PROP Prairie Operating Company

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 8-K

 

CURRENT REPORT

Pursuant to Section 13 or 15(d)

of the Securities Exchange Act of 1934

 

Date of Report (Date of earliest event reported): March 24, 2025

 

Prairie Operating Co.

(Exact name of registrant as specified in its charter)

 

Delaware		001-41895		98-0357690
(State or other jurisdiction of incorporation)		(Commission File Number)		(IRS Employer Identification No.)

 

55 Waugh Drive
Suite 400
Houston, TX		77007
(Address of principal executive offices)		(Zip Code)

 

(713) 424-4247

(Registrant’s telephone number, including area code)

 

Not Applicable

(Former name or former address, if changed since last report)

 

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

 

☐	Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
☐	Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
☐	Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
☐	Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

 

Securities registered pursuant to Section 12(b) of the Act:

 

Title of each class		Trading Symbol(s)		Name of each exchange on which registered
Common Stock, par value $0.01 per share		PROP		The Nasdaq Stock Market LLC

 

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter).

 

Emerging growth company ☐

 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

 

 

 

Item 8.01 Other Events.

 

As previously disclosed in the Current Report on Form 8-K of Prairie Operating Co. (the “Company”) filed with the Securities and Exchange Commission (the “SEC”) on February 7, 2025, the Company and certain of its subsidiaries entered into a Purchase and Sale Agreement to purchase certain oil gas properties (the “Acquired Properties”) from Bayswater Resources, LLC, Bayswater Fund III-A, LLC, Bayswater Fund III-B, LLC, Bayswater Fund IV-A, LP, Bayswater Fund IV-B, LP, Bayswater Fund IV-Annex, LP, and Bayswater Exploration & Production, LLC (collectively, “Bayswater”).

 

The Company is also filing:

 

	●	the audited combined statement of revenue and direct operating expenses of the Acquired Properties for the years ended December 31, 2024 and 2023, as set forth in Exhibit 99.2, which is incorporated herein by reference;
	●	its management’s discussion and analysis of results of operations of the Acquired Properties, as set forth in Exhibit 99.3, which is incorporated herein by reference;
	●	the unaudited pro forma condensed combined financial information of the Company as of and for the year ended December 31, 2024, as set forth in Exhibit 99.4, which is incorporated herein by reference; and
	●	the report of Cawley, Gillespie & Associates, Inc., independent petroleum engineers, relating to the pro forma estimated reserves of the Company as of December 31, 2024, as set forth in Exhibit 99.5, which is incorporated herein by reference.

 

Item 9.01 Financial Statements and Exhibits.

 

(a) Financial Statements of Business Acquired.

 

The audited combined statement of revenue and direct operating expenses of the Acquired Properties for the years ended December 31, 2024 and 2023 is attached hereto as Exhibit 99.2 and is incorporated herein by reference.

 

(b) Pro Forma Financial Information.

 

The unaudited pro forma condensed combined financial information of the Company as of and for the year ended December 31, 2024 is attached hereto as Exhibit 99.4 and is incorporated herein by reference. The pro forma financial statements being filed in this Current Report on Form 8-K supersede the pro forma financial statements that were filed in the Company’s Current Report on Form 8-K filed with the SEC on February 7, 2025.

 

(d) Exhibits

 

Exhibit Number		Description
23.1		Consent of Plante & Moran, PLLC, dated March 24, 2025.
23.2		Consent of Cawley, Gillespie & Associates, Inc., dated March 24, 2025.
99.2		Audited Combined Statement of Revenue and Direct Operating Expenses of the Acquired Properties for the Years Ended December 31, 2024 and 2023.
99.3		Management’s Discussion and Analysis of Results of Operations of the Acquired Properties.
99.4		Unaudited Pro Forma Condensed Combined Financial Information of the Company as of and for the Year Ended December 31, 2024.
99.5		Report of Cawley, Gillespie & Associates, Inc. Relating to the Estimated Pro Forma Reserves of the Company as of December 31, 2024.
104		Cover Page Interactive Date File-formatted as Inline XBRL.

 

 

SIGNATURES

 

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

 

	PRAIRIE OPERATING CO.
	By:	/s/ Craig Owen
	Name:	Craig Owen
	Title:	Chief Financial Officer

 

Date: March 24, 2025

 

 

 

Exhibit 23.1

 

 

CONSENT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANT

 

We consent to the incorporation by reference in Prairie Operating Co.’s (“Prairie”) Registration Statement No. 333-282730 on Form S-3 of our independent auditor’s report dated March 7, 2025 related to the combined statement of revenues and direct operating expenses (the “combined financial statement”) of certain oil and natural gas properties of Bayswater Resources, LLC, Bayswater Fund III-A, LLC, Bayswater Fund III-B, LLC, Bayswater Fund IV-A, LP, Bayswater Fund IV-B, LP, and Bayswater Fund IV-Annex, LP for the years ended December 31, 2024 and 2023 and the related notes to the combined financial statement appearing in this Current Report on Form 8-K of Prairie, and to the reference to our Firm under the caption “Experts” in the Prospectus.

 

Denver, Colorado	/s/ Plante & Moran, PLLC
March 24, 2025

 

 

 

Exhibit 23.2

 

 

CONSENT OF INDEPENDENT PETROLEUM RESERVE EXPERTS

 

As independent petroleum engineers, we hereby consent to the reference to our firm, in the context in which they appear, and to the references to, and to the inclusion of, our reserve report, dated March 17, 2025, with respect to the estimates of pro forma reserves of Prairie Operating Co. (the “Company”) as of December 31, 2024, included in or made part of this Current Report on Form 8-K of the Company, and to the incorporation by reference of such report in the Registration Statement on Form S-3 (No. 333-282730), including any amendments thereto (the “Registration Statement”), and the related Prospectus of the Company, filed with the U.S. Securities and Exchange Commission. We also hereby consent to the references to our firm contained in the Registration Statement, including under the caption “Experts” in the Prospectus.

 

	CAWLEY, GILLESPIE & ASSOCIATES, INC.
	Texas Registered Engineering Firm F-693

 

	By:	/s/ W. Todd Brooker
		W. Todd Brooker, P.E.
		President

 

Austin, Texas

March 24, 2025

 

 

 

 

Exhibit 99.2

 

Acquired Properties

Combined Statement of Revenue and Direct Operating Expenses

For the Years Ended December 31, 2024 and 2023

 

 

Table of Contents

 

	Page
Independent Auditor’s Report	1
Financial Statements
Combined Statement of Revenues and Direct Operating Expenses	3
Notes to Combined Statement of Revenues and Direct Operating Expenses	4
Supplemental Oil and Gas Information (Unaudited)	8

 

 

 

Independent Auditor’s Report

 

To the Members and Partners

Bayswater Resources, LLC

Bayswater Fund III-A, LLC

Bayswater Fund III-B, LLC

Bayswater Fund IV-A, LP

Bayswater Fund IV-B, LP

Bayswater Fund IV-Annex, LP

 

Opinion

 

We have audited the combined statement of revenues and direct operating expenses (the “combined financial statement”) of certain oil and natural gas properties of Bayswater Resources, LLC; Bayswater Fund III-A, LLC; Bayswater Fund III-B, LLC; Bayswater Fund IV-A, LP; Bayswater Fund IV-B, LP; and Bayswater Fund IV-Annex, LP (collectively, Bayswater) for the years ended December 31, 2024 and 2023 and the related notes to the combined financial statement.

 

In our opinion, the accompanying combined financial statement presents fairly, in all material respects, the revenues and direct operating expenses of certain oil and natural gas properties of Bayswater for the years ended December 31, 2024 and 2023 in accordance with accounting principles generally accepted in the United States of America.

 

Basis for Opinion

 

We conducted our audits 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 Audits of the Combined Financial Statement section of our report. We are required to be independent of Bayswater and to meet our 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 Note 1 to the combined financial statement, the combined statement of revenues and direct operating expenses was prepared for the purpose of presenting solely the revenues and direct operating expenses derived from certain oil and natural gas interests owned by Bayswater and is not intended to be a complete presentation of Bayswater’s assets, liabilities, revenues, or expenses. Our opinion is not modified with respect to this matter.

