4,352,985.4 | 9,050,378.9 | ||||||||||||||
| Future Net Revenue | - M$ | 10,320,887.5 | 1,539,385.2 | 11,860,272.7 | 13,899,017.8 | 25,759,290.6 | ||||||||||||||
| Future Production Costs | - M$ | 3,182,873.1 | 237,720.9 | 3,420,594.0 | 2,433,592.2 | 5,854,186.2 | ||||||||||||||
| Taxes | - M$ | 720,784.0 | 108,344.6 | 829,128.6 | 963,032.3 | 1,792,160.9 | ||||||||||||||
Future Development Costs | - M$ | 5,187.2 | 149,081.5 | 154,268.7 | 3,194,503.1 | 3,348,771.8 | ||||||||||||||
Net Operating Income (BFIT) | - M$ | 6,412,043.2 | 1,044,238.3 | 7,456,281.5 | 7,307,890.2 | 14,764,171.6 | ||||||||||||||
| Discounted @ 10% | - M$ | 4,021,205.5 | 707,966.9 | 4,729,172.4 | 3,644,745.4 | 8,373,917.8 | ||||||||||||||
CrownRock LP Interests
Reserve Evaluation – SEC Pricing
January 24, 2024
Page 2
Future net revenue is prior to deducting state production taxes and ad valorem taxes. Future net cash flow (net operating income) is after deducting these taxes, future capital (development) costs and operating (production) expenses, but before consideration of federal income taxes. In accordance with SEC guidelines, the future net cash flow has been discounted at an annual rate of ten percent to determine its “present worth”. The present worth is shown to indicate the effect of time on the value of money and should not be construed as being the fair market value of the properties.
The oil reserves, which include oil and condensate volumes, are expressed in barrels (42 U.S. gallons) and natural gas liquids (“NGL”) volumes are in gallons. Gas volumes are expressed in thousands of standard cubic feet (Mcf) at contract temperature and pressure base.
Hydrocarbon Pricing
The base SEC oil and gas prices calculated for December 31, 2023 were $74.70/bbl and $2.64/MMBTU, respectively. As specified by the SEC, a company must use a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. The base oil and gas prices are based upon West Texas Intermediate (Plains Posted) and Henry Hub (Platts Gas Daily) spot prices, respectively, for January 1, 2023 through December 1, 2023.
The base prices shown above were adjusted for differentials on a per-property basis, which may include local basis differentials, transportation, gas shrinkage, gas heating value (BTU content) and/or crude quality and gravity corrections. NGL prices on average were applied to all properties at 29.2% of WTI prices. After these adjustments, the net realized prices for the SEC price case over the life of the proved properties was estimated to be $77.55 per barrel for oil, -$0.04 per MCF for gas, and $0.52 per gallon for NGL. All economic factors were held constant in accordance with SEC guidelines.
Future Development Costs, Expenses and Taxes
Ownership was accepted as furnished and has not been independently confirmed. Oil and gas price differentials, gas shrinkage, ad valorem taxes, severance taxes, lease operating expenses and investments were calculated and prepared by CrownQuest and were reviewed by us for reasonableness. Lease operating expenses were determined at either the field or individual well level using averages calculated from historical lease operating statements. All economic parameters, including lease operating expenses and investments, were held constant (not escalated) throughout the life of these properties in accordance with SEC guidelines.
SEC Conformance and Regulations
The reserve classifications and the economic considerations used herein conform to the criteria of the SEC as defined in pages 6 and 7 of the Appendix. The reserves and economics are predicated on regulatory agency classifications, rules, policies, laws, taxes and royalties currently in effect except as noted herein. Government policies and market conditions different from those employed in this report may cause (1) the total quantity of oil or gas to be recovered, (2) actual production rates, (3) prices received, or (4) operating and capital costs to vary from those presented in this report. However, we do not anticipate nor are we aware of any legislative changes or restrictive regulatory actions that may impact the recovery of reserves.
CG&A evaluated 47 Proved Developed Non-Producing (drilled but uncompleted) and 595 Proved Undeveloped locations targeting various reservoirs in New Mexico and Texas, all of which are commercial using required SEC pricing. Non-producing and undeveloped reserves were assigned based on specific type curves and analogy to recent, modern completions. Furthermore, the development schedule and capital costs for drilling and completions were provided by CrownQuest and accepted as provided upon review for reasonableness.
CrownRock LP Interests
Reserve Evaluation – SEC Pricing
January 24, 2024
Page 3
Each of these commercial drilling locations proposed as part of CrownQuest’s development plan conforms to the proved undeveloped standards as set forth by the SEC. In our opinion, CrownQuest has indicated it has every intent to complete this development plan as scheduled. Furthermore, CrownQuest has demonstrated it has adequate company staffing, financial backing and prior development success to ensure this development plan will be fully executed.
Reserve Estimation Methods
The methods employed in estimating reserves are described on page 5 of the Appendix. Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a relatively high degree of accuracy.
Non-producing reserve estimates, for both developed and undeveloped properties, were forecast using either volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of accuracy for predicting proved developed non-producing and proved undeveloped reserves. The assumptions, data, methods and procedures used herein are appropriate for the purpose served by this report.
General Discussion
An on-site field inspection of the properties has not been performed. The mechanical operation or condition of the wells and their related facilities have not been examined nor have the wells been tested by Cawley, Gillespie & Associates, Inc. (“CG&A”) Possible environmental liability related to the properties has not been investigated nor considered. The cost of plugging and the salvage value of equipment at abandonment have NOT been included as directed by CrownQuest.
The estimates and forecasts were based upon interpretations of data furnished by your office and available from our files. To some extent information from public records has been used to check and/or supplement these data. The basic engineering and geological data were subject to third party reservations and qualifications. Nothing has come to our attention, however, that would cause us to believe that we are not justified in relying on such data. All estimates represent our best judgment based on the data available at the time of preparation. Due to inherent uncertainties in future production rates, commodity prices and geologic conditions, it should be realized that the reserve estimates, the reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be more or less than the estimated amounts.
Opinion
Please be advised that, based upon the foregoing, in our opinion the above-described estimates of the direct interests of CrownRock LP’s reserves and economics are, in the aggregate, reasonable and have been prepared in accordance with generally accepted petroleum engineering and evaluation principles as set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information promulgated by the Society of Petroleum Engineers. In general, CG&A reserve estimates are within 10% of CrownQuest’s in-house reserve estimates shown in the tables above for CrownRock LP properties.
Closing
Cawley, Gillespie & Associates, Inc. is a Texas Registered Engineering Firm (F-693), made up of independent registered professional engineers and geologists that have provided petroleum consulting services to the oil and gas industry for over 60 years. The lead evaluator preparing this report was W. Todd Brooker, P.E.,
CrownRock LP Interests
Reserve Evaluation – SEC Pricing
January 24, 2024
Page 4
President at Cawley, Gillespie & Associates, Inc. and a State of Texas Licensed Professional Engineer (License #83462). We do not own an interest in the properties or CrownRock LP and are not employed on a contingent basis. We have used all methods and procedures that we consider necessary under the circumstances to prepare this report. Our work-papers and related data utilized in the preparation of these estimates are available in our office.
The professional qualifications of the undersigned, the technical person primarily responsible for the preparation of this report, are included as an attachment to this letter. This letter is for the use of CrownRock LP. and should not be used, circulated, or quoted for any other purpose without the express written consent of Cawley, Gillespie & Associates, Inc. or except as required by law.
Sincerely,
CAWLEY, GILLESPIE & ASSOCIATES, INC.
Texas Registered Engineering Firm F-693
/s/ W. Todd Brooker
W. Todd Brooker, P.E.
TBPELS License No. 83462
President
[SEAL]
/s/ Robert P. Bergeron, Jr.
Robert P. Bergeron, Jr., P.E
TBPELS License No. 95592
Partner
[SEAL]
CrownRock LP Interests – SEC Pricing
January 23, 2024
Page 5
Methods Employed in the Estimation of Reserves
The four methods customarily employed in the estimation of reserves are (1) production performance, (2) material balance, (3) volumetric and (4) analogy. Most estimates, although based primarily on one method, utilize other methods depending on the nature and extent of the data available and the characteristics of the reservoirs.
Basic information includes production, pressure, geological and laboratory data. However, a large variation exists in the quality, quantity and types of information available on individual properties. Operators are generally required by regulatory authorities to file monthly production reports and may be required to measure and report periodically such data as well pressures, gas-oil ratios, well tests, etc. As a general rule, an operator has complete discretion in obtaining and/or making available geological and engineering data. The resulting lack of uniformity in data renders impossible the application of identical methods to all properties, and may result in significant differences in the accuracy and reliability of estimates.
A brief discussion of each method, its basis, data requirements, applicability and generalization as to its relative degree of accuracy follows:
Production performance. This method employs graphical analyses of production data on the premise that all factors which have controlled the performance to date will continue to control and that historical trends can be extrapolated to predict future performance. The only information required is production history. Capacity production can usually be analyzed from graphs of rates versus time or cumulative production. This procedure is referred to as "decline curve" analysis. Both capacity and restricted production can, in some cases, be analyzed from graphs of producing rate relationships of the various production components. Reserve estimates obtained by this method are generally considered to have a relatively high degree of accuracy with the degree of accuracy increasing as production history accumulates.
Material balance. This method employs the analysis of the relationship of production and pressure performance on the premise that the reservoir volume and its initial hydrocarbon content are fixed and that this initial hydrocarbon volume and recoveries therefrom can be estimated by analyzing changes in pressure with respect to production relationships. This method requires reliable pressure and temperature data, production data, fluid analyses and knowledge of the nature of the reservoir. The material balance method is applicable to all reservoirs, but the time and expense required for its use is dependent on the nature of the reservoir and its fluids. Reserves for depletion type reservoirs can be estimated from graphs of pressures corrected for compressibility versus cumulative production, requiring only data that are usually available. Estimates for other reservoir types require extensive data and involve complex calculations most suited to computer models which makes this method generally applicable only to reservoirs where there is economic justification for its use. Reserve estimates obtained by this method are generally considered to have a degree of accuracy that is directly related to the complexity of the reservoir and the quality and quantity of data available.
Volumetric. This method employs analyses of physical measurements of rock and fluid properties to calculate the volume of hydrocarbons in-place. The data required are well information sufficient to determine reservoir subsurface datum, thickness, storage volume, fluid content and location. The volumetric method is most applicable to reservoirs which are not susceptible to analysis by production performance or material balance methods. These are most commonly newly developed and/or no-pressure depleting reservoirs. The amount of hydrocarbons in-place that can be recovered is not an integral part of the volumetric calculations but is an estimate inferred by other methods and a knowledge of the nature of the reservoir. Reserve estimates obtained by this method are generally considered to have a low degree of accuracy; but the degree of accuracy can be relatively high where rock quality and subsurface control is good and the nature of the reservoir is uncomplicated.
Analogy. This method which employs experience and judgment to estimate reserves, is based on observations of similar situations and includes consideration of theoretical performance. The analogy method is a common approach used for “resource plays,” where an abundance of wells with similar production profiles facilitates the reliable estimation of future reserves with a relatively high degree of accuracy. The analogy method is applicable where the data are insufficient or so inconclusive that reliable reserve estimates cannot be made by other methods. Reserve estimates obtained by this method are generally considered to have a relatively low degree of accuracy.
Much of the information used in the estimation of reserves is itself arrived at by the use of estimates. These estimates are subject to continuing change as additional information becomes available. Reserve estimates which presently appear to be correct may be found to contain substantial errors as time passes and new information is obtained about well and reservoir performance.
Cawley, Gillespie & Associates, Inc.
CrownRock LP Interests – SEC Pricing
January 23, 2024
Page 6
APPENDIX
Reserve Definitions and Classifications
The Securities and Exchange Commission, in SX Reg. 210.4-10 dated November 18, 1981, as amended on September 19, 1989 and January 1, 2010, requires adherence to the following definitions of oil and gas reserves:
"(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations— prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
"(i)The area of a reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
"(ii)In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
"(iii)Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
"(iv)Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.
"(v)Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
"(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
“(i)Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
“(ii)Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
"(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
“(i)Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
“(ii)Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
“(iii)Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.
Cawley, Gillespie & Associates, Inc.
CrownRock LP Interests – SEC Pricing
January 23, 2024
Page 7
"(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
“(i)When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
“(ii)Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.
“(iii)Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
“(iv)See also guidelines in paragraphs (17)(iv) and (17)(vi) of this section (below).
"(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.
“(i)When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.
“(ii)Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
“(iii)Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
“(iv)The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
“(v)Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.
“(vi)Pursuant to paragraph (22)(iii) of this section (above), where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.”
Instruction 4 of Item 2(b) of Securities and Exchange Commission Regulation S-K was revised January 1, 2010 to state that "a registrant engaged in oil and gas producing activities shall provide the information required by Subpart 1200 of Regulation S–K." This is relevant in that Instruction 2 to paragraph (a)(2) states: “The registrant is permitted, but not required, to disclose probable or possible reserves pursuant to paragraphs (a)(2)(iv) through (a)(2)(vii) of this Item.”
"(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
“Note to paragraph (26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).”
Cawley, Gillespie & Associates, Inc.
CAWLEY, GILLESPIE & ASSOCIATES, INC.
PETROLEUM CONSULTANTS
| 6500 RIVER PLACE BLVD, SUITE 3-200 | 306 WEST SEVENTH STREET, SUITE 302 | 1000 LOUISIANA STREET, SUITE 1900 | ||||||
| AUSTIN, TEXAS 78730-1111 | FORT WORTH, TEXAS 76102-4987 | HOUSTON, TEXAS 77002-5008 | ||||||
| 512-249-7000 | 817- 336-2461 | 713-651-9944 | ||||||
www.cgaus.com
Professional Qualifications of W. Todd Brooker, P.E.
Primary Technical Person
Primary Technical Person
The evaluation summarized by this report was conducted by a proficient team of geologists and reservoir engineers who integrate geological, geophysical, engineering and economic data to produce high quality reserve estimates and economic forecasts. This report was supervised by Todd Brooker, President of Cawley, Gillespie & Associates, Inc. (CG&A).
Prior to joining CG&A, Mr. Brooker worked in Gulf of Mexico drilling and production engineering at Chevron USA. Mr. Brooker has been an employee of CG&A since 1992 and became President in 2017. His responsibilities include reserve and economic evaluations, fair market valuations, expert reporting and testimony, field/reservoir studies, pipeline resource assessments, field development planning and acquisition/divestiture analysis. His reserve reports are routinely used for public company U.S. Securities and Exchange Commission (SEC) disclosures. His experience includes significant projects in both conventional and unconventional resources in every major U.S. producing basin and abroad, including oil and gas shale plays, coalbed methane fields, waterfloods and complex, faulted structures.
Mr. Brooker graduated with honors from the University of Texas at Austin in 1989 with a Bachelor of Science degree in Petroleum Engineering. He is a registered Professional Engineer in the State of Texas (License #83462), and a member of the Society of Petroleum Engineers (SPE) and the Society of Petroleum Evaluation Engineers (SPEE).
Based on his educational background, professional training and more than 30 years of experience, Mr. Brooker and CG&A continue to deliver independent, professional, ethical and reliable engineering and geological services to the petroleum industry.
