Occidental Petroleum 8K Consolidated Financial Statements | OXY 19 Jul 24

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

Independent Auditor’s Report

To the Partners
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.

•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

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.

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.

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.

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.

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.

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.

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.

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.

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.

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.

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).

B. Summary of Significant Accounting Policies (Continued)
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.

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

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.

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.

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.

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

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.

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.

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

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.

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.

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.

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.

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.

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.

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

Occidental Petroleum (OXY) 8-KConsolidated Financial Statements