 

Responsibilities of Management for the Combined Financial Statement

 

Management is responsible for the preparation and fair presentation of the combined financial statement 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 combined financial statement that is free from material misstatement, whether due to fraud or error.

 

In preparing the combined financial statement, management is required to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the certain oil and natural gas properties of Bayswater’s ability to continue as a going concern within one year after the date that the combined financial statement is issued or available to be issued.

 

Auditor’s Responsibilities for the Audits of the Combined Financial Statement

 

Our objectives are to obtain reasonable assurance about whether the combined financial statement as a whole is 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 combined financial statement.

 

 

 

To the Members and Partners

Bayswater Resources, LLC

Bayswater Fund III-A, LLC

Bayswater Fund III-B, LLC

Bayswater Fund IV-A, LP

Bayswater Fund IV-B, LP

Bayswater Fund IV-Annex, LP

 

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 combined financial statement, 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 combined financial statement.
●	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 Bayswater’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 combined financial statement.
●	Conclude whether, in our judgment, there are conditions or events, considered in the aggregate, that raise substantial doubt about the certain oil and natural gas properties of Bayswater’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 audits.

 

Required Supplementary Information

 

Accounting principles generally accepted in the United States of America require that supplementary information relating to oil and gas producing activities contained within Note 7 be presented to supplement the basic combined financial statement. Such information is the responsibility of management and, although not a part of the basic combined financial statement, is required by the United States Financial Accounting Standards Board, which, as described by Accounting Standards Codification 932-235-50, considers it to be an essential part of financial reporting for placing the basic combined financial statement in an appropriate operational, economic, or historical context. We have applied certain limited procedures to the required supplementary information in accordance with auditing standards generally accepted in the United States of America, which consisted of inquiries of management about the methods of preparing the information and comparing the information for consistency with management’s responses to our inquiries, the basic combined financial statement, and other knowledge we obtained during our audit of the basic combined financial statement. We do not express an opinion or provide any assurance on the information because the limited procedures do not provide us with sufficient evidence to express an opinion or provide any assurance.

 

/s/ Plante & Moran, PLLC

 

March 7, 2025

 

 

Acquired Properties

Combined Statement of Revenues and Direct Operating Expenses

For the Years Ended December 31, 2024 and 2023

 

		December 31, 2024				December 31, 2023
Revenues
Oil sales, net of deductions		$	391,062,469			$	415,000,112
Natural gas and liquids sales, net of deductions			52,789,878				51,831,604
Total revenues			443,852,347				466,831,716
Direct operating expenses
Lease operating expenses			35,899,238				39,898,053
Production and property taxes			33,139,836				31,325,533
Oil gathering expenses			10,167,374				8,542,616
Workover expenses			2,706,483				3,278,240
Lease operating expenses, related party			3,315,395				2,687,187
Total direct operating expenses			85,228,326				85,731,629
Revenues in excess of direct operating expenses		$	358,624,021			$	381,100,087

 

See accompanying notes to the Combined Statement of Revenues and Direct Operating Expenses

 

 

Acquired Properties

Notes to the Combined Statement of Revenues and Direct Operating Expenses

 

Note 1 – Basis of Presentation

 

On February 6, 2025, Prairie Operating Co. (“Prairie”) entered into a Purchase and Sale Agreement (the “Agreement”) to acquire certain oil and natural gas properties owned by Bayswater Resources, LLC, Bayswater Fund III-A, LLC, Bayswater Fund III-B, LLC, Bayswater Fund IV-A, LP, Bayswater Fund IV-B, LP, and Bayswater Fund IV-Annex, LP (collectively the “Sellers”) which include properties operated by an affiliated entity of the Sellers (together with the Sellers, “Bayswater”), non-operated properties, related proved reserves, and associated well equipment and infrastructure in Weld County, Colorado (the “Acquired Properties”), for an agreed to purchase price of $603 million, subject to typical adjustments including those associated with net cash flows between the effective date of December 1, 2024 and the closing date. The transaction is subject to customary closing considerations and has not yet closed.

 

The Bayswater entities are under common-control and thus the collective results of the Sellers, inclusive of the incremental working interests described above, have been combined in the accompanying Combined Statement of Revenues and Direct Operating Expenses. Upon combination, all intercompany accounts and transactions are eliminated.

 

The accompanying Combined Statement of Revenue and Direct Operating Expenses’ purpose is to present activity solely related to the revenues and direct operating expenses of the oil and natural gas interests of the Acquired Properties. It is not intended to be a complete presentation of the results of operations of the Acquired Properties and may not be representative of future operations as it does not include general and administrative expenses, interest income or expense, depreciation, depletion and amortization, income taxes or other income and expense items not directly associated with revenues from oil and gas.

 

Note 2 - Summary of Significant Accounting Policies

 

Use of Estimates

 

The preparation of the Combined Statement of Revenue and Direct Operating Expenses in conformity with GAAP required Bayswater’s management to make various assumptions, judgements and estimates to determine the reported amounts of revenues and direct operating expenses of the Acquired Properties for the periods reported. These estimates and assumptions are based on Bayswater’s best estimates and judgements. Changes in these assumptions, judgements and estimates will occur due to the passage of time and occurrence of future events. Accordingly, actual results could differ materially from amounts previously established.

 

 

Acquired Properties

Notes to the Combined Statement of Revenues and Direct Operating Expenses

 

Note 2 – Summary of Significant Accounting Policies (continued)

 

Revenue Recognition

 

Oil and natural gas revenues from production on the Acquired Properties in which Bayswater shares an economic interest with other owners are recognized on the basis of Bayswater’s pro-rata interest and are recognized in the month production is delivered to the purchaser, at which point Bayswater’s performance obligations under its commodity sales contracts are satisfied and control of the commodity is transferred to the purchaser. For commodity sales contracts related to production from oil and gas properties operated by Bayswater, fees included in the contract that are incurred prior to control transfer are classified as oil gathering expenses on the Combined Statement of Revenues and Direct Operating Expenses and fees incurred after control transfers are included as a reduction to the transaction price and are netted within oil and gas sales on the Combined Statement of Revenues and Direct Operating Expenses. For commodity sales contracts related to production from non-operated oil and gas properties, all fees are included as a reduction to the transaction price and are netted within oil and gas sales on the Combined Statement of Revenues and Direct Operating Expenses. Provided that reasonable estimates can be made, revenue and receivables are accrued to recognize delivery of product to the purchaser in the month the performance obligation is satisfied. Differences between estimates and actual volumes and prices, if any, are adjusted upon final settlement.

 

Direct Operating Expenses

 

Direct operating expenses are recognized when incurred and include amounts required to operate the wells to produce, gather, transport, process and treat oil and natural gas. Direct operating expenses also include production and property taxes and expenses with support personnel, support services, equipment and facilities related to oil and natural gas production.

 

Concentrations of Credit Risk

 

There were no joint interest operators that accounted for 10% or more of the Acquired Properties’ total revenue in any of the periods presented. One purchaser accounted for 76% and 58% of the Acquired Properties’ total revenue for the years ended December 31, 2024 and 2023, respectively.

 

 

Acquired Properties

Notes to the Combined Statement of Revenues and Direct Operating Expenses

 

Note 3 – Related Party Transactions

 

The majority of the Acquired Properties are operated by an entity under common-control with the Sellers (the “Operator”). For these properties, the Operator assesses certain overhead charges to, among other things, operate producing oil and gas wells and to drill and complete new oil and gas wells. The amount and frequency of these charges are based on industry-standard agreements used between third party joint-owners of oil and gas properties. During the years ended December 31, 2024 and 2023, the Operator billed $3,315,395 and $2,687,187, respectively, in producing overhead fees to the Acquired Properties. The producing overhead is presented in lease operating expenses, related party on the Combined Statement of Revenues and Direct Operating Expenses.