CAWLEY, GILLESPIE & ASSOCIATES, INC. | ||
TEXAS REGISTERED ENGINEERING FIRM F-693 | ||
Exhibit 99.3
Condensed Consolidated Financial Statements of CrownRock, L.P. and Subsidiaries
for the Period Ended March 31, 2024
TABLE OF CONTENTS
| FINANCIAL INFORMATION | Page | ||||
| Condensed Consolidated Financial Statements (Unaudited) | |||||
| Condensed Consolidated Balance Sheet as of March 31, 2024 | 2 | ||||
| Condensed Consolidated Statement of Income for the Three Months Ended March 31, 2024 | 3 | ||||
| Condensed Consolidated Statement of Partners' Capital for the Three Months Ended March 31, 2024 | 4 | ||||
| Condensed Consolidated Statement of Cash Flows for the Three Months Ended March 31, 2024 | 5 | ||||
| Notes to Condensed Consolidated Financial Statements | 6 | ||||
CROWNROCK, L.P.
CONDENSED CONSOLIDATED BALANCE SHEET
(Unaudited)
| March 31, 2024 | |||||
| (in thousands) | |||||
| ASSETS | |||||
| Current assets: | |||||
| Cash and cash equivalents | $ | 362,598 | |||
| Accounts receivable – related party: | |||||
| Oil and natural gas | 212,225 | ||||
| Other | 37,659 | ||||
| Prepaid costs and other current assets | 1,358 | ||||
| Total current assets | 613,840 | ||||
Oil and natural gas properties, net, successful efforts method of accounting | 3,951,547 | ||||
Other property and equipment, net | 142,230 | ||||
Deferred loan costs, net | 8,948 | ||||
Total Assets | $ | 4,716,565 | |||
LIABILITIES AND PARTNERS' CAPITAL Current liabilities: | |||||
| Accounts payable – related party | $ | 2,422 | |||
| Accrued drilling cost – related party | 60,389 | ||||
| Other accrued liabilities – related party | 13,591 | ||||
| Accrued distribution payable - limited partner | 99,032 | ||||
| Accrued interest payable | 30,217 | ||||
| Asset retirement obligations, current portion | 355 | ||||
| Total current liabilities | 206,006 | ||||
Long-term debt, net | 1,237,894 | ||||
| Asset retirement obligations | 47,185 | ||||
| Total liabilities | 1,491,085 | ||||
Commitments and Contingencies (Note I) | |||||
| CrownRock, L.P. Partners' Capital | 3,225,480 | ||||
| Total Liabilities and Partners' Capital | $ | 4,716,565 | |||
See accompanying notes to these condensed consolidated financial statements.
2
CROWNROCK, L.P.
CONDENSED CONSOLIDATED STATEMENT OF INCOME
(Unaudited)
Statements of Income Revenues: | Three Months Ended March 31, 2024 | ||||
| (in thousands) | |||||
| Oil and natural gas sales | $ | 570,587 | |||
| Saltwater disposal | 20,353 | ||||
| Gathering system rent and transportation fees | 13,159 | ||||
| Fresh water supply | 7,359 | ||||
| Surface ownership | 871 | ||||
| Total revenues | 612,329 | ||||
| Costs and expenses: | |||||
| Lease operating expense | 103,562 | ||||
| Production and ad valorem taxes | 32,765 | ||||
| Depreciation, depletion and amortization | 154,747 | ||||
| Accretion of discount on asset retirement obligation | 529 | ||||
| General and administrative | 4,714 | ||||
| Total costs and expenses | 296,317 | ||||
| Operating income | 316,012 | ||||
| Other income (expense): | |||||
| Interest income | 2,527 | ||||
| Interest expense | (19,394) | ||||
| Other income (expense), net | (1,358) | ||||
| Total other income (expense) | (18,225) | ||||
| Net income attributable to CrownRock, L.P. | $ | 297,787 | |||
See accompanying notes to these condensed consolidated financial statements.
3
CROWNROCK, L.P.
CONDENSED CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL
(Unaudited)
| (in thousands, except units) | Limited Partner | Total CrownRock, LP Partners' Capital | Non- Controlling Interest | Total Partners' Capital | |||||||||||||
Units | Amount | ||||||||||||||||
| Balance, December 31, 2023 | 100 | $ | 3,053,580 | $ | 3,053,580 | $ | (155) | $ | 3,053,425 | ||||||||
| Net income (loss) | — | 297,787 | 297,787 | — | 297,787 | ||||||||||||
| Distributions to limited partner: | |||||||||||||||||
| Tax distribution | — | (99,032) | (99,032) | — | (99,032) | ||||||||||||
| Oil and natural gas properties | — | (12,227) | (12,227) | — | (12,227) | ||||||||||||
| Building and land | — | (14,617) | (14,617) | — | (14,617) | ||||||||||||
| Equity interests in subsidiaries | — | (759) | (759) | 155 | (604) | ||||||||||||
| Capital contribution - unit based compensation | — | 748 | 748 | — | 748 | ||||||||||||
| Balance, March 31, 2024 | 100 | $ | 3,225,480 | $ | 3,225,480 | $ | — | $ | 3,225,480 | ||||||||
See accompanying notes to these condensed consolidated financial statements.
4
CROWNROCK, L.P.
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS
(Unaudited)
| Three Months Ended March 31, 2024 | |||||
| Cash flows from operating activities: | (in thousands) | ||||
| Net income | $ | 297,787 | |||
| Adjustments to reconcile net income to net cash provided by | |||||
| operating activities: | |||||
| Depreciation, depletion and amortization | 154,747 | ||||
| Accretion of discount on asset retirement obligation | 529 | ||||
| Accretion of discount on long-term debt | 90 | ||||
| Amortization of deferred loan costs | 1,127 | ||||
| Unit-based compensation expense | 748 | ||||
| Settlements of asset retirement obligations | (213) | ||||
| Change in assets and liabilities: | |||||
| Accounts receivable – related party | 839 | ||||
| Prepaid costs and other current assets | (52) | ||||
| Accounts payable - related party | 2,412 | ||||
| Other accrued liabilities - related party | 615 | ||||
| Accrued interest payable | 16,909 | ||||
| Other liabilities | (203) | ||||
| Net cash flows provided by operating activities | 475,335 | ||||
| Cash flows from investing activities: | |||||
| Acquisition of leasehold and oil and natural gas properties | (141) | ||||
| Capital expenditures on oil and natural gas properties | (252,903) | ||||
| Additions to other property and equipment | (3,144) | ||||
| Net cash flows used in investing activities | (256,188) | ||||
| Cash flows from financing activities: | |||||
| Distributions of cash of subsidiaries to limited partner | (592) | ||||
| Repayments of long-term borrowings under construction loan | (751) | ||||
| Net cash flows used in financing activities | (1,343) | ||||
| Net increase in cash and cash equivalents | 217,804 | ||||
| Cash and cash equivalents, beginning of period | 144,794 | ||||
| Cash and cash equivalents, end of period | $ | 362,598 | |||
| Supplemental disclosure of cash flow information: | |||||
| Cash paid for interest | 1,263 | ||||
| Non-cash investing and financing activities: | |||||
| Change in accrued capital expenditures in accrued drilling cost | |||||
| and accrued liabilities | 16,492 | ||||
| Additions to asset retirement obligation | 670 | ||||
| Change in accrued distributions to limited partner | 99,032 | ||||
| Asset retirement obligation associated with properties distributed to limited partner | (734) | ||||
| Distribution of oil and natural gas properties to limited partner | 12,961 | ||||
| Distribution of building and land to limited partner | 14,617 | ||||
| Distribution of equity interests in subsidiaries to limited partner | 759 | ||||
See accompanying notes to these condensed consolidated financial statements.
5
CROWNROCK, L.P.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
A. Organization and Nature of Operations
CrownRock, L.P. (the “Partnership,” “we,” “us,” and “our”) is a Delaware limited partnership formed on February 14, 2007 by affiliates of CrownQuest Operating, LLC (“CrownQuest”), an independent oil and natural gas producer which is a wholly-owned subsidiary of one of the members of the Partnership’s ultimate general partner, CrownRock Holdings GP, LLC (“Holdings GP”), and Lime Rock Partners, a private equity firm focused on the oil and natural gas industry (“Lime Rock”). The Partnership’s principal business is the acquisition, development, exploration and production of oil and natural gas properties primarily located in the Permian Basin of West Texas.
On December 21, 2017, affiliates of CrownQuest’s management team and Lime Rock formed CrownRock Holdings, L.P., a Delaware limited partnership (“Holdings”). Effective January 1, 2018, the Partnership merged with a subsidiary of Holdings, and, as a result, Holdings is the sole limited partner of the Partnership and sole owner of the Partnership’s general partner, CrownRock GP, LLC (“CrownRock GP”). The Partnership admitted Holdings as its sole limited partner by issuing 100 new limited partnership units and cancelling all its other limited partner interests comprised of Class A, B, C, D and E limited partnership units. Holdings issued equivalent units of equivalent classes to the former limited partners of the Partnership.
On December 10, 2023, Holdings and CrownRock GP entered into a Partnership Interest Purchase Agreement (the “PIPA”), as amended, to sell their limited partner interests and general partner interests in the Partnership, respectively, to subsidiaries of Occidental Petroleum Corporation, a Delaware Corporation (“Occidental”), for total consideration of approximately $12.0 billion including the assumption of the Partnership’s existing debt (the “Partnership Sale Transaction”). This transaction is expected to close in the second half of 2024, subject to customary closing conditions and the receipt of regulatory approvals. See Note M – Agreement to Sell Partnership Interest to Occidental Petroleum Corporation.
B. Summary of Significant Accounting Policies
Organization and principles of consolidation. On July 7, 2011, CrownRock Finance, Inc. (“CrownRock Finance”), a Delaware corporation and wholly-owned subsidiary of the Partnership, was organized for the sole purpose of serving as co-issuer of senior notes and it is currently a co-issuer of $868 million outstanding aggregate principal amount of 5.625% senior unsecured notes due 2025 (the “2025 Senior Notes”) and $376 million outstanding aggregate principal amount of 5.000% senior unsecured notes due 2029 issued at par (the “2029 Senior Notes” and, together with the 2025 Senior Notes, the “Senior Notes”). CrownRock Finance currently has, and will have, no operations, assets or liabilities other than with respect to the Partnership’s revolving credit facility, as amended (the “Credit Facility”), the Senior Notes or other debt securities the Partnership may issue in the future. See Note L – Long-term Debt.
On February 28, 2014, Canvasback Properties, LLC (“Canvasback”), a Texas corporation and wholly-owned subsidiary of the Partnership, was organized for the purpose of constructing, owning and managing an office building in Midland, Texas, which is the Partnership’s headquarters, and two field operations offices in Martin County, Texas.
On November 15, 2019, CR Royalties Management, LLC (“CR Management”), a Delaware limited liability company, and CR Royalties, L.P. (“CR Royalties”), a Delaware limited partnership, were organized for the purpose of owning oil and gas mineral interests and overriding royalty interests contributed by the Partnership. CR Management is a wholly-owned subsidiary of the Partnership. The Partnership owns 99% of CR Royalties and CR Management owns the remaining 1% of CR Royalties. The Partnership contributed the specified assets effective on January 1, 2020.
Entity restructurings and asset conveyances. The Partnership conducted several transactions effective January 31, 2024 to distribute certain Partnership assets to newly formed entities which are wholly owned by Holdings. These include:
•the Partnership distributed its Eastern Shelf properties in Mitchell County, Texas and associated obligations to Eastern Shelf Holdco, LLC (“Eastern Shelf”), a wholly-owned subsidiary of Holdings; and
•Canvasback distributed the office building and land in Midland, Texas, which is the Partnership’s headquarters, to 18 Desta Holdco, LLC (“18 Desta”), a wholly-owned subsidiary of Holdings.
6
B. Summary of Significant Accounting Policies (Continued)
Additionally, the Partnership conducted the following:
•the Partnership distributed all its interest in Roddy Production Company, LLC (“Roddy”) to Holdings;
•the Partnership distributed all its interest in Abajo Gas Transmission Company, LLC (“Abajo”) to Holdings. Also, the Partnership resigned as manager of Abajo and assigned such role to Holdings; and
•the Partnership conveyed its ownership in remaining Lea County, New Mexico and San Juan County, Utah assets and associated obligations to Holdings.
Additionally, as a result of these restructuring transactions, the following changes were made relative to existing debt agreements as follows:
•Roddy was released in its capacity as guarantor of the Credit Facility; and
•Roddy, Eastern Shelf and 18 Desta were designated as unrestricted subsidiaries under the indenture governing the 2025 Senior Notes and the indenture governing the 2029 Senior Notes. This resulted in Roddy being released as a guarantor on the 2025 Senior Notes and the 2029 Senior Notes.
The distributions were accounted for as transactions between entities under common control; thus, were accounted for at the net book value.
The condensed consolidated financial statements include the accounts of the Partnership and its majority-owned subsidiaries. All intercompany accounts and transactions have been eliminated in consolidation.
Interim financial statements. These condensed consolidated financial statements as of March 31, 2024 and for the three months ended March 31, 2024 are unaudited. In the opinion of management, such financial statements include the adjustments and accruals, all of which are of a normal recurring nature, which are necessary for a fair presentation of the results for the interim periods. These interim results are not necessarily indicative of results for a full year. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted. These unaudited condensed consolidated financial statements should be read in conjunction with the Partnership’s annual financial statements for the year ended December 31, 2023.
Cash and cash equivalents. The Partnership considers all highly liquid instruments with original maturities of three months or less to be cash equivalents.
Accounts receivable – related party and allowance for credit losses. CrownQuest operates 99% of the Partnership’s total wells and markets most of the Partnership’s oil and natural gas to various customers. In conjunction, CrownQuest has oil and natural gas sales receivables and joint interest receivables from third-party working interest owners. Oil and natural gas sales receivables are generally unsecured. CrownQuest monitors exposure to these customers primarily by reviewing credit ratings, financial statements and payment history. CrownQuest extends credit terms based on their evaluation of each customer’s creditworthiness. Receivables are considered past due if full payment is not received by the contractual due date. CrownQuest and the Partnership estimate uncollectible amounts based on the length of time that the accounts receivable has been outstanding, historical collection experience and current and future economic and market conditions, if failure to collect is expected to occur. CrownQuest records allowances for credit losses as reductions to the carrying values of the accounts receivables included in its financial statements if failure to collect an estimable portion is determined to be probable. The Partnership’s allowance for credit losses related to oil and natural gas sales receivables at March 31, 2024 is zero. CrownQuest bills the Partnership for such allowances related to joint interest receivables which are included in management fees and recorded by the Partnership in general and administrative costs in the condensed consolidated statements of income and comprehensive income. CrownQuest had an allowance for joint interest receivable credit losses of $647 thousand at March 31, 2024. The Partnership does not have any off balance sheet credit exposure related to its customers.
Oil and natural gas properties. The Partnership uses the successful efforts method of accounting for its investments in oil and natural gas properties. Under such method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil and natural gas lease acquisition costs are also capitalized.
7
B. Summary of Significant Accounting Policies (Continued)
Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and natural gas leases, are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities. If the unproved properties are determined to be productive, the related costs are transferred to proved oil and natural gas properties. If proved leasehold costs are determined to no longer be proved as a result of changes in the Partnership’s development plan, the related acreage costs are transferred to unproved oil and natural gas properties.