 

Note 4 – Commitments and Contingencies

 

The activities of the Acquired Properties are subject to potential claims and litigation in the normal course of operations. Pursuant to the terms of the Agreement between Bayswater and Prairie, certain liabilities arising in connection with ownership of the Acquired Properties prior to the effective date are to be retained by Bayswater.

 

Management is not aware of any pending or threatened legal, environmental remediation or other commitments or contingencies that would have a material effect on the Acquired Properties, other than customary plugging and abandonment obligations associated with the Acquired Properties.

 

Gas Processing Agreement

 

The Acquired Properties are subject to a Natural Gas Gathering and Processing Agreement (the “Gas Agreement”) with a gas processing company (the “Gas Processing Company”), under which all natural gas produced from certain Weld County leases within certain drill spacing units under the Acquired Properties will be gathered and purchased by the Gas Processing Company. The Gas Agreement provides for payments based on volumes gathered and processed, as well as a guaranteed monthly payment of $98,778 intended to reimburse costs incurred by the Gas Processing Company in order to connect the gathering facility to the covered leases and drill spacing units. Per the Gas Agreement, guaranteed monthly payments commenced on the date of initial deliveries of natural gas, which was October 2019, and continue over 120 months.

 

Additionally, the Gas Agreement, as amended, allocates a portion of the Gas Processing Company’s firm commitments to transport natural gas liquids processed by the Gas Processing Company to the Acquired Properties beginning in July 2022 and continuing through October 2029. The commitments cover 3.6 million barrels of natural gas liquids over this period and, beginning in January 2023, are subject to monthly shortfall fees of $4.83 per barrel for any under-delivered volumes, subject to annual consumer price index-based escalations. As of December 31, 2024, the remaining commitments cover 1.6 million barrels of natural gas liquids. No shortfall payments have been required to date and none are expected to be made based on estimated NGL production forecasts.

 

 

Acquired Properties

Notes to the Combined Statement of Revenues and Direct Operating Expenses

 

Note 4 – Commitments and Contingencies (continued)

 

Gas Processing Agreement (continued)

 

The estimated future commitment for the Acquired Properties under the Gas Agreement as of December 31, 2024 is presented in the table below:

 

		Guaranteed Monthly Payment				Maximum Shortfall Fee				Maximum Commitment
2025		$	927,516			$	1,970,676			$	2,898,192
2026			927,516				1,608,528				2,536,044
2027			927,516				1,282,456				2,209,972
2028			927,516				895,490				1,823,006
2029			695,637				278,045				973,682
Total		$	4,405,701			$	6,035,195			$	10,440,896

 

Oil Purchase Agreement

 

The Acquired Properties are also subject to a Crude Oil Purchase and Sale Agreement (the “Oil Agreement”) with an oil pipeline company (the “Oil Pipeline Company”), under which all oil produced from certain Weld County leases within certain drill spacing units under the Acquired Properties will be gathered and purchased by the Oil Pipeline Company. Additionally, the Oil Agreement, as amended in 2023, requires a minimum volume of 15.85 million barrels of oil from the Acquired Properties to be delivered each year beginning in 2023 and continuing through 2026. As of December 31, 2024, 6.8 million barrels of oil remained to be delivered. All oil delivered to the Oil Pipeline Company from the Acquired Properties under the Oil Agreement will be subject to a gathering fee of $1.68 - $1.91 per barrel, and under-delivered volumes will incur a fee of $1.73 - $1.91, subject to annual consumer price index-based escalations. During the year ended December 31, 2024, the Acquired Properties incurred under-delivered volume fees totaling $1,821,920, which is included in lease operating expenses on the Combined Statement of Revenue and Direct Operating Expenses. There were no under-delivered volumes during the year ended December 31, 2023. Amounts owed for under-delivered volume fees may be incurred in future periods and will be recognized in the period in which the amounts are deemed probable and estimable.

 

The estimated future commitment for the Acquired Properties under the Oil Agreement as of December 31, 2024 is presented in the table below:

 

		Total Oil Gathering Fee Exposure
2025		$	5,518,191
2026			5,795,084
Total		$	11,313,275

 

 

Acquired Properties

Notes to the Combined Statement of Revenues and Direct Operating Expenses

 

Note 5 – Excluded Expenses

 

Indirect general and administrative expenses, interest expense, income taxes, depreciation, depletion, amortization, impairment, and other indirect expenses have not been allocated to the Acquired Properties by Bayswater and as such, have been excluded from the accompanying Combined Statement of Revenue and Direct Operating Expenses.

 

Note 6 – Subsequent Events

 

Subsequent events have been evaluated through March 7, 2025, the date the accompanying Combined Statement of Revenues and Direct Operating Expenses was available to be issued. There were no material subsequent events that require recognition or additional disclosure in the accompanying Combined Statement of Revenue and Direct Operating Expenses.

 

Note 7 – Supplemental Oil and Gas Information (Unaudited)

 

Oil and Natural Gas Reserves

 

The estimates of proved oil and natural gas reserves and discounted future net cash flows for the Acquired Properties as of December 31, 2024 and 2023, were prepared using historical data and other information by qualified petroleum engineers at Bayswater. The process of estimating quantities of proved oil and natural gas reserves is very complex, requiring significant subjective decisions to be made in the evaluation of available geologic, engineering and economic data for each reservoir. The data for any given reservoir may also change substantially over time as the result of numerous factors, including but not limited to, additional development activity, production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time.

 

The estimated proved net recoverable reserves presented below include only those quantities of oil and natural gas that geologic and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic, operating, and regulatory practices. In accordance with the Securities and Exchange Commission’s (“SEC”) guidelines, estimates of proved reserves from which present values are derived were based on unweighted 12-month average price of the first day of the month price for the period, and held constant. Proved developed reserves represent only those reserves estimated to be recovered through existing wells. All of the Acquired Properties’ reserves set forth herein are in the United States and are proved reserves.

 

 

Acquired Properties

Notes to the Combined Statement of Revenues and Direct Operating Expenses

 

Note 7 – Supplemental Oil and Gas Information (Unaudited) (continued)

 

Oil and Natural Gas Reserves (continued)

 

The Acquired Properties’ estimated quantities of proved oil and natural gas reserves and changes in net proved reserves are summarized below for the years ended December 31, 2024 and 2023:

 

		Crude Oil (Bbl)				Natural Gas Liquids (Bbl)				Natural Gas (Mcf)
Proved developed and undeveloped reserves - January 1, 2023			43,534,578				25,716,588				151,438,028
Oil and gas production			(5,426,809	)			(1,983,172	)			(14,030,620	)
Acquisition of reserves			-				-				-
Extensions and discoveries			-				-				-
Revisions of previous estimates			(6,479,476	)			(4,566,309	)			(23,197,951	)
Proved developed and undeveloped reserves - December 31, 2023			31,628,293				19,167,107				114,209,457
Proved developed reserves at beginning of year			22,829,518				16,353,984				94,295,230
Proved developed reserves at end of year			19,869,387				13,663,700				80,473,539
Proved undeveloped reserves at beginning of year			20,705,060				9,362,604				57,142,798
Proved undeveloped reserves at end of year			11,758,906				5,503,407				33,735,918

 

		Crude Oil (Bbl)				Natural Gas Liquids (Bbl)				Natural Gas (Mcf)
Proved developed and undeveloped reserves - January 1, 2024			31,628,293				19,167,107				114,209,457
Oil and gas production			(5,208,746	)			(2,165,092	)			(18,097,870	)
Acquisition of reserves			-				-				-
Extensions and discoveries			-				-				-
Revisions of previous estimates			(4,854,367	)			(1,106,716	)			(1,039,772	)
Proved developed and undeveloped reserves - December 31, 2024			21,565,180				15,895,299				95,071,815
Proved developed reserves at beginning of year			19,869,387				13,663,700				80,473,539
Proved developed reserves at end of year			19,174,475				14,610,472				87,749,703
Proved undeveloped reserves at beginning of year			11,758,906				5,503,407				33,735,918
Proved undeveloped reserves at end of year			2,390,705				1,284,827				7,322,112

 

 

Acquired Properties

Notes to the Combined Statement of Revenues and Direct Operating Expenses

 

Note 7 – Supplemental Oil and Gas Information (Unaudited) (continued)

 

Standardized Measure

 

The Acquired Properties compute a standardized measure of future net cash flows and changes therein relating to estimated proved reserves in accordance with authoritative accounting guidance. The assumptions used to compute the standardized measure are those prescribed by the Financial Accounting Standards Board (“FASB”) and the SEC. These assumptions do not necessarily reflect the Company’s expectations of actual revenues to be derived from those reserves, nor their present value amount. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these reserve quantity estimates are the basis for the valuation process.

 

Future cash inflows and production and development costs are determined by applying prices and costs, including transportation, quality, and basis differentials, to the yearend estimated future reserve quantities. The following weighted average prices as adjusted for transportation, quality, and basis differentials were used in the calculation of the standardized measure:

 

		2024				2023
Crude Oil per Bbl		$	72.41			$	75.40
Natural Gas Liquids per Bbl		$	22.97			$	20.34
Natural Gas per Mcf		$	0.09			$	0.78

 

Future operating costs are determined based on estimates of expenditures to be incurred in developing and producing the proved reserves in place at the end of the period using yearend costs and assuming continuation of existing economic conditions. The standardized measure presented here does not include the effects of federal and state income taxes as the Sellers are partnerships and not subject to federal and state income taxes.

 

The standardized measure of discounted future net cash flows relating to the Acquired Properties’ proved oil and natural gas reserves is as follows (in thousands):

 

		December 31, 2024				December 31, 2023
Future cash inflows		$	1,934,965			$	2,864,222
Future production costs			(703,289	)			(795,220	)
Future development costs			(44,245	)			(93,467	)
Future net cash flows			1,187,431				1,975,535
Less: 10% annual discount to reflect timing of cash flows			(416,026	)			(695,350	)
Standardized measure of discounted future net cash flows		$	771,405			$	1,280,185

 

 

Acquired Properties

Notes to the Combined Statement of Revenues and Direct Operating Expenses

 

Note 7 – Supplemental Oil and Gas Information (Unaudited) (continued)

 

Changes in Standardized Measure

 

Changes in the standardized measure of discounted future net cash flows before income taxes related to the proved oil and gas reserves of the Acquired Properties are as follows (in thousands):

 

		For the Years Ended
		December 31, 2024				December 31, 2023
Standardized measure – beginning of the year		$	1,280,185			$	2,354,947
Sales of oil and natural gas, net of production costs			(358,624	)			(381,100	)
Net changes in price and production costs			(63,186	)			(831,988	)
Revisions of previous quantity estimates			(221,598	)			(320,932	)
Acquisition of reserves			-				-
Development costs incurred			47,354				266,702
Extensions and discoveries			-				-
Accretion of discount			128,018				235,495
Net change in future development costs			3,182				(19,569	)
Changes in timing and other			(43,926	)			(23,370	)
Standardized measure – end of year		$	771,405			$	1,280,185

 

 

 

Exhibit 99.3

 

MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS OF The ACQUIRED PROPERTIES

 

Certain aspects of the presentation of the results of operations of the Acquired Properties (as defined below) have been conformed for purposes of presenting comparable results. The following discussion and analysis of the results of operations of the Acquired Properties should be read in conjunction with the audited combined statement of revenue and direct operating expenses of the Acquired Properties for the years ended December 31, 2024 and 2023 and related notes, filed herewith.

 

General and Basis of Presentation

 

Under the terms of a contemplated Purchase and Sale Agreement between the Sellers (as defined below) and Prairie Operating Co. (“Prairie”) (the “Agreement”), Prairie would acquire certain oil and natural gas properties owned by Bayswater Resources, LLC, Bayswater Fund III-A, LLC, Bayswater Fund III-B, LLC, Bayswater Fund IV-A, LP, Bayswater Fund IV-B, LP, and Bayswater Fund IV-Annex, LP (collectively the “Sellers”) which include properties operated by an affiliated entity of the Sellers (together with the Sellers, “Bayswater”), non-operated properties, related proved reserves, and associated well equipment and infrastructure in Weld County, Colorado (the “Acquired Properties”).

 

Substantially all of the revenue of the Acquired Properties is derived from the sale of oil, natural gas and NGLs. Oil, natural gas and NGL prices are inherently volatile and are influenced by many factors outside of Bayswater’s control.

 

Overview

 

The following table presents production volumes and financial highlights of the Acquired Properties for the years ended December 31, 2024 and 2023:

 

		Year Ended December 31,
		2024								2023
		Period Total				Per Day				Period Total				Per Day
Production Sales Volume Data:
Oil (Mbbls)			5,209				14.3				5,427				14.9
Natural gas (MMcf)			18,098				49.6				14,031				38.4
Liquids (Mbbls)			2,165				5.9				1,983				5.4
Financial Data (thousands):
Revenue		$	443,852							$	466,832
Revenues in excess of direct operating expenses		$	358,624							$	381,100

 

Revenues for the year ended December 31, 2024 decreased by $23.0 million compared to the year ended December 31, 2023, primarily due to lower oil sales volumes and prices. Revenues in excess of direct operating expenses for the year ended December 31, 2024 decreased by $22.5 million compared to the year ended December 31, 2023, primarily due to the decrease in revenues.

 

 

Results of Operations

 

Year ended December 31, 2024 vs. Year ended December 31, 2023

 

		Year ended December 31,
		2024				2023				$ Change				% Change
		(Thousands)
Revenues:
Oil sales		$	391,062			$	415,000			$	(23,938	)			(6	)%
Natural gas and liquids sales			52,790				51,832				958				2	%
Total revenues		$	443,852			$	466,832			$	(22,979	)			(5	)%

 

Oil Sales

 

Oil sales for the year ended December 31, 2024 decreased $23.9 million, or 6%, from the year ended December 31, 2023, related to lower oil sales volumes and lower oil sales prices. The following table reflects oil prices and oil sales volumes for the years ended December 31, 2024 and 2023.

 

		Year ended December 31,
		2024				2023
Oil sales (per barrel)		$	75.08			$	76.47
Oil sales volumes (Mbbls)			5,209				5,427
Per day oil sales volumes (Mbbls/d)			14.3				14.9

 

Natural Gas and liquids sales

 

Natural gas and liquids sales for the year ended December 31, 2024 increased $1.0 million, or 2%, from the year ended December 31, 2023, due to an increase in natural gas and liquids sales volumes and higher liquids sales prices, partially offset by lower natural gas sales prices. The following table reflects natural gas and liquids prices and natural gas and liquids production volumes for the years ended December 31, 2024 and 2023.

 

		Year ended December 31,
		2024				2023
Natural gas sales (per Mcf)		$	0.17			$	0.81
Natural gas sales volumes (MMcf)			18,098				14,031
Per day natural gas sales volumes (MMcf/d)			49.6				38.4
Liquids sales (per barrel)		$	22.95			$	20.37
Liquids sales volumes (Mbbls)			2,165				1,983
Per day liquids sales volumes (Mbbls/d)			5.9				5.4

 

Direct operating expenses analysis:

 

		Year ended December 31,																Per Boe Expense
		2024				2023				$ Change				% Change				2024				2023
		(Thousands)
Direct operating expenses:
Lease operating expenses		$	35,899			$	39,898			$	(3,999	)			(10	)%		$	3.46			$	4.09
Lease operating expenses, related party			3,315				2,687				628				23	%			0.32				0.28
Production and property taxes			33,140				31,326				1,814				6	%			3.19				3.21
Oil gathering expenses			10,167				8,543				1,625				19	%			0.98				0.88
Workover expenses			2,706				3,278				(572	)			(17	)%			0.26				0.34
Total direct operating expenses		$	85,228			$	85,732			$	(503	)			(1	)%		$	8.20			$	8.79
Revenues in excess of direct operating expenses		$	358,624			$	381,100			$	(22,476	)			(6	)%		$	34.52			$	39.09

 

 

Lease operating expenses decreased $3.4 million for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily related to a decrease in water hauling and disposal expense.