Capitalized costs of producing oil and natural gas properties and support infrastructure, including water-related wells, facilities and equipment, net of estimated salvage values, are depleted and depreciated by the units-of-production method. Acquisition and leasehold costs of proved properties are depleted on the basis of total proved reserves, and capitalized development costs (wells and related equipment and facilities) are depreciated on the basis of proved developed reserves.
On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depreciation, depletion, and amortization are eliminated from the property accounts, and the resulting gain or loss is recognized. On the sale or retirement of a partial unit of proved property, the costs, net of proceeds, are charged to accumulated depreciation, depletion, and amortization, unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized in the statement of income and comprehensive income. Proceeds from sales of partial interests in unproved leases are accounted for as a recovery of costs without recognizing any gain or loss.
On exchanges of oil and natural gas assets with third parties, the Partnership reviews the transactions for certain key aspects that may have a significant impact on its accounting. Exchange transactions that only involve unproved properties are generally measured on recorded values rather than fair values. Thus, no gain or loss is recognized. Conversely, exchange transactions involving proved developed properties must be analyzed for possible business combinations and commercial substance. These aspects, along with others, dictate whether the Partnership records exchanges at recorded values or fair values and whether gains or losses should be recognized.
Oil and natural gas properties are reviewed for impairment when facts and circumstances indicate that their carrying value may not be recoverable. The Partnership reviews its oil and natural gas properties by amortization base or by individual well for those wells not constituting part of an amortization base. The Partnership assesses impairment of capitalized costs of proved oil and natural gas properties by comparing net capitalized costs to estimated undiscounted future net cash flows using management’s expectations of future oil and natural gas prices. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, which would consider estimated future discounted cash flows. Estimating future cash flows involves the use of judgments, including estimation of the proved oil and natural gas reserve quantities, timing of development and production, expected future commodity prices, capital expenditures and production costs. Unproved properties are assessed for impairment at least annually on a property-by-property basis, and any impairment is charged to expense.
The Partnership periodically reviews its proved and unproved oil and natural gas properties that are sensitive to oil and natural gas prices for impairment. Impairment expense is caused primarily due to declines in commodity prices and well performance.
Revenue Recognition. The Partnership recognizes revenues from the sales of oil and natural gas to its customers and aggregates them on the Partnership’s consolidated statement of income and comprehensive income. Disaggregated revenue from contracts with customers by product type is as follows:
| Three Months Ended | |||||
| March 31, 2024 | |||||
| (in thousands) | |||||
| Oil sales | $ | 500,771 | |||
| Natural gas sales | (755) | ||||
| Natural gas liquids sales | 70,571 | ||||
| Total oil and natural gas sales | $ | 570,587 | |||
8
B. Summary of Significant Accounting Policies (Continued)
CrownQuest markets the Partnership’s oil and natural gas and enters into contracts with customers to sell the Partnership’s oil and natural gas production. Revenue from these contracts is recognized by the Partnership in accordance with the five-step revenue recognition model prescribed in Accounting Standards Codification 606, “Revenue from Contracts with Customers” (“ASC 606”). Specifically, revenue is recognized when the Partnership’s performance obligations under these contracts are satisfied, which generally occur with the transfer of control of the oil and natural gas to the purchaser. Control is generally considered transferred when the following criteria are met: (i) transfer of physical custody; (ii) transfer of title; (iii) transfer of risk of loss; and (iv) relinquishment of any repurchase rights or other similar rights. Given the nature of the products sold, revenue is recognized at a point in time based on the amount of consideration the Partnership expects to receive in accordance with the price specified in the contract. Consideration under the oil and natural gas marketing contracts is typically received from the purchaser one to two months after production. At March 31, 2024, the Partnership had receivables related to contracts with customers of approximately $212.2 million. At December 31, 2023, the Partnership had receivables related to contracts with customers of approximately $196.5 million.
Oil Contracts. The majority of CrownQuest’s oil marketing contracts covering the Partnership’s oil production, transfer physical custody and title at or near the wellhead, which is generally when control of the oil has been transferred to the purchaser. The majority of the oil produced is sold under contracts using market-based pricing which is then adjusted for differentials based upon delivery location and oil quality. To the extent differentials are incurred after the transfer of control of the oil, the differentials are included in oil and natural gas sales on the condensed consolidated statements of income and comprehensive income as they represent part of the transaction price of the contract. If the differentials, or other related costs, are incurred prior to the transfer of control of the oil, those costs are included in lease operating expenses on the Partnership’s condensed consolidated statements of income and comprehensive income and are accounted for as costs incurred directly and not netted from the transaction price.
Natural Gas Contracts. The majority of the Partnership’s natural gas is sold at the lease location, which is generally when control of the natural gas has been transferred to the purchaser. The natural gas is sold under (i) percentage of proceeds processing contracts, (ii) fee-based contracts or (iii) a hybrid of percentage of proceeds and fee-based contracts. Under the majority of CrownQuest’s gas marketing contracts covering the Partnership’s gas production, the purchaser gathers the natural gas in the field where it is produced and transports it via pipeline to natural gas processing plants where natural gas liquid products are extracted. The natural gas liquid products and remaining residue gas are then sold by the purchaser. Under the percentage of proceeds and hybrid percentage of proceeds and fee-based contracts, the Partnership receives a percentage of the value for the extracted liquids and the residue gas. Under the fee-based contracts, the Partnership receives natural gas liquids and residue gas value, less the fee component. To the extent control of the natural gas transfers upstream of the transportation and processing activities, revenue is recognized at the net amount received from the purchaser. To the extent that control transfers downstream of those activities, revenue is recognized on a gross basis, and the related costs are classified as lease operating expenses on the Partnership’s condensed consolidated statements of income and comprehensive income.
The Partnership does not disclose the value of unsatisfied performance obligations under its contracts with customers as it applies the practical exemption in accordance with ASC 606. The exemption, as described in ASC 606-10-50-14A, applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required.
Use of estimates. Preparing financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The financial statements are based on a number of significant estimates including oil and natural gas reserve quantities and values, which are the basis for oil and natural gas properties acquired or exchanged, calculation of depreciation, depletion and amortization, asset retirement obligations (“ARO”), and impairment of oil and natural gas properties.
Fair value. Fair value is defined as the price that would be received upon the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are classified and disclosed in one of the following categories:
9
B. Summary of Significant Accounting Policies (Continued)
Level 1. Measured based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. The Partnership considers active markets to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Items included in this category are short term money market investments.
Level 2. Measured based on quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that the Partnership values using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data, or supported by observable levels at which transactions are executed in the marketplace. Instruments in this category are non-exchange traded derivatives such as over-the-counter commodity price swaps, collars and options. The Partnership’s valuation models are primarily industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures.
Level 3. Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e. supported by little or no market activity). Items included in this category are AROs, asset impairments and asset acquisitions and exchanges.
Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Partnership’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.
New accounting pronouncements issued but not yet adopted.
Compensation – Stock Compensation (Topic 718): In March 2024, the FASB issued Accounting Standards Update No. 2024-01 “Compensation – Stock Compensation (Topic 718): Scope - Application of Profits Interest and Similar Awards”, with the objective of uniformity in the accounting treatment for profit interests and similar awards. The update is effective for public business entities for annual periods beginning after December 15, 2024, and interim periods within those annual periods. For all other entities, the amendments are effective for annual periods beginning after December 15, 2025, and interim periods within those annual periods. Early application of this ASU is permitted. The Partnership is currently evaluating the impact of ASU No. 2024-01 on its consolidated financial statements.
Subsequent events. The Partnership performed an evaluation of subsequent events through May 10, 2024, which is the date the condensed consolidated financial statements were available to be issued.
C. Oil and Natural Gas Properties
The following table sets forth information concerning the Partnership’s oil and natural gas properties as of March 31, 2024:
| March 31, 2024 | |||||
| (in thousands) | |||||
| Proved oil and natural gas properties | $ | 6,935,802 | |||
| Unproved oil and natural gas properties | 340,772 | ||||
| Less accumulated depreciation, depletion, | |||||
| amortization and impairment | (3,325,027) | ||||
| Net oil and natural gas properties | $ | 3,951,547 | |||
During the three months ended March 31, 2024, the Partnership did not recognize any exploration costs.
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C. Oil and Natural Gas Properties (Continued)
Additionally, during the three months ended March 31, 2024, the Partnership did not recognize any non-cash charges against earnings nor a corresponding allowance for expiring acreage.
See Note H – Fair Value for discussion of proved property impairments recorded during the three months ended March 31, 2024.
D. Other Property and Equipment
The following table sets forth the Partnership’s other property and equipment as of March 31, 2024:
| March 31, 2024 | |||||
| (in thousands) | |||||
| Land | $ | 23,904 | |||
| Water rights | 11,872 | ||||
| Construction in progress - gathering systems | 1,264 | ||||
| Office buildings | 7,988 | ||||
| Equipment | 45 | ||||
| Gathering systems | 120,218 | ||||
| Compressor stations | 18,930 | ||||
| Less accumulated depletion, depreciation and impairment | (41,991) | ||||
| Net other property and equipment | $ | 142,230 | |||
E. Asset Retirement Obligations
The Partnership records a liability for the present value of all legal obligations associated with the retirement of tangible long-lived assets and capitalizes an equal amount as part of the cost of their related oil and natural gas properties. AROs are initially recorded at fair value and assessed for revisions periodically thereafter. The significant unobservable inputs to this fair value measurement include estimates of plugging, abandonment and remediation costs and well life. The inputs are calculated based on historical data as well as current estimated costs.
The following table summarizes the changes in the Partnership’s ARO during the three months ended March 31, 2024:
Three Months Ended | |||||
March 31, 2024 | |||||
(in thousands) | |||||
| Balance, beginning of period | $ | 47,288 | |||
| Liabilities incurred during the period | 670 | ||||
| Liabilities settled during the period | (213) | ||||
| Liabilities associated with properties distributed to limited partner | (734) | ||||
| Accretion expense | 529 | ||||
| Balance, end of period | 47,540 | ||||
| Less current portion | (355) | ||||
| Non-current portion | $ | 47,185 | |||
AROs for natural gas pipeline facilities generally become firm at the time the facilities are permanently shut down and dismantled. These obligations may include the costs of asset disposal and additional soil remediation. However, these sites have indeterminate lives based on plans for continued operations and as such, the fair value of the conditional legal obligations cannot be measured since it is impossible to estimate the future settlement dates of such obligations.
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F. Credit and Counterparty Risk
Cash and cash equivalents are maintained at financial institutions and, at times, balances may exceed federally insured limits. Amounts on deposit at financial institutions at March 31, 2024 were approximately $2.6 million, of which approximately $1.6 million was in excess of federally insured limits. In addition to funds maintained at financial institutions, at March 31, 2024, the Partnership had approximately $360.0 million invested in an institutional fund that invests at least 99.5% of its total assets in cash, U.S. Treasury Bills, notes or other obligations issued or guaranteed as to principal and interest by the U.S. Treasury, and repurchase agreements secured by such obligations or cash. The Partnership classifies investment securities with original maturities of three months or less as cash equivalents.
At March 31, 2024, the Partnership had no commodity derivatives. The Partnership routinely monitors the creditworthiness of its counterparties but does not require collateral or other security to support derivative instruments. However, agreements with the counterparties contain netting provisions such that if a default occurs, the non-defaulting party can offset the amount payable to the defaulting party under derivative contracts with the amount due from the defaulting party under derivative contracts. As a result of the netting provisions, the Partnership’s maximum amount of loss due to credit risk is limited to the net amounts due to and from the counterparty under the derivative contracts.
G. Related Party Transactions
Related party operator of oil and natural gas properties. Most of the Partnership’s properties are operated by CrownQuest. As of March 31, 2024, aggregate related party accounts payable and accrued liabilities owed to CrownQuest in the normal course of the Partnership’s oil and natural gas property operations were $76.4 million, related specifically to accrued drilling costs on wells being drilled and completed as of period end, accrued ad valorem taxes and accrued infrastructure costs on facilities being constructed as of period end. Further, with respect to the properties operated by CrownQuest, at March 31, 2024, related party accounts receivable outstanding in the normal course of business related primarily to accrued oil and natural gas sales, fresh water sales and water disposal fees were $249.9 million.
As a result of its ownership of surface acreage, water rights and infrastructure, the Partnership recognizes amounts due from CrownQuest for surface damages, fresh water purchases and water disposal. During the three months ended March 31, 2024, the Partnership recognized receivables from CrownQuest of $12.3 million for these transactions. The unpaid portion of these amounts due are included in the related party accounts receivable listed above.
Management fees paid to related party. Pursuant to an administrative support agreement, the Partnership pays CrownQuest a monthly management fee based upon an annual budget approved by the Partnership. The Partnership is required to reimburse CrownQuest for substantially all costs, which include employee expense, rent expense, license fees, insurance cost, general office expenses, depreciation expense related to capitalized equipment, third party charges incurred for the benefit of the Partnership, and any and all expenses incurred by CrownQuest in providing support to the Partnership net of any amounts received under any operating agreements. During the three months ended March 31, 2024, the Partnership recorded management fees of $3.6 million in general and administrative expenses.
Royalty and other payments to affiliates. CrownQuest, as the operator of the Partnership’s properties, periodically makes various types of payments to companies affiliated with CrownQuest and the Partnership in connection with its role as operator of properties in which the Partnership owns a working interest. During the three months ended March 31, 2024 payments of $39.7 million were made by CrownQuest to affiliates for royalty interests, lease bonuses and extensions, surface acquisitions, surface damages, water purchases and water disposal with respect to such properties. Payments during the three months ended March 31, 2024 include amounts paid to a CrownQuest-affiliated royalty partnership formed in July 2018 (the “2018 Royalty Partnership”) and a CrownQuest-affiliated royalty partnership formed in March 2016 (the “2016 Royalty Partnership”). These royalty partnerships acquired royalty interests from third parties on properties operated by CrownQuest and in which the Partnership owns working interests. Payments to the 2018 Royalty Partnership during the three months ended March 31, 2024 were $6.5 million, primarily for royalty interests on properties operated by CrownQuest in which the Partnership owns a working interest. Payments to the 2016 Royalty Partnership during the three months ended March 31, 2024 were $31.2 million, primarily for royalty interests on properties operated by CrownQuest.
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G. Related Party Transactions (Continued)
Oil and natural gas property lease from an officer of CrownQuest. A family partnership controlled by Mr. Robert W. Floyd, President of CrownQuest and Director of Holdings GP, and his wife has royalty interests in certain properties that the Partnership is developing in the Permian Basin. During the three months ended March 31, 2024, CrownQuest paid $2 thousand for royalty interests on properties operated by CrownQuest.
In a series of transactions beginning in August 2013, the Partnership entered into oil and natural gas property lease agreements with several relatives of Mr. Floyd and a family limited liability company in which Mr. Floyd owns a 33 1/3% interest. The leases are for unproved acreage in the Midland Basin in West Texas. The Partnership is currently developing this acreage. During the three months ended March 31, 2024, CrownQuest paid $13.5 million, primarily for royalty interests on properties operated by CrownQuest, to Mr. Floyd’s relatives and the family limited liability company mentioned above.