 

Production and property taxes decreased $1.8 million for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily due to a decrease in oil revenue.

 

Oil gathering expenses increased $1.6 million for the year ended December 31, 2024, compared to the year ended December 31, 2023, primarily related to an increase in the oil sales volumes gathered and transported via pipeline.

 

Workover expenses decreased $0.6 million for the year ended December 31, 2024, compared to the year ended December 31, 2023, related to a decline in required maintenance on producing wells.

 

Critical Accounting Estimates

 

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts and disclosure of contingent liabilities at the date of the combined financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

 

The more significant reporting areas impacted by management’s judgments and estimates are as follows:

 

Revenue Recognition

 

Revenues are derived from the sale of produced oil, natural gas and natural gas liquids and are recognized when the recognition criteria of the Financial Accounting Standards Board (“FASB”) ASC Topic 606, Revenue from Contracts with Customers, are met, which generally occurs at the point in which title passes to the customers. Payment is generally received from one to three months after delivery. Provided that reasonable estimates can be made, revenues are accrued in the month the performance obligation is satisfied. Differences between estimates and actual volumes and prices, if any, are adjusted upon final settlement.

 

Direct Operating Expenses

 

Direct operating expenses are recognized when incurred and include amounts required to operate the wells to produce, gather, transport, process and treat oil and natural gas. Direct operating expenses also include production and property taxes and expenses with support personnel, support services, equipment and facilities related to oil and natural gas production.

 

Oil and Gas Data

 

Oil and Natural Gas Reserves

 

The estimates of proved oil and natural gas reserves and discounted future net cash flows for the Acquired Properties as of December 31, 2024 and 2023, were prepared using historical data and other information by qualified petroleum engineers at Bayswater. The process of estimating quantities of proved oil and natural gas reserves is very complex, requiring significant subjective decisions to be made in the evaluation of available geologic, engineering and economic data for each reservoir. The data for any given reservoir may also change substantially over time as the result of numerous factors, including but not limited to, additional development activity, production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time.

 

The estimated proved net recoverable reserves presented below include only those quantities of oil and natural gas that geologic and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic, operating, and regulatory practices. In accordance with the Securities and Exchange Commission’s (“SEC”) guidelines, estimates of proved reserves from which present values are derived were based on unweighted 12-month average price of the first day of the month price for the period, and held constant. Proved developed reserves represent only those reserves estimated to be recovered through existing wells. All the Acquired Properties’ reserves set forth herein are in the United States and are proved reserves.

 

 

		Crude Oil (Bbl)				Natural Gas Liquids (Bbl)				Natural Gas (Mcf)				BOE
Proved developed and undeveloped reserves
As of January 1, 2023			43,534,577				25,716,589				151,438,029				94,490,838
Oil and gas production			(5,426,809	)			(1,983,172	)			(14,030,620	)			(9,748,417	)
Extensions and discoveries			—				—				—				—
Revisions of previous estimates			(6,479,476	)			(4,566,309	)			(23,197,951	)			(14,912,110	)
December 31, 2023			31,628,293				19,167,109				114,209,457				69,830,311
Proved developed reserves at beginning of year			22,829,517				16,353,985				94,295,231				54,899,375
Proved developed reserves at end of year			19,869,387				13,663,701				80,473,539				46,945,345
Proved undeveloped reserves at beginning of year			20,705,060				9,362,604				57,142,798				39,591,463
Proved undeveloped reserves at end of year			11,758,906				5,503,407				33,735,918				22,884,966

 

		Crude Oil (Bbl)				Natural Gas Liquids (Bbl)				Natural Gas (Mcf)				BOE
Proved developed and undeveloped reserves
As of January 1, 2024			31,628,293				19,167,107				114,209,457				69,830,310
Oil and gas production			(5,208,746	)			(2,165,092	)			(18,097,870	)			(10,390,150	)
Extensions and discoveries			—				—				—				—
Revisions of previous estimates			(4,854,367	)			(1,106,716	)			(1,039,772	)			(6,134,378	)
December 31, 2024			21,565,180				15,895,299				95,071,815				53,305,782
Proved developed reserves at beginning of year			19,869,387				13,663,700				80,473,539				46,945,344
Proved developed reserves at end of year			19,174,475				14,610,472				87,749,703				48,409,898
Proved undeveloped reserves at beginning of year			11,758,906				5,503,407				33,735,918				22,884,966
Proved undeveloped reserves at end of year			2,390,705				1,284,827				7,322,112				4,895,884

 

As of December 31, 2023, proved developed and undeveloped reserves of the Acquired Properties were estimated to be 69,830 Mboe. During the year ended December 31, 2023, oil and gas production from the Acquired Properties were 9,748 Mboe and net downward revisions of 14,912 Mboe were recorded, primarily due to technical revisions attributable to decreased well performance. There were no extensions or discoveries during 2023 as all properties were proved reserves as of the beginning of the period. Proved undeveloped reserves were 22,885 Mboe as of December 31, 2023, representing 33% of total proved reserves compared to 39,591 Mboe of proved undeveloped reserves as of December 31, 2022, or approximately 42% of total proved reserves. The decrease was primarily due to the continued development of the Acquired Properties which resulted in 17,840 Mboe of beginning-of-the-year proved undeveloped reserves to be classified to proved developed reserves during 2023. All remaining proved undeveloped reserves are forecasted to be drilled and completed within five years.

 

 

As of December 31, 2024, proved developed and undeveloped reserves of the Acquired Properties were estimated to be 53,306 Mboe. During the year ended December 31, 2024, oil and gas production from the Acquired Properties were 10,390 Mboe and net downward revisions of 6,134 Mboe were recorded, primarily due to technical revisions attributable to decreased well performance. There were no extensions or discoveries during 2024 as all properties were proved reserves as of the beginning of the period. Proved undeveloped reserves were 4,896 Mboe as of December 31, 2024, representing 9% of total proved reserves compared to 22,885 Mboe of proved undeveloped reserves as of December 31, 2023, or approximately 33% of total proved reserves. The decrease was primarily due to the continued development of the Acquired Properties which resulted in 16,121 Mboe of beginning-of-the-year proved undeveloped reserves to be classified to proved developed reserves during 2024. All remaining proved undeveloped reserves are forecasted to be drilled and completed within five years.

 

Revisions represent the net changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development, drilling, and production history or resulting from a change in economic factors, such as commodity prices, operating costs or development costs.

 

Oil, natural gas and NGL reserve engineering is an estimation of accumulations of oil, natural gas and NGLs that cannot be measured exactly. The accuracy of any reserves estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserves estimates may vary from the quantities of oil, natural gas and NGLs that are ultimately recovered.

 

Standardized Measure

 

The Acquired Properties compute a standardized measure of future net cash flows and changes therein relating to estimated proved reserves in accordance with authoritative accounting guidance. The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC. These assumptions do not necessarily reflect Bayswater’s expectations of actual revenues to be derived from those reserves, nor their present value amount. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these reserve quantity estimates are the basis for the valuation process.

 

Future cash inflows and production and development costs are determined by applying prices and costs, including transportation, quality, and basis differentials, to the yearend estimated future reserve quantities. The following weighted average prices as adjusted for transportation, quality, and basis differentials were used in the calculation of the standardized measure:

 

		2024				2023
Crude Oil per Bbl		$	72.41			$	75.40
Natural Gas Liquids per Bbl		$	22.97			$	20.34
Natural Gas per Mcf		$	0.09			$	0.78

 

Future operating costs are determined based on estimates of expenditures to be incurred in developing and producing the proved reserves in place at the end of the period using yearend costs and assuming continuation of existing economic conditions. The standardized measure presented here does not include the effects of federal income taxes as the Sellers are partnerships and not subject to federal income taxes.