Related party owner and operator of aircraft used by CrownQuest. Mr. Floyd and EnerQuest Oil & Gas Ltd. (“EOG”), an entity affiliated with the Partnership, own an entity named EnerQuest Aviation Partners, LLC (“Aviation Partners”) which owns 60% of an aircraft with the other 40% belonging to a third party individual. The aircraft is managed by Crown Eye Partners, LLC (“Crown Eye”) which is owned 60% by Aviation Partners and 40% by the same third party individual. This aircraft is available for use by CrownQuest employees when conducting business on behalf of the Partnership. The Partnership pays CrownQuest’s usage of the aircraft under the terms of the administrative support agreement. During the three months ended March 31, 2024, CrownQuest did not use the aircraft.
H. Fair Value
Assets and Liabilities Measured at Fair Value on a Recurring Basis. The following table sets forth by level within the fair value hierarchy the Partnership’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2024.
| Description | Fair value measurements using | ||||||||||||||||||||||
Quoted prices in active markets (Level 1) | Other observable inputs (Level 2) | Unobservable inputs (Level 3) | Fair Value | ||||||||||||||||||||
(in thousands) | |||||||||||||||||||||||
| Money market funds | $ | 360,004 | $— | $— | $ | 360,004 | |||||||||||||||||
Total as of March 31, 2024 | $ | 360,004 | $— | $— | $ | 360,004 | |||||||||||||||||
The following table represents the carrying amounts and fair values of the Partnership’s financial instruments at March 31, 2024.
| March 31, 2024 | |||||||||||
| Carrying Value | Fair Value | ||||||||||
| (in thousands) | |||||||||||
| Assets: | |||||||||||
| Money market funds | $ | 360,004 | $ | 360,004 | |||||||
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H. Fair Value (Continued)
Credit Facility. The fair value of the revolving Credit Facility borrowings approximate the carrying amounts
based upon interest rates currently available to the Partnership for borrowings with similar terms (Level 2).
Senior Notes. The fair value of the Partnership’s 2025 Senior Notes was $863.8 million at March 31, 2024. The fair value of the Partnership’s 2029 Senior Notes was $368.6 million at March 31, 2024. Such fair value was determined using Level 2 inputs including quoted period end market prices.
Other financial assets and liabilities. The Partnership has other financial instruments consisting primarily of receivables, payables and other current assets and liabilities. The carrying amounts approximate fair value due to the short maturity of these instruments.
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis. Non-recurring fair value
measurements include certain nonfinancial assets and liabilities as may be acquired in a business combination or property exchange and thereby measured at fair value; impaired oil and natural gas property assessments; and the initial recognition of AROs for which fair value is used. These estimates are derived from historical costs as well as management’s expectation of future cost and commodity price environments. As there is no corroborating market activity to support the assumptions used, the Partnership has designated these estimates as Level 3.
Impairments of long-lived assets. The Partnership reviews its long-lived assets to be held and used, including proved oil and natural gas properties accounted for under the successful efforts method of accounting, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable, for instance when there are declines in commodity prices or well performance. The Partnership performed such a review at March 31, 2024 and determined there was no impairment. During the three months ended March 31, 2024, the Partnership did not recognize a non-cash charge against earnings nor a corresponding allowance for expiring acreage.
I. Commitments and Contingencies
As part of the administrative support agreement between the Partnership and CrownQuest, the Partnership reimburses CrownQuest for rent expense. At March 31, 2024, CrownQuest was party to one operating lease with Canvasback for office space: lease agreement dated August 28, 2023 with Canvasback as lessor on the field operations office and barn in Martin County, Texas and the extension of the field operations office in Martin County, Texas. The lease agreement was effective September 1, 2023 and terminates on August 31, 2024.
During the three months ended March 31, 2024, the Partnership reimbursed CrownQuest for rent expense for office space of $295 thousand, included in the monthly management fee. The rent expense relates to the Canvasback lease which is eliminated in consolidation.
In conjunction with the entity restructurings and asset conveyances – see Note B – Summary of Significant Accounting Policies – and Canvasback’s distribution of the Partnership’s headquarters building and land to 18 Desta, the operating lease for the headquarters building with CrownQuest, as lessee, was also assigned to 18 Desta.
CrownQuest has entered into contracts to secure the availability of drilling rigs and are subject to payments in accordance with the contracts based on the utilization of the drilling rigs.
From time to time, the Partnership is party to ordinary routine litigation incidental to the business. The Partnership believes that the results of such proceedings will not have a material adverse effect on its condensed consolidated financial statements.
J. Partners’ Capital
CrownRock, L.P. is a privately held limited partnership formed in the State of Delaware on February 14, 2007. Holdings GP has the exclusive right to manage the business of the Partnership and has all powers and rights necessary or advisable to effectuate and carry out the purposes and business of the Partnership.
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J. Partners’ Capital (Continued)
Effective January 1, 2018, the Partnership merged with a subsidiary of Holdings. As a result of this merger, the Partnership and CrownRock GP became wholly-owned subsidiaries of Holdings. The Partnership admitted Holdings as its sole limited partner by issuing 100 new limited partnership units and cancelling all its other limited partner interests comprised of Class A, B, C, D and E limited partnership units. Holdings issued equivalent units of equivalent classes to the former limited partners of the Partnership. The only outstanding units of the Partnership at March 31, 2024 are the 100 limited partnership units held by Holdings. Additionally, effective January 1, 2018, the Partnership executed its Second Amended and Restated Limited Partnership Agreement to provide for sole control and management of the Partnership by CrownRock GP and the simplification of the governance of the Partnership.
Distributions are made solely to Holdings as the Partnership’s sole limited partner and in turn, Holdings has made distributions to its limited partners.
The Partnership’s Credit Facility, the indentures governing its 2025 Senior Notes and 2029 Senior Notes and the PIPA have restrictive covenants limiting dividends and distributions (See Note L – Long-term Debt and Note M – Agreement to Sell Partnership Interests to Occidental Petroleum Corporation). The Partnership makes distributions to Holdings within the limits of these agreements.
During the three months ended March 31, 2024, the Partnership recognized a distribution payable of $99.0 million, to provide Holdings with funds to pay its holders of Class A, B, C, D and E limited partnership units for estimated tax.
Based upon the provisions of the Partnership’s more restrictive indenture which governs the 2025 Senior Notes, as of March 31, 2024, the Partnership is allowed to make additional discretionary distributions to Holdings of approximately $1.18 billion (See Note L – Long-term Debt). However, discretionary distributions are restricted by the PIPA from January 1, 2024 to the closing date of the Partnership Sale Transaction (See Note M – Agreement to Sell Partnership Interest to Occidental Petroleum Corporation).
K. Incentive Plans
Defined contribution plan. CrownQuest sponsors a 401(k) defined contribution plan for the benefit of substantially all employees. Currently, CrownQuest matches 100% of employee contributions, not to exceed 10% of the employee’s annual base salary. The Partnership’s contributions to the plan, through its reimbursement to CrownQuest pursuant to the terms of an administrative support agreement, were approximately $976 thousand for the three months ended March 31, 2024.
L. Long-term Debt
The Partnership’s debt consists of the following at March 31, 2024:
March 31, 2024 | |||||
(in thousands) | |||||
| 5.625% unsecured senior notes due 2025 | $ | 868,132 | |||
| 5.000% unsecured senior notes due 2029 | 376,084 | ||||
| Unamortized original issue discount | (552) | ||||
| Unamortized deferred loan costs - senior notes | (5,770) | ||||
| Total debt | 1,237,894 | ||||
Credit facility. The Partnership’s Credit Facility has a maturity date of March 7, 2028. In conjunction with its regular semi-annual borrowing base redetermination done in conjunction with its amendment and syndication, effective November 9, 2023, the Partnership’s lenders reaffirmed the borrowing base at $2.0 billion. The Partnership also elected to maintain its elected commitment amount of $1.0 billion. Commitments from the Partnership’s bank group total $3.5 billion. As of March 31, 2024, the Partnership had no advances outstanding against the Credit Facility.
The PIPA limits advances outstanding on the Credit Facility to $20 million for the period of February 1, 2024 until the closing of the Partnership Sale Transaction.
15
L. Long-term Debt (Continued)
Between scheduled semi-annual borrowing base redeterminations in May and November, the Partnership and lenders, if requested by 66 2/3% of the lenders, may each request one special redetermination.
Advances on the Credit Facility bear interest, at the Partnership’s option, based on (i) Secured Overnight Financing Rate (“SOFR”) or (ii) the prime rate as quoted by The Wall Street Journal (“Prime Rate”) (8.50% at March 31, 2024). The Credit Facility’s interest rates on SOFR rate advances and Prime Rate advances vary, with interest margins ranging from 175 to 275 basis points and 75 to 175 basis points, respectively, per annum depending on the debt balance outstanding. Additionally, SOFR rate advances include a 10 basis points credit spread adjustment. The Partnership pays commitment fees on the unused portion of the available commitment of 50 basis points per annum. Total interest expense on the Credit Facility, including commitment fees paid on the unused portion, was $1.3 million for the three months ended March 31, 2024. The weighted average cash interest rate on the Credit Facility, including commitment fees, for the three months ended March 31, 2024 was 0.5%.
The Partnership’s obligations under the Credit Facility are secured by a first lien on substantially all of its oil and natural gas properties. In addition, all of the Partnership’s subsidiaries (excluding Roddy and Abajo) are guarantors, and the equity interests in such subsidiaries have been pledged to secure borrowings under the Credit Facility.
If the outstanding principal balance under the Credit Facility exceeds the aggregate available commitment amount at any time, the Partnership must make a lump sum payment curing the deficiency within three business days. If the outstanding principal balance of the loans under the Credit Facility exceeds the borrowing base at any time, the Partnership has the option to take any of the following actions, either individually or in combination: (1) make a lump sum payment curing the deficiency within 30 days; (2) pledge additional collateral sufficient in the lenders’ opinion to increase the borrowing base and cure the deficiency; or (3) begin making equal monthly principal payments that will cure the deficiency within the ensuing six-month period.
The Credit Facility contains various restrictive covenants and compliance requirements, which include:
•maintenance of certain financial ratios, including:
(i) maintenance of a quarterly ratio of current assets to current liabilities to be not less than 1.0 to 1.0, excluding noncash assets and liabilities related to financial derivatives and AROs and including all letter of credit obligations as liabilities but excluding current maturities of indebtedness, and including any unused availability under the Credit Facility as a current asset, and
(ii) maintenance of a quarterly ratio of total funded indebtedness, net of unrestricted cash up to $125 million, to 12-month consolidated earnings before interest expense, income taxes, depletion, depreciation, and amortization, exploration expense and noncash income and expenses to be no greater than 3.5 to 1.0.
•delivery to the lender and maintenance of satisfactory title opinions covering not less than 80% and 85% of the present value of proved oil and natural gas reserves and proved developed producing oil and natural gas reserves, respectively;
•limits on the incurrence of additional indebtedness and certain types of liens;
•restrictions as to investments, mergers, acquisitions and dispositions of assets;
•restrictions on hedging contracts and transactions with affiliates; and
•limits on dividends and distributions. The agreement allows permitted tax distributions. It also allows periodic cash distributions if the unused availability on the Credit Facility, plus unrestricted cash, is greater than or equal to 20% of the elected commitment amount, and the Partnership’s funded indebtedness to 12-month consolidated earnings before interest expense, income taxes, depletion, depreciation and amortization, exploration expense and non-cash income and expenses is no more than 3.00 to 1.00 calculated on a pro forma basis after giving effect to such cash payment. However, discretionary distributions are restricted by the PIPA from January 1, 2024 to the closing date of the Partnership Sale Transaction (See Note M – Agreement to Sell Partnership Interest to Occidental Petroleum Corporation).
16
L. Long-term Debt (Continued)
At March 31, 2024, the Partnership was in compliance with all of the covenants under the Credit Facility.
5.625% Senior Notes due 2025. On October 11, 2017, the Partnership and CrownRock Finance issued $1.0 billion aggregate principal amount of the 2025 Senior Notes at par. On May 22, 2018, the Partnership and CrownRock Finance issued an additional $185 million aggregate principal amount of 2025 Senior Notes at 98.26% of par. These additional notes were fungible with the original notes and are governed by the same indenture and thus contain the same terms and conditions.
The 2025 Senior Notes mature on October 15, 2025, and interest is paid in arrears semi-annually on April 15 and October 15. The 2025 Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by Canvasback, CR Management and CR Royalties. The notes may be redeemed on or after October 15, 2023 at the redemption price of 100.00%, expressed as a percentage of principal amount plus accrued and unpaid interest if any.
The 2025 Senior Notes are general, unsecured senior obligations and are subordinated to all existing and future secured indebtedness, including the Credit Facility. The indenture to the 2025 Senior Notes dated as of October 11, 2017, as supplemented (“2025 Senior Note Indenture”) contains various restrictive covenants which include:
•limits on the incurrence of additional indebtedness and certain types of liens;
•restrictions as to mergers and disposition of assets;
•limits on transactions with affiliates; and
•limits on dividends and distributions. The 2025 Senior Note Indenture allows permitted tax distributions. The 2025 Senior Notes Indenture also allows periodic cash distributions up to $150 million plus 50% of consolidated net income as adjusted for certain non-cash items from July 1, 2017 to the end of the Partnership’s most recently ended fiscal quarter. Based on this provision, as of March 31, 2024, the Partnership is allowed to make discretionary distributions of approximately $1.18 billion. However, discretionary distributions are restricted by the PIPA from January 1, 2024 to the closing date of the Partnership Sale Transaction (See Note M – Agreement to Sell Partnership Interest to Occidental Petroleum Corporation).
At March 31, 2024, the Partnership was in compliance with all of the covenants under the 2025 Senior Note Indenture.
5.000% Senior Notes due 2029. On April 20, 2021, the Partnership and CrownRock Finance issued $400.0 million aggregate principal amount of the 2029 Senior Notes at par. The Partnership issued the 2029 Senior Notes to fund distributions to Holdings. Holdings utilized the net proceeds in the amount of $396 million to redeem a portion of its Series A Preferred Units. The 2029 Senior Notes mature on May 1, 2029, and interest is paid in arrears semi-annually on May 1 and November 1. The 2029 Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by Canvasback, CR Management and CR Royalties. The 2029 Senior Notes may be redeemed on or after the following dates and at the following redemption prices, expressed as a percentage of principal amount plus accrued and unpaid interest if any, during the twelve-month periods beginning on the dates indicated: May 1, 2024, 102.500%; May 1, 2025, 101.667%; May 1, 2026, 100.833%; May 1, 2027 and thereafter, 100.00%.