 

 

The standardized measure of discounted future net cash flows relating to the Acquired Properties’ proved oil and natural gas reserves is as follows (in thousands):

 

		December 31, 2024				December 31, 2023
Future cash inflows		$	1,934,965			$	2,864,222
Future production costs			(703,289	)			(795,220	)
Future development costs			(44,245	)			(93,467	)
Future net cash flows			1,187,431				1,975,535
Less: 10% annual discount to reflect timing of cash flows			(416,026	)			(695,350	)
Standardized measure of discounted future net cash flows		$	771,405			$	1,280,185

 

Changes in Standardized Measure

 

Changes in the standardized measure of discounted future net cash flows before income taxes related to the proved oil and gas reserves of the Acquired Properties are as follows (in thousands):

 

		For the Years Ended
		December 31, 2024				December 31, 2023
Standardized measure – beginning of the year		$	1,280,185			$	2,354,947
Sales of oil and natural gas, net of production costs			(358,624	)			(381,100	)
Net changes in price and production costs			(63,186	)			(831,988	)
Revisions of previous quantity estimates			(221,598	)			(320,932	)
Acquisition of reserves			-				-
Development costs incurred			47,354				266,702
Extensions and discoveries			-				-
Accretion of discount			128,018				235,495
Net change in future development costs			3,182				(19,569	)
Changes in timing and other			(43,926	)			(23,370	)
Standardized measure – end of year		$	771,405			$	1,280,185

 

Internal Controls and Qualifications of Technical Persons

 

The technical persons responsible for preparing the reserves estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Reserve Standards.

 

Bayswater maintains an internal staff of petroleum engineers and geoscience professionals who work closely with its reserve engineers to ensure the integrity, accuracy and timeliness of the data used to calculate its proved reserves relating to its assets. Bayswater’s internal engineers meet with independent reserve engineers periodically during the periods covered by the reserve report to discuss the assumptions and methods used in the proved reserve estimation process.

 

The preparation of Bayswater’s proved reserve estimates is completed in accordance with Bayswater’s internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:

 

	●	review and verification of historical production data, working interest, net revenue interest, lease operating statements, capital costs, severance and ad valorem taxes, which data is based on actual production as reported by Bayswater;
	●	verification of property ownership by Bayswater’s land department;
	●	preparation of reserve estimates by Bayswater’s Senior Vice President of Engineering;
	●	review by Bayswater’s Senior Vice President of Engineering of all of Bayswater’s reported proved reserves, including the review of all significant reserve changes and all new proved undeveloped reserves additions; and
	●	direct reporting responsibilities and final approval by Bayswater’s Senior Vice President of Engineering to Bayswater’s Valuation and Investment Committees.

 

 

John Arsenault, Senior Vice President of Engineering, is the technical person primarily responsible for overseeing the preparation of Bayswater’s reserves estimates. He has more than 30 years of experience in petroleum reservoir engineering, including reserve and economic evaluations, acquisition and divestitures, reservoir simulation and management. He has worked as an engineer with various consulting firms in his career, including several years with Schlumberger’s Reservoir Technologies Division, and MHA Petroleum Consultants. He has worked internationally in Mexico, Germany and Indonesia. Mr. Arsenault has significant experience with reserves evaluation and acquisition and development activities in the DJ Basin. While with Schlumberger, he managed offices in both Mexico and in the United States, leading large teams of integrated reservoir studies groups. He has extensive experience in hydraulic fracturing, having worked with the Gas Technology Institute on the implementation of various research projects. Mr. Arsenault has a BSc in Petroleum Engineering from the Colorado School of Mines.

 

Drilling Activity

 

The following table sets forth the exploratory and development wells completed (operated and non-operated) during the years ended December 31, 2024 and 2023:

 

		Year Ended December 31
		2024								2023
		Gross				Net				Gross				Net
Exploratory
Productive Wells			—				—				—				—
Dry Wells			—				—				—				—
Total Exploratory Wells			—				—				—				—
Development
Productive Wells			30				28.3				60				53.4
Dry Wells			—				—				—				—
Total Development Wells			30				28.3				60				53.4
Total			30				28.3				60				53.4

 

At December 31, 2024, 8.8 net (10 gross) wells were in the process of being drilled, completed, awaiting completion, or any other related material activities.

 

Production and Cost History

 

The following tables set forth information regarding net production of oil, natural gas and liquids and certain price and cost information for each of the periods indicated. The information set forth below related to the Acquired Properties consists of the historical results for the years ended December 31, 2024 and 2023:

 

		Year Ended December 31,
		2024				2023
Oil:
Total production (Mbbls)			5,209				5,427
Average sales price ($ per Bbl)		$	75.08			$	76.47
Natural Gas:
Total production (MMcf)			18,098				14,031
Average sales price ($ per Mcf)		$	0.17			$	0.81
Natural Gas Liquids:
Total production (Mbbls)			2,165				1,983
Average sales price ($ per Bbl)		$	22.95			$	20.37
Oil Equivalents:
Total production (MBoe)			10,390				9,748
Average daily production (MBoe/d)			28.47				26.7
Average direct operating expenses ($ per Boe)		$	8.11			$	8.79

 

Wells

 

The following table sets forth the number wells in which the Sellers owned a working interest as of December 31, 2024:

 

		Total
		Gross				Net
DJ Basin – Operated			327				299.9
DJ Basin – Non-operated			150				6.3

 

 

Developed and Undeveloped Acreage

 

The following table sets forth the Acquired Properties leasehold acreage as of December 31, 2024.

 

Developed Acres

Undeveloped Acres

Total Acres

Gross

Net

Gross

Net

Gross

Net

DJ Basin

25,856

21,906

2,619

2,374

28,475

24,280

 

All of the leases comprising the undeveloped acreage set forth in the table above will expire at the end of their primary terms unless an extension provision within the lease is exercised, the lease is extended by continuous operations, or production is established, in which event the lease will remain in effect until the cessation of production. The following table sets forth, as of December 31, 2024, the above undeveloped acreage subject to two-year extension provisions.

 

		2025								2026								2027
		Gross				Net				Gross				Net				Gross				Net
Extension Acres			545				545				-				-				-				-

 

All of the leases comprising the undeveloped acreage set forth in the tables above will expire at the end of their respective primary terms unless otherwise extended as described above. The following table sets forth, as of December 31, 2024, the expiration periods of the undeveloped acres, excluding the Extension Acres described above.

 

		2025								2026								2027
		Gross				Net				Gross				Net				Gross				Net
Expiration			640				640				160				160

 

Operations

 

The development plan for the Acquired Properties, as of December 31, 2024, assumed that all of the undeveloped acreage set forth in the tables above would be extended by continuous development and thereafter establishment of production, thereby negating the need to exercise the available extension provisions and nullifying the expiration periods.

 

General

 

Bayswater is the operator of substantially all of the Acquired Properties’ acreage. As operator, Bayswater obtains regulatory authorizations, designs and manages the development of a well and supervises operation and maintenance activities on a day-to-day basis. Bayswater does not own drilling rigs or the majority of the other oil field service equipment used for drilling or maintaining wells on the properties it operates. Independent contractors engaged by Bayswater provide a majority of the equipment and personnel associated with these activities. Bayswater utilizes the services of drilling, production and reservoir engineers and geologists and other specialists who work to improve production rates, increase reserves and lower the cost of operating Bayswater’s oil and natural gas properties.

 

Marketing

 

Bayswater markets all of the oil, natural gas and NGLs production from its operated properties. For the year ended December 31, 2024, the three largest customers with respect to the Acquired Properties generated approximately 87% of sales. For the year ended December 31, 2023, the three largest customers with respect to the Acquired Properties generated approximately 73% of sales. The loss of any single purchaser could materially and adversely affect the revenues of the Acquired Properties in the short-term; however, Bayswater believes that the loss of any of its purchasers would not have a long-term material adverse effect on its results of operations as oil, natural gas and NGLs are fungible products with well-established markets and numerous purchasers.

 

The majority of the Acquired Properties’ production is party to crude oil purchase contracts, pursuant to which the counterparty is required to receive and purchase all crude oil produced from the wells. One of the crude oil purchase contracts to which the Acquired Properties are subject requires a minimum volume of oil to be delivered each year beginning in 2023 and continuing through 2026. If volumes are under-delivered during this period, the Acquired Properties incur a fee per barrel of under-delivered volumes. The oil produced from the Acquired Properties is primarily gathered and purchased via pipeline.