The 2029 Senior Notes are general, unsecured senior obligations and are subordinated to all existing and future secured indebtedness, including the Credit Facility. The indenture to the 2029 Senior Notes dated as of April 20, 2021 (“2029 Senior Note Indenture”) contains various restrictive covenants which include:
•limits on the incurrence of additional indebtedness and certain types of liens;
•restrictions as to mergers and disposition of assets;
•limits on transactions with affiliates; and
•limits on dividends and distributions. The 2029 Senior Note Indenture allows permitted tax distributions. The 2029 Senior Note Indenture also allows periodic cash distributions up to 50% of consolidated net income as adjusted for certain non-cash items from July 1, 2017 to the end of the Partnership’s most recently ended fiscal quarter. Based on this provision, as of March 31, 2024, the Partnership is allowed to make
discretionary distributions of approximately $1.26 billion. Notwithstanding this limit based on
consolidated net income, the 2029 Senior Note Indenture provides for unlimited periodic cash discretionary distributions if the Partnership’s leverage ratio, as defined, is less than 1.5 to 1.0, determined on a pro forma
consolidated net income, the 2029 Senior Note Indenture provides for unlimited periodic cash discretionary distributions if the Partnership’s leverage ratio, as defined, is less than 1.5 to 1.0, determined on a pro forma
17
L. Long-term Debt (Continued)
•basis giving effect to any such distribution payments. However, discretionary distributions are restricted by the PIPA from January 1, 2024 to the closing date of the Partnership Sale Transaction (See Note M – Agreement to Sell Partnership Interest to Occidental Petroleum Corporation).
At March 31, 2024, the Partnership was in compliance with all of the covenants under the 2029 Senior Note Indenture.
Construction loan - Canvasback office building. On June 19, 2014, Canvasback entered into a construction loan agreement with a bank (the “Construction Loan”) to partially finance the cost of the construction of an office building in Midland, Texas that became the Partnership’s headquarters. Advances were made during the period of February 2015 through December 2015 when the final advance was made, and the balance outstanding was at its maximum amount available of $12.0 million. Construction was completed and the certain conditions of the loan agreement were satisfied in December 2015 to effect the extension of the loan to June 30, 2026. Payments of principal and interest are due on the first of each month in an amount necessary to fully amortize the loan over its remaining term. Advances on the Construction Loan bear interest at a fixed rate equal to the Wall Street Journal published Prime Rate in effect on July 1st of each year plus 100 basis points, but in no event shall the interest rate be less than 4.25% nor more than 4.75%.
On July 6, 2023, Canvasback and the bank modified the Construction Loan amortization schedule and maturity date to facilitate the full amortization of the loan on June 1, 2024. In conjunction with this modification, Canvasback made a principal prepayment on June 30, 2023 in the amount of $1.0 million. The interest rate for the period of July 1, 2023 through June 1, 2024 was determined at 4.75%.
On January 19, 2024, Canvasback fully prepaid the remaining principal balance and accrued interest on the Construction Loan. As a result of this repayment, the bank released all security instruments including the mortgage and the Partnership’s guaranty which had been part of the original loan documents.
Effective January 31, 2024, Canvasback distributed the office building to 18 Desta, a wholly-owned subsidiary of Holdings.
Principal maturities of debt. The Credit Facility expires in 2028. The 2025 Senior Notes are due in 2025. The 2029 Senior Notes are due in 2029.
Interest expense. The following amounts have been incurred and charged to interest expense for the three months ended March 31, 2024:
Three Months Ended March 31, 2024 | |||||
| (in thousands) | |||||
| Cash payments for interest | $ | 1,263 | |||
| Amortization of original issue discount | 90 | ||||
| Amortization of deferred loan costs | 1,127 | ||||
| Net changes in accrued interest expense | 16,914 | ||||
| Total interest expense | $ | 19,394 | |||
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M. Agreement to Sell Partnership Interest to Occidental Petroleum Corporation
On December 10, 2023, Holdings and CrownRock GP entered into the PIPA governing the Partnership Sale Transaction. This transaction is expected to close in the second half of 2024, subject to customary closing conditions and the receipt of regulatory approvals.
The PIPA contains various restrictive operating covenants for the period from January 1, 2024 to the closing date of the Partnership Sale Transaction which include:
•limits on variances from the approved 2024 capital expenditure plan;
•limits on indebtedness including limits on amounts which can be borrowed on the Partnership’s Credit Facility;
•limits on the acquisition and sales of properties, assets and entities;
•limits on distributions to Holdings; and
•restriction on entering into any additional commodity hedging transactions.
On January 19, 2024, Holdings and Occidental each received a request for additional information and documentation material (each, a “Second Request”) from the Federal Trade Commission (“FTC”) in connection with the FTC’s review of the Partnership Sale Transaction. A Second Request extends the waiting period imposed by the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (the “HSR Act”) until 30 days after each of Holdings and Occidental have substantially complied with the Second Request issued to them, unless that period is extended voluntarily by Holdings and Occidental or terminated sooner by the FTC. Holdings and Occidental continue to work constructively with the FTC in its review of the Partnership Sale Transaction.
19
Exhibit 99.4
UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS
On December 10, 2023, Occidental Petroleum Corporation (“Occidental”) and certain of its subsidiaries entered into an agreement (the “purchase agreement”) to purchase CrownRock, L.P. (“CrownRock”) for total consideration of approximately $12.5 billion (“the acquisition”) consisting of $9.4 billion of cash consideration (inclusive of and subject to certain working capital adjustments set forth in the purchase agreement), approximately 29.6 million shares of common stock of Occidental, and the assumption of $1.2 billion of existing debt of CrownRock. Concurrent with or prior to the acquisition closing, Occidental intends to issue $9.7 billion aggregate principal amount of new debt.
In 2019, Occidental Midland Basin, LLC, a wholly owned indirect subsidiary of Occidental (“Occidental Midland Basin”), and Ecopetrol Permian LLC (“Ecopetrol”), formed Rodeo Midland Basin, LLC (the “Rodeo Midland Basin Joint Venture”), as a joint venture to develop and operate oil and gas properties in the Midland Basin. Under that joint venture, each of Occidental Midland Basin and Ecopetrol were given the right, subject to certain conditions, to participate in oil and gas interests acquired by the other and its affiliates in an area of mutual interest. On March 4, 2024, Occidental Midland Basin and Ecopetrol entered into a letter agreement regarding Ecopetrol’s evaluation of CrownRock’s assets. On May 31, 2024, Ecopetrol notified Occidental of its intent to acquire an undivided thirty percent (30%) interest in the CrownRock assets, subject to the negotiation of a mutually agreeable transaction structure. Occidental and Ecopetrol are engaged in discussions regarding a structure for Ecopetrol’s potential acquisition of an undivided thirty percent (30%) interest in the CrownRock assets (the “Ecopetrol Transaction”). If consummated, Occidental expects the Ecopetrol Transaction purchase price to be approximately $3.6 billion (which equates to approximately thirty percent (30%) of the aggregate consideration to be paid by Occidental in connection with the acquisition), subject to customary purchase price adjustments based on a January 1, 2024 effective date. If Occidental and Ecopetrol are unable to reach agreement regarding the structure of the Ecopetrol Transaction and the joint ownership, development and operation of the CrownRock assets related to such Ecopetrol Transaction in August 2024, then Ecopetrol will have an option to elect for the Rodeo Midland Basin Joint Venture to acquire the CrownRock assets, resulting in an indirect ownership by Ecopetrol of an undivided forty-nine percent (49%) interest in the CrownRock assets (the “Ecopetrol Option”). The Ecopetrol Option expires in August 2024, and there is no assurance that Ecopetrol can or would exercise the Ecopetrol Option.
The unaudited pro forma condensed combined financial statements (the “pro forma financial statements”) presented below have been prepared from the respective historical consolidated financial statements of Occidental and CrownRock and have been adjusted to reflect (i) the completion of the acquisition, (ii) Occidental’s incurrence of $9.7 billion aggregate principal amount of new indebtedness, (iii) the issuance of approximately 29.6 million shares of Occidental’s common stock, (iv) the redemption of CrownRock’s unsecured senior notes due in 2025 (the “CrownRock 2025 notes”) and (v) the Ecopetrol Transaction (which is subject to entry into definitive agreements and consummation of the transactions contemplated thereby). The unaudited pro forma condensed combined balance sheet (the “pro forma balance sheet”) is presented as if the transactions had been completed on March 31, 2024. The unaudited pro forma combined statements of operations (the “pro forma statements of operations”) for the year ended December 31, 2023, and for the three months ended March 31, 2024, are presented as if the transactions had been completed on January 1, 2023. The amounts related to discontinued operations in Occidental’s Quarterly Report on Form 10-Q for the period ended March 31, 2024 have been excluded from the pro forma statements of operations.
The pro forma financial statements have been prepared from, and should be read in conjunction with, (i) the unaudited consolidated financial statements of Occidental contained in its Quarterly Report on Form 10-Q for the period ended March 31, 2024, (ii) the unaudited condensed consolidated financial statements of CrownRock for the three months ended March 31, 2024 included as Exhibit 99.3 to the Current Report on Form 8-K which these pro forma financial statements are filed with as Exhibit 99.4, (iii) the audited consolidated financial statements of Occidental contained in its Annual Report on Form 10-K for the year ended December 31, 2023 and (iv) the audited consolidated financial statements of CrownRock for the year ended December 31, 2023, included as Exhibit 99.1 to the Current Report on Form 8-K which these pro forma financial statements are filed with as Exhibit 99.4. Certain of CrownRock’s historical amounts have been reclassified to conform to Occidental’s financial statement presentation.
The pro forma financial statements have been prepared to reflect adjustments to Occidental’s historical consolidated financial information that are (i) directly attributable to the acquisition, (ii) factually supportable and (iii) with respect to the pro forma statements of operations only, expected to have a continuing impact on Occidental’s results.
The pro forma financial statements reflect the following pro forma adjustments, based on available information and certain assumptions that Occidental believes are reasonable:
• the acquisition of CrownRock contemplated by the purchase agreement under the acquisition method of accounting;
• the assumption of liabilities for expenses related to the transactions;
• the incurrence by Occidental of $9.7 billion of new indebtedness, consisting of (i) $2.0 billion in term loans with a maturity of 364 days and $2.7 billion in term loans with a maturity of two years borrowed under a term loan agreement with Bank of America, N.A., as administrative agent, and certain financial institutions party thereto, as
1
lenders, and (ii) $5.0 billion in senior unsecured long-term debt issued or incurred in lieu of borrowings pursuant to, and termination of, a 364-day senior unsecured bridge loan facility;
•the redemption of the CrownRock 2025 notes, totaling approximately $868 million, and the obligor exchange of CrownRock’s unsecured senior notes due in 2029, totaling approximately $376 million;
•the issuance of approximately 29.6 million shares of Occidental’s common stock; and
•subject to entry into definitive agreements and consummation of the transactions contemplated thereby, the acquisition of a thirty percent (30%) interest in CrownRock by Ecopetrol for $3.6 billion and the use of proceeds therefrom to pay down a portion of the term loans.
In the event a definitive agreement for the Ecopetrol Transaction is entered into, Occidental expects such transaction to be subject to the satisfaction or waiver of customary closing conditions, including, among other things, the expiration of the waiting period under the Hart-Scott-Rodino Antitrust Improvement Act of 1976, the receipt of approval from the Committee on Foreign Investment in the United States and the closing of the acquisition, which may not be ultimately satisfied or waived. In the event (i) a definitive agreement for the Ecopetrol Transaction is not entered into and the Ecopetrol Option expires or (ii) the Ecopetrol Transaction does not close, the acquisition and the other transactions contemplated in connection therewith will still close, and Occidental will own a one hundred percent (100%) interest in CrownRock.
The pro forma financial statements do not include the realization of cost savings from operating efficiencies, revenue synergies or other integration costs expected to result from the acquisition.
The pro forma financial statements have been prepared using the acquisition method of accounting using the accounting guidance in Accounting Standards Codification 805, Business Combinations (“ASC 805”), with Occidental treated as the acquirer. The acquisition method of accounting is dependent upon certain valuations and other studies that, as of the date of these pro forma financial statements, have yet to commence or progress to a stage where there is sufficient information for a definitive measure. As indicated in the pro forma financial statements and under “—Estimated Purchase Price and Allocation” below, Occidental has performed a preliminary valuation analysis of the fair value of CrownRock’s assets to be acquired and liabilities to be assumed and has made certain adjustments to the historical book values of the assets and liabilities of CrownRock to reflect preliminary estimates of the fair values necessary to prepare the pro forma financial statements. Occidental will perform a detailed review of CrownRock’s accounting policies in connection with the completion of the acquisition. Accordingly, the pro forma financial statements and pro forma adjustments are preliminary and have been made solely for the purpose of preparing the pro forma financial statements. Amounts used in these pro forma financial statements will differ from ultimate amounts once Occidental has closed the acquisition and has completed the valuation studies necessary to finalize the required purchase price allocation and identified any necessary conforming accounting policy changes for CrownRock. Differences between these preliminary estimates and the final acquisition accounting may have a material impact on the pro forma financial statements and the combined company’s future results of operations and financial position.
The pro forma financial statements are provided for illustrative purposes only and do not purport to represent what the actual consolidated results of operations or consolidated financial position of Occidental would have been had the transactions occurred on the dates assumed, nor are they necessarily indicative of future consolidated results of operations or consolidated financial position.
The pro forma financial statements and related notes should be read in conjunction with the separate historical consolidated financial statements and related notes of Occidental included in its Annual Report on Form 10-K for the year ended December 31, 2023 and Quarterly Report on Form 10-Q for the period ended March 31, 2024, and CrownRock included elsewhere as Exhibits 99.1 and 99.3 to the Current Report on Form 8-K which these pro forma financial statements are filed with as Exhibit 99.4.
Estimated Purchase Price and Allocation
The estimated aggregate value of the purchase price is approximately $11.3 billion based on the closing price of Occidental common stock of $63.15 on July 17, 2024, the last practicable trading date prior to the date of these pro forma financial statements. The value of the purchase price will fluctuate based upon changes in the share price of Occidental’s common stock until the date of closing.
2
Estimated Purchase Price
The following table summarizes the cash and common stock components of the estimated purchase price:
| in millions, except per-share amounts | Total | ||||
| Cash portion of estimated purchase price | $ | 9,100 | |||
| Closing Adjustments | |||||
| Net Working Capital and Other Purchase Price Adjustments | 285 | ||||
| Pre-closing dividends declared by Occidental | $ | 7 | |||
| Total Cash Purchase Price | $ | 9,392 | |||
| Estimated total shares of Occidental common stock to be issued | 29.6 | ||||
| Assumed share price of Occidental common stock | $ | 63.15 | |||
| Stock portion of estimated purchase price | $ | 1,867 | |||
| Total estimated purchase price | $ | 11,259 | |||
Occidental anticipates incurring approximately $9.7 billion aggregate principal amount of new indebtedness and using available cash to finance the cash purchase price of the acquisition, redeem the CrownRock 2025 notes and pay related fees and expenses.
Purchase Price Sensitivity
The table below illustrates the potential impact to the total estimated purchase price resulting from a ten percent (10%) increase or decrease in the assumed share price of Occidental's common stock of $63.15. For purposes of this calculation, the stock portion of the estimated purchase price is based on the number of shares of Occidental common stock to be issued as dictated by the purchase agreement.
| in millions | 10% increase in Occidental share price | 10% decrease in Occidental share price | ||||||
| Cash portion of estimated purchase price | $ | 9,392 | $ | 9,392 | ||||
| Stock portion of estimated purchase price | 2,053 | 1,680 | ||||||
| Total estimated purchase price | $ | 11,445 | $ | 11,072 | ||||
From December 8, 2023, the last trading day before the public announcement of Occidental's proposal to acquire CrownRock, to July 17, 2024, the last practicable trading day prior to the date of these pro forma financial statements, the preliminary value of the purchase price to be transferred increased by approximately $197 million, as a result of the increase in the share price of Occidental's common stock from $56.47 to $63.15. Changes in the purchase price would result in a re-evaluation of the preliminary purchase price allocation, particularly the values determined for property, plant and equipment.
Preliminary Purchase Price Allocation
The preliminary allocation of the estimated purchase price to the fair values of assets acquired and liabilities assumed includes pro forma adjustments for the fair value of CrownRock's assets and liabilities. The final allocation will be determined as of the closing of the acquisition once Occidental has determined the final purchase price and completed the necessary detailed valuation analysis and calculations. The final allocation could differ materially from the preliminary allocation used in these pro forma financial statements and related pro forma adjustments.
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Occidental has performed a preliminary valuation analysis of the fair market value of the CrownRock assets to be acquired and liabilities to be assumed and the related allocations to such items of the estimated purchase price. The following table summarizes the allocation of the preliminary estimated purchase price:
| in millions | As of March 31, 2024 | |||||||
| Fair value of assets acquired: | ||||||||
| Cash and cash equivalents | $ | 363 | ||||||
| Trade receivables, net | 250 | |||||||
| Inventories | — | |||||||
| Other current assets | 1 | |||||||
| Property, plant and equipment, net | 12,142 | |||||||
| Operating lease assets | — | |||||||
| Other long-term assets | — | |||||||
| Amount attributable to assets acquired | $ | 12,756 | ||||||
| Fair value of liabilities assumed: | ||||||||
| Current maturities of long-term debt | $ | — | ||||||
| Accounts payable | 2 | |||||||
| Accrued liabilities | 204 | |||||||
| Long-term debt | 1,244 | |||||||
| Asset retirement obligations | 47 | |||||||
| Amount attributable to liabilities assumed | $ | 1,497 | ||||||
| Fair value of net assets acquired: | $ | 11,259 | ||||||
| Goodwill as of March 31, 2024: | $ | — | ||||||
| Total Estimated Purchase Price: | $ | 11,259 | ||||||
Changes in future commodity prices, reserve estimates, other changes in cost assumptions and other facts and circumstances existing on the closing date of the acquisition compared to the date of these pro forma financial statements could result in changes to the fair value of the assets identified above.
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OCCIDENTAL PETROLEUM CORPORATION
UNAUDITED PRO FORMA CONDENSED COMBINED BALANCE SHEET
MARCH 31, 2024
UNAUDITED PRO FORMA CONDENSED COMBINED BALANCE SHEET
MARCH 31, 2024
| Occidental Historical | CrownRock Historical (Adjusted) | Debt Issuance | Acquisition Accounting and Related Transactions | Occidental Combined Pro Forma - 100% CrownRock Ownership | Ecopetrol Transaction | Occidental Combined Pro Forma - 70% CrownRock Ownership | ||||||||||||||||||||||||||
| in millions | ||||||||||||||||||||||||||||||||
| ASSETS | ||||||||||||||||||||||||||||||||
| Current Assets | ||||||||||||||||||||||||||||||||
| Cash and cash equivalents | 1,272 | 363 | 9,646 | (a) | (9,392) | (a) | 945 | 3,630 | (a) | 945 | ||||||||||||||||||||||
| (76) | (a) | (3,630) | (a) | |||||||||||||||||||||||||||||
| (868) | (a) | |||||||||||||||||||||||||||||||
| Trade receivables | 3,271 | 250 | — | — | 3,521 | — | 3,521 | |||||||||||||||||||||||||
| Inventories | 2,131 | — | — | — | 2,131 | — | 2,131 | |||||||||||||||||||||||||
| Other current assets | 1,671 | 1 | — | — | 1,672 | — | 1,672 | |||||||||||||||||||||||||
| Total current assets | 8,345 | 614 | 9,646 | (10,336) | 8,269 | — | 8,269 | |||||||||||||||||||||||||
| Investments in Unconsolidated Entities | 3,400 | — | — | — | 3,400 | — | 3,400 | |||||||||||||||||||||||||
| Property, plant and equipment | ||||||||||||||||||||||||||||||||
| Oil and gas | 110,680 | 7,453 | — | 4,689 | (b) | 122,822 | (3,645) | (j) | 119,177 | |||||||||||||||||||||||
| Chemical | 8,315 | — | — | — | 8,315 | — | 8,315 | |||||||||||||||||||||||||
| Midstream and marketing | 8,487 | — | — | — | 8,487 | — | 8,487 | |||||||||||||||||||||||||
| Corporate | 1,060 | 8 | — | (8) | (f) | 1,060 | — | 1,060 | ||||||||||||||||||||||||
| Gross property, plant and equipment | 128,542 | 7,461 | — | 4,681 | 140,684 | (3,645) | 137,039 | |||||||||||||||||||||||||
| Accumulated depreciation, depletion and amortization | (69,779) | (3,367) | — | 3,367 | (b) | (69,779) | — | (69,779) | ||||||||||||||||||||||||
| Net property, plant, and equipment | 58,763 | 4,094 | — | 8,048 | 70,905 | (3,645) | 67,260 | |||||||||||||||||||||||||
| Operating lease assets | 1,038 | — | — | — | 1,038 | — | 1,038 | |||||||||||||||||||||||||
| Other long-term assets | 2,731 | 9 | — | (9) | (b) | 2,731 | — | 2,731 | ||||||||||||||||||||||||
| TOTAL ASSETS | 74,277 | 4,717 | 9,646 | (2,297) | 86,343 | (3,645) | 82,698 | |||||||||||||||||||||||||
See accompanying notes to unaudited pro forma condensed combined financial statements.
5
OCCIDENTAL PETROLEUM CORPORATION
UNAUDITED PRO FORMA CONDENSED COMBINED BALANCE SHEET
MARCH 31, 2024
UNAUDITED PRO FORMA CONDENSED COMBINED BALANCE SHEET
MARCH 31, 2024
| Occidental Historical | CrownRock Historical (Adjusted) | Debt Issuance | Acquisition Accounting and Related Transactions | Occidental Combined Pro Forma - 100% CrownRock Ownership | Ecopetrol Transaction | Occidental Combined Pro Forma - 70% CrownRock Ownership | ||||||||||||||||||||||||||
| in millions | ||||||||||||||||||||||||||||||||
| LIABILITIES AND EQUITY | ||||||||||||||||||||||||||||||||
| Current Liabilities | ||||||||||||||||||||||||||||||||
| Current maturities of long-term debt | 1,203 | — | 2,000 | (c) | — | 3,203 | (2,000) | (a) | 1,203 | |||||||||||||||||||||||
| Current operating lease liabilities | 424 | — | — | — | 424 | — | 424 | |||||||||||||||||||||||||
| Accounts payable | 3,827 | 2 | — | — | 3,829 | — | 3,829 | |||||||||||||||||||||||||
| Accrued liabilities | 3,358 | 204 | — | — | 3,562 | — | 3,562 | |||||||||||||||||||||||||
| Total current liabilities | 8,812 | 206 | 2,000 | — | 11,018 | (2,000) | 9,018 | |||||||||||||||||||||||||
| Long-term debt, net | 18,545 | 1,238 | 7,646 | (c) | 6 | (b) | 26,567 | (1,630) | (a) | 24,937 | ||||||||||||||||||||||
| (868) | (a) | |||||||||||||||||||||||||||||||
| Deferred credits and other liabilities | ||||||||||||||||||||||||||||||||
| Deferred income taxes, net | 5,728 | — | — | — | 5,728 | — | 5,728 | |||||||||||||||||||||||||
| Asset retirement obligations | 3,867 | 47 | — | — | 3,914 | (15) | (j) | 3,899 | ||||||||||||||||||||||||
| Pension and postretirement obligations | 933 | — | — | — | 933 | — | 933 | |||||||||||||||||||||||||
| Environmental remediation liabilities | 870 | — | — | — | 870 | — | 870 | |||||||||||||||||||||||||
| Operating lease liabilities | 664 | — | — | — | 664 | — | 664 | |||||||||||||||||||||||||
| Other | 3,891 | — | — | — | 3,891 | — | 3,891 | |||||||||||||||||||||||||
| Total deferred credits and other liabilities | 15,953 | 47 | — | — | 16,000 | (15) | 15,985 | |||||||||||||||||||||||||
| Equity | ||||||||||||||||||||||||||||||||
| Preferred stock, at par value | 8,287 | — | — | — | 8,287 | — | 8,287 | |||||||||||||||||||||||||
| Common stock, at par value | 223 | — | — | 6 | (g) | 229 | — | 229 | ||||||||||||||||||||||||
| Treasury stock | (15,582) | — | — | — | (15,582) | — | (15,582) | |||||||||||||||||||||||||
| Additional paid-in capital | 17,456 | 3,226 | — | (1,365) | (g) | 19,317 | — | 19,317 | ||||||||||||||||||||||||
| Retained earnings | 20,147 | — | — | (76) | (a) | 20,071 | — | 20,071 | ||||||||||||||||||||||||
| Accumulated other comprehensive income | 280 | — | — | — | 280 | — | 280 | |||||||||||||||||||||||||
| Total stockholders’ equity | 30,811 | 3,226 | — | (1,435) | 32,602 | — | 32,602 | |||||||||||||||||||||||||
| Non-controlling interest | 156 | — | — | 156 | — | 156 | ||||||||||||||||||||||||||
| Total equity | 30,967 | 3,226 | — | (1,435) | 32,758 | — | 32,758 | |||||||||||||||||||||||||
| TOTAL LIABILITIES AND EQUITY | 74,277 | 4,717 | 9,646 | (2,297) | 86,343 | (3,645) | 82,698 | |||||||||||||||||||||||||
See accompanying notes to unaudited pro forma condensed combined financial statements.
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OCCIDENTAL PETROLEUM CORPORATION
UNAUDITED PRO FORMA STATEMENT OF COMBINED OPERATIONS
THREE MONTHS ENDED MARCH 31, 2024
UNAUDITED PRO FORMA STATEMENT OF COMBINED OPERATIONS
THREE MONTHS ENDED MARCH 31, 2024
| in millions except per-share amounts | Occidental Historical | CrownRock Historical (Adjusted) | Debt Issuance | Acquisition Accounting and Related Transactions | Occidental Combined Pro Forma - 100% CrownRock Ownership | Ecopetrol Transaction (j) | Occidental Combined Pro Forma - 70% CrownRock Ownership | ||||||||||||||||||||||
| Revenues and other income | |||||||||||||||||||||||||||||
| Net sales | 5,975 | 612 | — | — | 6,587 | (184) | 6,403 | ||||||||||||||||||||||
| Interest, dividends and other income | 36 | 3 | — | — | 39 | (1) | 38 | ||||||||||||||||||||||
| Gains (losses) on sales of assets and other, net | (1) | — | — | — | (1) | — | (1) | ||||||||||||||||||||||
| Total | 6,010 | 615 | — | — | 6,625 | (185) | 6,440 | ||||||||||||||||||||||
| Costs and other deductions | |||||||||||||||||||||||||||||
| Oil and gas lease operating expense | 1,161 | 104 | — | — | 1,265 | (31) | 1,234 | ||||||||||||||||||||||
| Transportation and gathering expense | 353 | — | — | — | 353 | — | 353 | ||||||||||||||||||||||
| Chemical and midstream cost of sales | 742 | — | — | — | 742 | — | 742 | ||||||||||||||||||||||
| Purchased commodities | 86 | — | — | — | 86 | — | 86 | ||||||||||||||||||||||
| Selling, general and administrative expenses | 259 | 5 | — | — | 264 | (2) | 262 | ||||||||||||||||||||||
| Other operating and non-operating expense | 410 | — | — | — | 410 | — | 410 | ||||||||||||||||||||||
| Taxes other than on income | 235 | 33 | — | — | 268 | (10) | 258 | ||||||||||||||||||||||
| Depreciation, depletion and amortization | 1,693 | 155 | — | 51 | (d) | 1,899 | (62) | 1,837 | |||||||||||||||||||||
| Acquisition-related costs | 12 | — | — | — | 12 | — | 12 | ||||||||||||||||||||||
| Exploration expense | 66 | — | — | — | 66 | — | 66 | ||||||||||||||||||||||
| Interest and debt expense, net | 284 | 19 | 156 | (c) | (12) | (c) | 447 | (64) | 383 | ||||||||||||||||||||
| Total | 5,301 | 316 | 156 | 39 | 5,812 | (169) | 5,643 | ||||||||||||||||||||||
| Income before income taxes and other items | 709 | 299 | (156) | (39) | 813 | (16) | 797 | ||||||||||||||||||||||
| Other items | |||||||||||||||||||||||||||||
| Income from equity investments and other | 301 | (1) | — | — | 300 | — | 300 | ||||||||||||||||||||||
| Total | 301 | (1) | — | — | 300 | — | 300 | ||||||||||||||||||||||
| Income before income taxes | 1,010 | 298 | (156) | (39) | 1,113 | (16) | 1,097 | ||||||||||||||||||||||
| Income tax expense | (304) | — | 34 | (e) | (57) | (e) | (327) | 4 | (323) | ||||||||||||||||||||
| Income from continuing operations | 706 | 298 | (122) | (96) | 786 | (12) | 774 | ||||||||||||||||||||||
| Less: Preferred stock dividends and redemption premiums | (170) | — | — | — | (170) | — | (170) | ||||||||||||||||||||||
| Income (loss) from continuing operations attributable to Common Stockholders | 536 | 298 | (122) | (96) | 616 | (12) | 604 | ||||||||||||||||||||||
| Net income attributable to common stockholders—basic | $ | 0.60 | $ | 0.67 | $ | 0.66 | |||||||||||||||||||||||
| Net income attributable to common stockholders—diluted | $ | 0.56 | $ | 0.63 | $ | 0.61 | |||||||||||||||||||||||
| Weighted-average number of basic shares | 884.1 | 29.6 | (i) | 913.7 | 913.7 | ||||||||||||||||||||||||
| Diluted weighted-average common shares | 948.6 | 29.6 | (i) | 978.2 | 978.2 | ||||||||||||||||||||||||
See accompanying notes to unaudited pro forma condensed combined financial statements.