 

Additionally, the Acquired Properties are subject to various gas gathering and processing agreements pursuant to which it has dedicated acreage, which the counterparty is required to receive and purchase all natural gas produced from wells operated by Bayswater located within the dedicated area through the term of the contracts. In exchange for this land dedication, the Acquired Properties receive certain gathering and delivery rights. One of the gas gathering and processing agreements to which the Acquired Properties are subject requires a monthly minimum payment, beginning in October 2019 and continuing through September 2029, intended to reimburse costs incurred by the counterparty in order to connect the gathering facility to the covered lands. This gas gathering and processing agreement further allocates a portion of the counterparty’s firm commitments to transport natural gas liquids processed by the counterparty to the Acquired Properties beginning in July 2022 and continuing through September 2029. Beginning in January 2023, this commitment is subject to shortfall fees for any under-delivered volumes.

 

 

 

Exhibit 99.4

 

UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL INFORMATION

 

As previously disclosed, on February 6, 2025, Prairie Operating Co. (the “Company”) entered into an asset purchase agreement (the “Bayswater PSA”) by and among the Company, certain of the Company’s subsidiaries and Bayswater Resources, LLC and affiliates (the “Bayswater Entities”) to acquire certain assets for a total consideration of $602.8 million (the “Bayswater Purchase Price”), subject to certain closing price adjustments and other customary closing conditions (the “Bayswater Acquisition”).

 

The Company is providing the following unaudited pro forma condensed combined financial information to aid in the analysis of the financial aspects of the following:

 

	(i)	the Bayswater Acquisition; and
	(ii)	the acquisition of certain assets from Nickel Road Operating LLC (“NRO”), which closed on October 1, 2024 (the “NRO Acquisition,” and collectively, with the Bayswater Acquisition, the “Transactions”).

 

The following unaudited pro forma condensed combined financial information has been prepared in accordance with Article 11 of Regulation S—X as amended by the final rule, Release No. 33—10786 “Amendments to Financial Disclosures about Acquired and Disposed Businesses” and presents the combination of historical financial information of the Company and Prairie LLC, adjusted to give effect to the Transactions, subsequent events thereto (the “Subsequent Events”) as described in Note 3– Subsequent Events below, and the financing transactions thereto (“Financing Transactions”) described in Note 5 – Financing below.

 

The unaudited pro forma condensed combined balance sheet as of December 31, 2024 combines the historical balance sheet of the Company as of December 31, 2024, on a pro forma basis as if the Bayswater Acquisition, the Subsequent Events, described in Note 3 – Subsequent Events below, and the Financing Transactions described in Note 5 – Financing below had been consummated on December 31, 2024.

 

The unaudited pro forma condensed combined statement of operations for the year ended December 31, 2024 combines the historical statement of operations of the Company, the adjusted historical consolidated statement of operations of NRO from January 1, 2024 through September 30, 2024 (refer to Note 2 — NRO Acquisition), and the historical statement of revenue and direct operating expenses of Bayswater, as applicable, on a pro forma basis as if the NRO Acquisition, Bayswater Acquisition, the Subsequent Events, described in Note 3 – Subsequent Events below, and the Financing Transactions described in Note 5 – Financing below had been consummated on January 1, 2024.

 

The unaudited pro forma condensed combined financial information is based on, and should be read in conjunction with:

 

	(a)	the Company’s audited historical consolidated financial statements and related notes included in its Annual Report on Form 10—K for the year ended December 31, 2024, filed with the Securities and Exchange Commission (the “SEC”) on March 6, 2025;
	(c)	the section entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in the Company’s Annual Report on Form 10—K for the year ended December 31, 2024, filed with the SEC on March 6, 2025;
	(d)	NRO’s unaudited consolidated financial statements for the nine months ended September 30, 2024, included in the Company’s Current Report on Form 8—K, filed with the SEC on November 27, 2024;
	(e)	the exhibit entitled “Information About NRO” included in the Company’s Current Report on Form 8—K, filed with the SEC on February 7, 2025; and
	(f)	the exhibit entitled “Management’s Discussion and Analysis of Results of Operations of the Acquired Properties” included in the Company’s Current Report on Form 8—K, filed with the SEC on March 24, 2025.

 

The unaudited pro forma condensed combined financial information has been presented for illustrative purposes only and does not necessarily reflect what the Company’s financial condition or results of operations would have been had the Bayswater Acquisition, NRO Acquisition, Subsequent Events, described in Note 3 – Subsequent Events below, or the Financing Transactions described in Note 5 – Financing below occurred on the dates indicated. Further, the unaudited pro forma condensed combined financial information does not project the Company’s future financial condition and results of operations. The actual financial position and results of operations may differ significantly from the pro forma amounts reflected herein due to a variety of factors. The unaudited pro forma adjustments represent management’s estimates based on information available as of the date of this filing and certain assumptions that management believes are factually supportable and are expected to have a continuing impact on the Company’s results of operations and are subject to change as additional information becomes available and analyses are performed.

 

 

Bayswater Acquisition

 

On February 6, 2025, the Company entered into the Bayswater PSA by and among the Company, certain of the Company’s subsidiaries and the Bayswater Entities to acquire certain assets for a total consideration of $602.8 million, subject to certain closing price adjustments and other customary closing conditions.

 

The Bayswater Acquisition is expected to be accounted for as an asset acquisition in accordance with Accounting Standards Codification Topic 805 — Accounting for Business Combinations (“ASC 805”). The estimated fair value of the consideration paid by the Company and the allocation of that amount to the underlying assets acquired, on a relative fair value basis, will be recorded on the Company’s books as of the closing date of the Bayswater Acquisition. Additionally, costs directly related to the Bayswater Acquisition are expected to be capitalized as a component of the Bayswater Purchase Price.

 

NRO Acquisition

 

On January 11, 2024, the Company entered into the NRO Agreement to acquire the assets of NRO for the Purchase Price, subject to certain closing price adjustments and other customary closing conditions. The Purchase Price consisted of $83.0 million in cash and $11.5 million in deferred cash payments. The Company deposited $9.0 million of the Purchase Price into an escrow account on January 11, 2024 (the “Deposit”).

 

On October 1, 2024, the Company closed the NRO Acquisition and paid $49.6 million to the sellers in cash reflecting the purchase price as adjusted for the Deposit and customary closing price adjustments. In December 2024, the Company completed the final settlement with NRO, resulting in NRO paying the Company $2.6 million, (together with the Deposit and the $49.6 million paid on October 1, 2024, the “Final Purchase Price”).

 

The NRO Acquisition was accounted for as an asset acquisition in accordance with ASC 805. The estimated fair value of the consideration paid by the Company and the allocation of that amount to the underlying assets acquired, on a relative fair value basis, was recorded on the Company’s books as of the date of October 1, 2024, (the “Acquisition Closing Date”) of the NRO Acquisition. Additionally, costs directly related to the NRO Acquisition were capitalized as a component of the Final Purchase Price.

 

Subsequent Events

 

Acquisition of DrillCo Interest

 

In conjunction with the Bayswater Acquisition, the Company is expected to acquire an interest in a DrillCo partnership (“DrillCo”) not owned by Bayswater within 45 days of closing of the Bayswater Acquisition for $15.0 million. Bayswater does not currently own this interest, but is expected to acquire this interest within 45 days of closing of the Bayswater Acquisition. As such, DrillCo was not included in the historical financial results of Bayswater.

 

Credit Facility Borrowings

 

On December 16, 2024, the Company entered into a reserve-based credit agreement with Citibank, N.A., as administrative agent, and the financial institutions party thereto (the “Existing Credit Agreement”). As of December 16, 2024, the Existing Credit Agreement has a maximum credit commitment of $1.0 billion, a borrowing base of $44.0 million and an aggregate elected commitment of $44.0 million. The Existing Credit Agreement is scheduled to mature on December 16, 2026. The Company borrowed $28.0 million under the Existing Credit Agreement on December 17, 2024. Without the consent of each lender and the administrative agent, the aggregate amount of revolving borrowings and outstanding letters of credit cannot exceed 80% of aggregate elected commitment.