7
OCCIDENTAL PETROLEUM CORPORATION
UNAUDITED PRO FORMA STATEMENT OF COMBINED OPERATIONS
YEAR ENDED DECEMBER 31, 2023
UNAUDITED PRO FORMA STATEMENT OF COMBINED OPERATIONS
YEAR ENDED DECEMBER 31, 2023
| in millions except per-share amounts | Occidental Historical | CrownRock Historical (Adjusted) | Debt Issuance | Acquisition Accounting and Related Transactions | Occidental Combined Pro Forma - 100% CrownRock Ownership | Ecopetrol Transaction (j) | Occidental Combined Pro Forma - 70% CrownRock Ownership | ||||||||||||||||||||||
| Revenues and other income | |||||||||||||||||||||||||||||
| Net sales | 28,257 | 2,521 | — | (1) | (f) | 30,777 | (756) | 30,021 | |||||||||||||||||||||
| Interest, dividends and other income | 139 | 5 | — | (1) | (f) | 143 | (1) | 142 | |||||||||||||||||||||
| Gains on sales of assets and other, net | 522 | 2 | — | (24) | (f) | 500 | 7 | 507 | |||||||||||||||||||||
| Total | 28,918 | 2,528 | — | (26) | 31,420 | (750) | 30,670 | ||||||||||||||||||||||
| Costs and other deductions | |||||||||||||||||||||||||||||
| Oil and gas lease operating expense | 4,677 | 386 | — | (2) | (f) | 5,061 | (115) | 4,946 | |||||||||||||||||||||
| Transportation and gathering expense | 1,481 | — | — | — | 1,481 | — | 1,481 | ||||||||||||||||||||||
| Chemical and midstream cost of sales | 3,116 | — | — | — | 3,116 | — | 3,116 | ||||||||||||||||||||||
| Purchased commodities | 2,009 | — | — | — | 2,009 | — | 2,009 | ||||||||||||||||||||||
| Selling, general and administrative expenses | 1,083 | 24 | — | (1) | (f) | 1,106 | (7) | 1,099 | |||||||||||||||||||||
| Other operating and non-operating expense | 1,084 | — | — | — | 1,084 | — | 1,084 | ||||||||||||||||||||||
| Taxes other than on income | 1,087 | 139 | — | — | 1,226 | (42) | 1,184 | ||||||||||||||||||||||
| Depreciation, depletion and amortization | 6,865 | 635 | — | 180 | (d)(f) | 7,680 | (245) | 7,435 | |||||||||||||||||||||
| Asset impairments and other charges | 209 | — | — | — | 209 | — | 209 | ||||||||||||||||||||||
| Acquisition-related costs | 26 | — | — | — | 26 | — | 26 | ||||||||||||||||||||||
| Exploration expense | 441 | 6 | — | (5) | (f) | 442 | — | 442 | |||||||||||||||||||||
| Interest and debt expense, net | 945 | 82 | 617 | (c) | (49) | (c) | 1,595 | (254) | 1,341 | ||||||||||||||||||||
| Total | 23,023 | 1,272 | 617 | 123 | 25,035 | (663) | 24,372 | ||||||||||||||||||||||
| Income before income taxes and other items | 5,895 | 1,256 | (617) | (149) | 6,385 | (87) | 6,298 | ||||||||||||||||||||||
| Other items | |||||||||||||||||||||||||||||
| Income from equity investments and other | 534 | 23 | — | — | 557 | (7) | 550 | ||||||||||||||||||||||
| Total | 534 | 23 | — | — | 557 | (7) | 550 | ||||||||||||||||||||||
| Income from continuing operations before income taxes | 6,429 | 1,279 | (617) | (149) | 6,942 | (94) | 6,848 | ||||||||||||||||||||||
| Income tax expense | (1,733) | — | 136 | (e) | (249) | (e) | (1,846) | 21 | (1,825) | ||||||||||||||||||||
| Income from continuing operations | 4,696 | 1,279 | (481) | (398) | 5,096 | (73) | 5,023 | ||||||||||||||||||||||
| Less: Preferred stock dividends and redemption premiums | (923) | — | — | — | (923) | — | (923) | ||||||||||||||||||||||
| Income (loss) from continuing operations attributable to Common Stockholders | 3,773 | 1,279 | (481) | (398) | 4,173 | (73) | 4,100 | ||||||||||||||||||||||
| Net income attributable to common stockholders—basic | $ | 4.22 | $ | 4.52 | $ | 4.44 | |||||||||||||||||||||||
| Net income attributable to common stockholders—diluted | $ | 3.90 | $ | 4.19 | $ | 4.12 | |||||||||||||||||||||||
| Weighted-average number of basic shares | 889.2 | 29.6 | (i) | 918.8 | 918.8 | ||||||||||||||||||||||||
| Diluted weighted-average common shares | 960.9 | 29.6 | (i) | 990.5 | 990.5 | ||||||||||||||||||||||||
See accompanying notes to unaudited pro forma condensed combined financial statements.
8
NOTES TO PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS
a) Reflects sources of/(uses of) cash upon the completion of the acquisition as follows:
| millions | As of March 31, 2024 | ||||
| Issuance of indebtedness | $ | 9,700 | |||
| Issuance costs | (54) | ||||
| Net cash from issuance of indebtedness | $ | 9,646 | |||
| Cash portion of estimated purchase price | $ | 9,100 | |||
| Net working capital and other purchase price adjustments | 285 | ||||
| Pre-closing dividends declared by Occidental | 7 | ||||
| Total cash purchase price | $ | 9,392 | |||
Acquisition-related transaction costs1 | $ | (76) | |||
| Redemption of CrownRock 2025 notes | $ | (868) | |||
| Estimated net proceeds from Ecopetrol Transaction | $ | 3,630 | |||
| Use of proceeds from Ecopetrol Transaction to pay down term loan- current | $ | (2,000) | |||
| Use of proceeds from Ecopetrol Transaction to pay down term loan- long term | $ | (1,630) | |||
1 Represents an estimate of acquisition-related transaction costs, including fees related to advisory, legal, investment banking and other professional services, all of which are directly attributable to the acquisition. These are non-recurring charges and have been excluded from the unaudited pro forma statements of operations.
b) Reflects the fair value adjustments to CrownRock’s assets and liabilities, including property, plant, and equipment and debt. See "Estimated Purchase Price and Allocation" above.
c) Represents pro forma adjustments to current and long-term debt, which includes the incurrence of $9.7 billion aggregate principal amount of new indebtedness, with an estimated weighted average annual interest rate of 6.25%, yielding net proceeds of $2.0 billion and $7.6 billion in current and long-term debt, respectively. Anticipated proceeds are net of $54 million in debt issuance costs. If the sale of an undivided thirty percent (30%) interest in the CrownRock assets to Ecopetrol is consummated, Occidental anticipates using the proceeds to repay $3.6 billion aggregate principal amount of its term loans. After giving effect to such repayment, the estimated weighted average annual interest rate of the remaining $6.1 billion in new indebtedness is 5.81%. Estimated interest rates are based on underlying U.S. Treasury rates adjusted for Occidental's anticipated credit spreads across a range of maturities.
| in millions, except for interest rates | Principal Amount | Interest Rate (1) | Estimated interest expense for the three months ended March 31, 2024 | Estimated interest expense for the year ended December 31, 2023 | ||||||||||
| Notes | 5,000 | 5.53 | % | $ | 69 | $ | 277 | |||||||
| Term loan (364 day) | 2,000 | 6.94 | % | 35 | 139 | |||||||||
| Term loan (2 year) | 2,700 | 7.07 | % | 48 | 191 | |||||||||
| Total debt assumed issued | $ | 9,700 | 6.25 | % | $ | 152 | $ | 607 | ||||||
| Amortization of term loan debt issuance costs | 2 | 4 | ||||||||||||
| Amortization of notes debt issuance costs | 2 | 6 | ||||||||||||
| Total interest expense | $ | 156 | $ | 617 | ||||||||||
| Debt repayment post Ecopetrol Transaction | (3,630) | (64) | (254) | |||||||||||
| Debt and interest expense post Ecopetrol Transaction | $ | 6,070 | 5.81 | % | $ | 92 | $ | 363 | ||||||
1 The interest rates for the term loans are the July 17, 2024 SOFR of 5.343% plus the applicable margin as specified in the respective debt agreements. The rate for the notes is the pro-forma weighted average interest rate estimated by management.
Occidental has elected to redeem approximately $868 million of the $1.2 billion of assumed debt of CrownRock on or shortly after the closing of the acquisition, which is reflected above in Note (a). The redemption of the CrownRock 2025 notes
9
results in a decrease in CrownRock’s interest expense of $12 million and $49 million for the three months ended March 31, 2024 and the year ended December 31, 2023, respectively.
Prior to completion of the Ecopetrol Transaction, 1/8 of a percent change in the assumed interest rate of the $9.7 billion aggregate principal amount of new indebtedness would increase or decrease the interest expense by $3 million for the three months ended March 31, 2024 and $12 million for the year ended December 31, 2023. If the Ecopetrol Transaction is consummated, a 1/8 of a percent change in the assumed interest rate of the remaining $6.1 billion aggregate principal amount of new indebtedness would increase or decrease the interest expense by $2 million for the three months ended March 31, 2024 and $8 million for the year ended December 31, 2023.
d) Reflects adjustments to historical depreciation, depletion and amortization ("DD&A") expense related to the step up of property, plant and equipment to estimated fair value. Pro forma DD&A expense related to the assets acquired through the acquisition is $51 million for the three months ended March 31, 2024 and $182 million for the year ended December 31, 2023.
e) Reflects the income tax effects of the pro forma adjustments included in the pro forma statements of operations for the three months ended March 31, 2024 and for the year ended December 31, 2023, including an adjustment for income taxes for historical CrownRock that would have been recorded as a result of the acquisition. The effective tax rate of the combined company could be significantly different from what is presented in these pro forma financial statements for a variety of reasons, including post-merger activities.
f) Reflects adjustments to eliminate CrownRock’s historical revenue and expense related to certain subsidiaries retained by CrownQuest Operating, LLC (“CrownQuest”), the parent company of CrownRock, per the purchase agreement. Revenue and expenses related to such subsidiaries totaled $26 million and $10 million, respectively, for the year ended December 31, 2023. These subsidiaries were distributed to CrownQuest as of January 31, 2024. Revenue and expenses related to these subsidiaries for the month of January are immaterial.
g) Reflects elimination of CrownRock Partners’ Capital and issuance of 29.6 million shares of Occidental common stock, totaling $1.9 billion in common stock based on the assumed share price of $63.15:
| in millions | As of March 31, 2024 | ||||
| Estimated stock portion of purchase price: | |||||
| Common stock, $0.20 per share par value, expected to be issued in the acquisition | $ | 6 | |||
Pro forma adjustment to paid-in capital in excess of par value for common stock expected to be issued in the acquisition | 1,861 | ||||
| Estimated stock portion of purchase price | $ | 1,867 | |||
| Acquisition adjustment to paid-in capital in excess of par value for common stock: | |||||
Pro forma adjustment to paid-in capital in excess of par value for common stock expected to be issued in the acquisition | $ | 1,861 | |||
| Elimination of CrownRock Partners’ Capital | (3,226) | ||||
| Acquisition adjustment to paid-in capital in excess of par value for common stock | (1,365) | ||||
10
h) The following reclassifications were made to conform CrownRock's historical financial results to Occidental's presentation on the pro forma financial statements:
Balance Sheet in millions | As of March 31, 2024 | |||||||
| Reclassification from CrownRock Historical | Reclassification to CrownRock Historical (Adjusted) | |||||||
| Assets | ||||||||
| Trade receivables | 249.9 | |||||||
| Other current assets | 1.4 | |||||||
| Property, plant and equipment | ||||||||
| Oil and gas | 7,453.0 | |||||||
| Corporate | 8.0 | |||||||
| Accumulated depreciation, depletion and amortization | (3,367.0) | |||||||
| Other long-term assets | 8.9 | |||||||
| Accounts receivable - related party | ||||||||
| Oil and natural gas | 212.2 | |||||||
| Other | 37.7 | |||||||
| Prepaid costs and other current assets | 1.4 | |||||||
| Oil and natural gas properties, net, successful efforts method of accounting | 3,951.5 | |||||||
| Other property and equipment, net | 142.2 | |||||||
| Deferred loan costs, net | 8.9 | |||||||
| Liabilities | ||||||||
| Accrued liabilities | 203.6 | |||||||
| Accrued drilling cost – related party | 60.4 | |||||||
| Other accrued liabilities – related party | 13.6 | |||||||
| Accrued interest payable | 30.2 | |||||||
| Accrued distribution payable - limited partner | 99.0 | |||||||
| Asset retirement obligations, current portion | 0.4 | |||||||
| Equity | ||||||||
| Additional paid-in capital | 3,225.5 | |||||||
| CrownRock, L.P. Partners' Capital | 3,225.5 | |||||||
| Total | $ | 7,783 | $ | 7,783 | ||||
11
Income Statement in millions | For three months ended March 31, 2024 | For the year ended December 31, 2023 | |||||||||||||||
| Reclassification from CrownRock Historical | Reclassification to CrownRock Historical (Adjusted) | Reclassification from CrownRock Historical | Reclassification to CrownRock Historical (Adjusted) | ||||||||||||||
| Revenues and other income | |||||||||||||||||
| Net sales | 612.3 | 2,520.9 | |||||||||||||||
| Interest, dividends and other income | 2.5 | 4.8 | |||||||||||||||
| Gains on sales of assets and other, net | — | 2.1 | |||||||||||||||
| Oil and natural gas sales | 570.6 | 2,381.9 | |||||||||||||||
| Gain on sales and exchanges of oil and natural gas properties | — | 2.1 | |||||||||||||||
| Saltwater disposal | 20.4 | 66.9 | |||||||||||||||
| Gathering system rent and transportation fees | 13.2 | 47.9 | |||||||||||||||
| Fresh water supply | 7.4 | 20.0 | |||||||||||||||
| Surface ownership | 0.9 | 4.1 | |||||||||||||||
| Interest income | 2.5 | 4.8 | |||||||||||||||
| Costs and other deductions | |||||||||||||||||
| Oil and gas lease operating expense | 103.6 | 385.5 | |||||||||||||||
| Selling, general and administrative expenses | 4.7 | 24.2 | |||||||||||||||
| Taxes other than on income | 32.8 | 138.8 | |||||||||||||||
| Depreciation, depletion and amortization | 0.5 | 2.0 | |||||||||||||||
| Lease operating expense | 103.6 | 385.5 | |||||||||||||||
| Production and ad valorem taxes | 32.8 | 138.8 | |||||||||||||||
| Accretion of discount on asset retirement obligation | 0.5 | 2.0 | |||||||||||||||
| General and administrative | 4.7 | 24.2 | |||||||||||||||
| Other items | |||||||||||||||||
| Income from equity investments and other | (1.4) | 23.2 | |||||||||||||||
| Gain (loss) on derivatives not designated as hedges | — | 0.2 | |||||||||||||||
| Gain on extinguishment of debt | — | 1.5 | |||||||||||||||
| Other income (expense), net | (1.4) | 21.5 | |||||||||||||||
| Total | $ | 755 | $ | 755 | $ | 3,101 | $ | 3,101 | |||||||||
12
i) Reflects the issuance of approximately 29.6 million shares of Occidental common stock to the holders of the CrownRock interests as a portion of the consideration for the acquisition. The following table reconciles historical and pro forma basic and diluted earnings per share utilizing the two-class method for the periods indicated:
| in millions, except per-share amounts | For three months ended March 31, 2024 | For year ended December 31, 2023 | |||||||||||||||||||||
| Occidental Historical | Occidental Combined Pro Forma - 100% CrownRock Ownership | Occidental Combined Pro Forma - 70% CrownRock Ownership | Occidental Historical | Occidental Combined Pro Forma - 100% CrownRock Ownership | Occidental Combined Pro Forma - 70% CrownRock Ownership | ||||||||||||||||||
| Income from continuing operations attributable to common stock | $ | 536 | $ | 616 | 604 | $ | 3,773 | $ | 4,173 | $ | 4,100 | ||||||||||||
| Less: Net income allocated to participating securities | (4) | (4) | (4) | (21) | (21) | (21) | |||||||||||||||||
| Net income, net of participating securities | $ | 532 | $ | 612 | $ | 600 | $ | 3,752 | $ | 4,152 | $ | 4,079 | |||||||||||
| Weighted-average number of basic shares | 884.1 | 913.7 | 913.7 | 889.2 | 918.8 | 918.8 | |||||||||||||||||
| Dilutive securities | 64.5 | 64.5 | 64.5 | 71.7 | 71.7 | 71.7 | |||||||||||||||||
| Diluted weighted average common shares outstanding | 948.6 | 978.2 | 978.2 | 960.9 | 990.5 | 990.5 | |||||||||||||||||
| Basic income per share | $ | 0.60 | $ | 0.67 | $ | 0.66 | $ | 4.22 | $ | 4.52 | $ | 4.44 | |||||||||||
| Diluted income per common share | $ | 0.56 | $ | 0.63 | $ | 0.61 | $ | 3.90 | $ | 4.19 | $ | 4.12 | |||||||||||
j) Reflects the acquisition of an undivided thirty percent (30%) interest in the CrownRock assets by Ecopetrol in connection with the Ecopetrol Transaction based on the preliminary purchase price allocation:
Balance Sheet in millions | As of March 31, 2024 | ||||
| Property, plant and equipment, Oil and gas | $ | 3,645 | |||
| Assets | 3,645 | ||||
| Asset retirement obligations | 15 | ||||
| Liabilities | 15 | ||||
| Net | $ | 3,630 | |||
13
The following table includes the elimination of revenue and expenses for the three months ended March 31, 2024 and year ended December 31, 2023 related to the acquisition of an undivided thirty percent (30%) interest in the CrownRock assets by Ecopetrol in connection with the Ecopetrol Transaction:
Income Statement in millions | Three months ended March 31, 2024 | Year ended December 31, 2023 | ||||||
| Revenues and other income | ||||||||
| Net sales | 184 | 756 | ||||||
| Interest, dividends and other income | 1 | 1 | ||||||
| Gains on sales of assets and other, net | — | (7) | ||||||
| 185 | 750 | |||||||
| Costs and other deductions | ||||||||
| Oil and gas lease operating expense | 31 | 115 | ||||||
| Selling, general and administrative expenses | 2 | 7 | ||||||
| Taxes other than on income | 10 | 42 | ||||||
| Depreciation, depletion and amortization | 62 | 245 | ||||||
| Interest and debt expense, net | 64 | 254 | ||||||
| 169 | 663 | |||||||
| Income before income taxes and other items | 16 | 87 | ||||||
| Income from equity investments and other | — | 7 | ||||||
| Income tax expense | (4) | (21) | ||||||
| Total effect to net income | 12 | 73 | ||||||
14
Supplemental Pro Forma Crude Oil, Natural Gas Liquids ("NGLs") and Natural Gas Reserves Information
The following tables present the estimated pro forma combined net proved developed and undeveloped crude oil, NGLs and natural gas reserves as of December 31, 2023, along with a summary of changes in quantities of net remaining proved reserves during the year ended December 31, 2023.
The following estimated pro forma reserve information is not necessarily indicative of the results that might have occurred had the transactions been completed on January 1, 2023 and is not intended to be a projection of future results. Future results may vary significantly from the results reflected because of various factors, including those discussed in the section entitled "Risk Factors" in Occidental’s Annual Report on Form 10-K for the year ended December 31, 2023.
The pro forma adjustments below reflect the acquisition of an undivided thirty percent (30%) interest in the CrownRock assets by Ecopetrol in connection with the Ecopetrol Transaction.
| Oil Reserves | Occidental Historical | CrownRock Historical | Occidental Combined Pro Forma - 100% CrownRock Ownership | Ecopetrol Transaction | Occidental Combined Pro Forma - 70% CrownRock Ownership | ||||||||||||
| in millions of barrels (MMbbl) | |||||||||||||||||
| PROVED DEVELOPED AND UNDEVELOPED RESERVES | |||||||||||||||||
| Balance at December 31, 2022 | 1,913 | 249 | 2,162 | (75) | 2,087 | ||||||||||||
| Revisions of previous estimates | 168 | (14) | 154 | 4 | 158 | ||||||||||||
| Improved recovery | 18 | — | 18 | — | 18 | ||||||||||||
| Extensions and discoveries | 62 | 64 | 126 | (19) | 107 | ||||||||||||
| Purchases of proved reserves | 14 | — | 14 | — | 14 | ||||||||||||
| Sales of proved reserves | (1) | — | (1) | — | (1) | ||||||||||||
| Production | (234) | (27) | (261) | 8 | (253) | ||||||||||||
| Balance at December 31, 2023 | 1,940 | 272 | 2,212 | (82) | 2,130 | ||||||||||||
| DOMESTIC PROVED RESERVES | 1,600 | 272 | 1,872 | (82) | 1,790 | ||||||||||||
| INTERNATIONAL PROVED RESERVES | 340 | — | 340 | — | 340 | ||||||||||||
| PROVED DEVELOPED RESERVES | |||||||||||||||||
| December 31, 2023 | 1,398 | 122 | 1,520 | (37) | 1,483 | ||||||||||||
| PROVED UNDEVELOPED RESERVES | |||||||||||||||||
| December 31, 2023 | 542 | 150 | 692 | (45) | 647 | ||||||||||||
NGL Reserves | Occidental Historical | CrownRock Historical | Occidental Combined Pro Forma - 100% CrownRock Ownership | Ecopetrol Transaction | Occidental Combined Pro Forma - 70% CrownRock Ownership | ||||||||||||
| in millions of barrels (MMbbl) | |||||||||||||||||
| PROVED DEVELOPED AND UNDEVELOPED RESERVES | |||||||||||||||||
| Balance at December 31, 2022 | 846 | 181 | 1,027 | (54) | 973 | ||||||||||||
| Revisions of previous estimates | 185 | 9 | 194 | (3) | 191 | ||||||||||||
| Improved recovery | 2 | — | 2 | — | 2 | ||||||||||||
| Extensions and discoveries | 45 | 41 | 86 | (12) | 74 | ||||||||||||
| Purchases of proved reserves | 9 | — | 9 | — | 9 | ||||||||||||
| Sales of proved reserves | (1) | — | (1) | — | (1) | ||||||||||||
| Production | (103) | (15) | (118) | 4 | (114) | ||||||||||||
| Balance at December 31, 2023 | 983 | 216 | 1,199 | (65) | 1,134 | ||||||||||||
| DOMESTIC PROVED RESERVES | 802 | 216 | 1,018 | (65) | 953 | ||||||||||||
| INTERNATIONAL PROVED RESERVES | 181 | — | 181 | — | 181 | ||||||||||||
| PROVED DEVELOPED RESERVES | |||||||||||||||||
| December 31, 2023 | 639 | 112 | 751 | (34) | 717 | ||||||||||||
| PROVED UNDEVELOPED RESERVES | |||||||||||||||||
| December 31, 2023 | 344 | 104 | 448 | (31) | 417 | ||||||||||||
15
Natural Gas Reserves in billions of cubic feet (Bcf) PROVED DEVELOPED AND UNDEVELOPED RESERVES | Occidental Historical | CrownRock Historical | Occidental Combined Pro Forma - 100% CrownRock Ownership | Ecopetrol Transaction | Occidental Combined Pro Forma - 70% CrownRock Ownership | ||||||||||||
| Balance at December 31, 2022 | 6,350 | 865 | 7,215 | (259) | 6,956 | ||||||||||||
| Revisions of previous estimates | 319 | 80 | 399 | (24) | 375 | ||||||||||||
| Improved recovery | 18 | — | 18 | — | 18 | ||||||||||||
| Extensions and discoveries | 273 | 203 | 476 | (61) | 415 | ||||||||||||
| Purchases of proved reserves | 50 | — | 50 | — | 50 | ||||||||||||
| Sales of proved reserves | (2) | — | (2) | — | (2) | ||||||||||||
| Production | (656) | (73) | (729) | 22 | (707) | ||||||||||||
| Balance at December 31, 2023 | 6,352 | 1,075 | 7,427 | (322) | 7,105 | ||||||||||||
| DOMESTIC PROVED RESERVES | 4,235 | 1,075 | 5,310 | (322) | 4,988 | ||||||||||||
| INTERNATIONAL PROVED RESERVES | 2,117 | — | 2,117 | — | 2,117 | ||||||||||||
| PROVED DEVELOPED RESERVES | |||||||||||||||||
| December 31, 2023 | 4,277 | 558 | 4,835 | (167) | 4,668 | ||||||||||||
| PROVED UNDEVELOPED RESERVES | |||||||||||||||||
| December 31, 2023 | 2,075 | 517 | 2,592 | (155) | 2,437 | ||||||||||||
Total Reserves | Occidental Historical | CrownRock Historical | Occidental Combined Pro Forma - 100% CrownRock Ownership | Ecopetrol Transaction | Occidental Combined Pro Forma - 70% CrownRock Ownership | ||||||||||||
| in millions of BOE (MMBOE) | |||||||||||||||||
| PROVED DEVELOPED AND UNDEVELOPED RESERVES | |||||||||||||||||
| Balance at December 31, 2022 | 3,817 | 574 | 4,391 | (172) | 4,219 | ||||||||||||
| Revisions of previous estimates | 406 | 8 | 414 | (2) | 412 | ||||||||||||
| Improved recovery | 23 | — | 23 | — | 23 | ||||||||||||
| Extensions and discoveries | 153 | 138 | 291 | (41) | 250 | ||||||||||||
| Purchases of proved reserves | 31 | — | 31 | — | 31 | ||||||||||||
| Sales of proved reserves | (2) | — | (2) | — | (2) | ||||||||||||
| Production | (446) | (54) | (500) | 16 | (484) | ||||||||||||
| Balance at December 31, 2023 | 3,982 | 666 | 4,648 | (199) | 4,449 | ||||||||||||
| DOMESTIC PROVED RESERVES | 3,108 | 666 | 3,774 | (199) | 3,575 | ||||||||||||
| INTERNATIONAL PROVED RESERVES | 874 | — | 874 | — | 874 | ||||||||||||
| PROVED DEVELOPED RESERVES | |||||||||||||||||
| December 31, 2023 | 2,750 | 326 | 3,076 | (98) | 2,978 | ||||||||||||
| PROVED UNDEVELOPED RESERVES | |||||||||||||||||
| December 31, 2023 | 1,232 | 340 | 1,572 | (101) | 1,471 | ||||||||||||
16
Standardized measure of discounted future net cash flows
The following tables present the estimated pro forma discounted future net cash flows at December 31, 2023. The pro forma standardized measure information set forth below gives effect to the transactions as if the transactions had been completed on January 1, 2023. The disclosures below were determined by referencing the "Standardized Measure of Discounted Future Net Cash Flows" reported in Occidental's Annual Report on Form 10-K for the year ended December 31, 2023 and in the consolidated financial statements and related notes of CrownRock for the year ended December 31, 2023. An explanation of the underlying methodology applied, as required by U.S. Securities and Exchange Commission regulations, can be found within Occidental’s Annual Report on Form 10-K for the year ended December 31, 2023 and CrownRock’s consolidated financial statements and related notes for the year ended December 31, 2023. The calculations assume the continuation of existing economic, operating and contractual conditions at December 31, 2023.
Therefore, the following estimated pro forma standardized measure is not necessarily indicative of the results that might have occurred had the transactions been completed on January 1, 2023 and is not intended to be a projection of future results. Future results may vary significantly from the results reflected because of various factors, including those discussed in the section entitled "Risk Factors" in Occidental’s Annual Report on Form 10-K for the year ended December 31, 2023.
The pro forma adjustments below reflect the acquisition of an undivided thirty percent (30%) interest in the CrownRock assets by Ecopetrol in connection with the Ecopetrol Transaction.
| in millions | Occidental Historical | CrownRock Historical | Occidental Combined Pro Forma - 100% CrownRock Ownership | Ecopetrol Transaction | Occidental Combined Pro Forma - 70% CrownRock Ownership | ||||||||||||
| AS OF DECEMBER 31, 2023 | |||||||||||||||||
| Future cash inflows | $ | 178,491 | $ | 25,759 | $ | 204,250 | $ | (7,728) | $ | 196,522 | |||||||
| Future costs | |||||||||||||||||
| Production costs and other operating expenses | (69,785) | (7,646) | (77,431) | 2,294 | (75,137) | ||||||||||||
| Development costs | (23,110) | (3,349) | (26,459) | 1,005 | (25,454) | ||||||||||||
| Future income tax expense | (15,336) | — | (15,336) | — | (15,336) | ||||||||||||
| Future net cash flows | $ | 70,260 | $ | 14,764 | $ | 85,024 | $ | (4,429) | $ | 80,595 | |||||||
| Ten percent discount factor | (29,958) | (6,390) | (36,348) | 1,917 | (34,431) | ||||||||||||
| Standardized measure of discounted future net cash flows | $ | 40,302 | $ | 8,374 | $ | 48,676 | $ | (2,512) | $ | 46,164 | |||||||
Changes in the standardized measure of discounted future net cash flows from proved reserve quantities
The changes in the pro forma standardized measure of discounted future net cash flows relating to proved crude oil, NGLs and natural gas reserves for the year ended December 31, 2023 are as follows:
| in millions | Occidental Historical | CrownRock Historical | Occidental Combined Pro Forma - 100% CrownRock Ownership | Ecopetrol Transaction | Occidental Combined Pro Forma - 70% CrownRock Ownership | ||||||||||||
| Beginning of year | $ | 58,152 | $ | 12,263 | $ | 70,415 | $ | (3,679) | $ | 66,736 | |||||||
Sales and transfers of oil and gas produced, net of production costs and other operating expenses | (14,318) | (1,858) | (16,176) | 557 | (15,619) | ||||||||||||
Net change in prices received per barrel, net of production costs and other operating expenses | (23,774) | (4,255) | (28,029) | 1,278 | (26,751) | ||||||||||||
Extensions, discoveries and improved recovery, net of future production and development costs | 2,910 | 1,553 | 4,463 | (466) | 3,997 | ||||||||||||
| Change in estimated future development costs | (3,430) | 965 | (2,465) | (290) | (2,755) | ||||||||||||
| Revisions of quantity estimates | 6,313 | (589) | 5,724 | 177 | 5,901 | ||||||||||||
| Previously estimated development costs incurred during the period | 2,584 | — | 2,584 | — | 2,584 | ||||||||||||
| Accretion of discount | 6,152 | 1,226 | 7,378 | (368) | 7,010 | ||||||||||||
| Net change in income taxes | 5,575 | — | 5,575 | — | 5,575 | ||||||||||||
| Purchases and sales of reserves in place, net | 404 | (4) | 400 | 1 | 401 | ||||||||||||
| Changes in production rates and other | (266) | (927) | (1,193) | 278 | (915) | ||||||||||||
| Net change | (17,850) | (3,889) | (21,739) | 1,167 | (20,572) | ||||||||||||
| End of year | $ | 40,302 | $ | 8,374 | $ | 48,676 | $ | (2,512) | $ | 46,164 | |||||||
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