 

On February 3, 2025, the Company entered into the First Amendment to the Existing Credit Agreement (the “First Amendment”), which among other things, increased the borrowing base and the aggregate elected commitments to $60.0 million. As of March 1, 2025, $47.0 million of revolving borrowings and no letters of credit were outstanding under the Existing Credit Agreement.

 

Senior Convertible Note

 

On September 30, 2024, YA II PN, LTD., a Cayman Islands exempt limited company (“Yorkville”), advanced an initial $15.0 million to the Company and the Company issued a convertible promissory note (the “Senior Convertible Note”), with an interest rate of 8.00% and a maturity date of September 30, 2025.

 

In December 2024, and in conjunction with the Existing Credit Agreement, the Company made a $3.7 million payment on the Senior Convertible Note, resulting in a principal balance of $11.3 million as of December 31, 2024. Additionally, in January and February 2025, Yorkville converted the remaining $11.3 million of the Senior Convertible Note in exchange for 2.1 million shares of the Company’s common stock, par value $0.01 per share (“Common Stock”).

 

 

Unaudited Pro Forma Condensed Combined Balance Sheet

As of December 31, 2024

(In thousands, except share amounts)

 

		Prairie Operating Co.				Bayswater Transaction Accounting				Subsequent Event				Financing				Combined
		(Historical)				Adjustments				Adjustments				Adjustments				Pro Forma
						(See Notes 4 and 6)				(See Notes 3 and 6)				(See Notes 5 and 6)
Assets
Current assets:
Cash and cash equivalents		$	5,192			$	(467,455	)(a)		$	19,000	(e)		$	493,075	(i)		$	23,912
							(7,900	)(a)							(3,000	)(j)
							(15,000	)(k)
Accounts receivable:
Oil, natural gas, and NGL revenue			3,024				—				—				—				3,024
Joint interest and other			9,275				—				—				—				9,275
Note receivable			494				—				—				—				494
Prepaid expenses and other current assets			317				—				—				—				317
Total current assets			18,302				(490,355	)			19,000				490,075				37,022
Long-term assets:
Property and equipment
Oil and natural gas properties, successful efforts method of accounting			134,953				546,769	(a)			15,052	(k)			—				696,774
Other			94				18,415	(a)			—				—				18,509
Accumulated depreciation and depletion			(427	)			—				—				—				(427	)
Total property and equipment, net			134,620				565,184				15,052				—				714,856
Deposits on oil and natural gas properties			382				15,000	(k)			(15,000	)(k)			—				382
Operating lease assets			1,323				—				—				—				1,323
Note receivable – non-current			168				—				—				—				168
Other non-current assets			1,759				—				—				9,750	(g)			11,509
Total assets		$	156,554			$	89,829			$	19,052			$	499,825			$	765,260
Liabilities, Mezzanine Equity and Stockholders’ Equity
Current liabilities:
Accounts payable and accrued expenses		$	38,225			$	—			$	—			$	—			$	38,225
Ad valorem and production taxes payable			7,094				27,127	(a)			—				—				34,221
Oil, natural gas, and NGL revenue payable			2,366				44,821	(a)			—				—				47,187
Senior convertible note, at fair value			12,555				—				(12,555	)(f)			—				—
Derivative liabilities			2,446				—				—				—				2,446
Operating lease liabilities			323				—				—				—				323
Total current liabilities			63,009				71,948				(12,555	)			—				122,402
Long-term liabilities:
Credit facility			28,000				—				19,000	(e)			330,000	(g)			377,000
Subordinated note, at fair value - related party			4,609				—				—				(4,609	)(j)			—
Subordinated note warrants, at fair value - related party			4,159				—				—				—				4,159
SEPA, at fair value			790				—				—				—				790
Derivative liabilities			1,949				—				—				—				1,949
Asset retirement obligations			227				1,881	(a)			52	(k)			—				2,160
Operating lease liabilities			1,043				—				—				—				1,043
Total long-term liabilities			40,777				1,881				19,052				325,391				387,101
Total liabilities		$	103,786			$	73,829			$	6,497			$	325,391			$	509,503
Commitments and contingencies
Mezzanine equity:
Series F convertible preferred stock		$	—			$	—			$	—			$	140,750	(h)		$	140,750
Stockholders’ equity:
Series D convertible preferred stock; $0.01 par value; 50,000 shares authorized, and 14,457 shares issued and outstanding (actual)		$	—			$	—			$	—			$	—			$	—
Common stock; $0.01 par value; 500,000,000 shares authorized and 23,045,209 shares issued and outstanding (actual) and 34,159,253 shares issued and outstanding (pro forma)			230				29	(a)			22	(f)			61	(h)			342
Additional paid-in capital			172,304				15,971	(a)			11,230	(f)			32,014	(h)			231,519
Accumulated deficit			(119,766	)			—				1,302	(f)			1,609	(j)			(116,854	)
Total stockholders’ equity			52,768				16,000				12,555				33,684				115,007
Total liabilities, mezzanine equity, and stockholders’ equity		$	156,554			$	89,829			$	19,052			$	499,825			$	765,260

 

 

Unaudited Pro Forma Condensed Combined Statement of Operations

Year Ended December 31, 2024

(In thousands, except share and per share amounts)

 

		Prairie Operating Co.				Nickel Road Operating				Bayswater Revenue & Direct Operating				Bayswater Transaction Accounting				Subsequent Event				Financing				Combined
		(Historical)				(As Adjusted)				(Historical)				Adjustments				Adjustments				Adjustments				Pro Forma
						(See Note 2)								(See Notes 4 and 6)				(See Notes 3 and 6)				(See Notes 5 and 6)
Revenue:
Oil, natural gas, and NGL revenue		$	7,939			$	30,781			$	—			$	443,852	(c)		$	15,326	(k)		$	—			$	497,898
Oil sales			—				—				391,062				(391,062	)(c)			—				—				—
Natural gas and liquids sales			—				—				52,790				(52,790	)(c)			—				—				—
Total revenues			7,939				30,781				443,852				—				15,326				—				497,898
Operating costs and expenses:
Lease operating expense			1,265				4,169				35,900				3,315	(c)			3,377	(k)			—				48,026
Lease operating expense - related party			—				—				3,315				(3,315	)(c)			—				—				—
Gathering, transportation, and processing			864				—				—				10,167	(c)			1,552	(k)			—				12,583
Oil gathering expenses			—				—				10,167				(10,167	)(c)			—				—				—
Ad valorem and production taxes			591				1,486				33,140				—				1,096	(k)			—				36,313
Depreciation, depletion, and amortization			427				2,360				—				67,778	(b)			1,848	(k)			—				72,413
Accretion of asset retirement obligation			6				—				—				—				—				—				6
Workover expenses			—				—				2,706				—				—				—				2,706
Exploration expenses			734				—				—				—				—				—				734
General and administrative expenses			30,565				3,018				—				—				—				—				33,583
Impairment of oil and natural gas properties			—				29,719				—				—				—				—				29,719
Total operating expenses			34,452				40,752				85,228				67,778				7,873				—				236,083
(Loss) income from operations			(26,513	)			(9,971	)			358,624				(67,778	)			7,453				—				261,815
Other expenses:
Interest expense			(1,142	)			—				—				—				(1,520	)(e)			(28,838	)(g)			(30,231	)
																			900	(f)			369	(j)
Loss on derivatives, net			(4,395	)			—				—				—				—				—				(4,395	)
Loss on adjustment to fair value – debt and warrants			(5,358	)			—				—				—				1,302	(f)			1,328	(j)			(2,728	)
Loss on issuance of debt			(3,039	)			—				—				—				—				281	(j)			(2,758	)
Interest income and other			580				—				—				—				—				—				580
Total other expenses			(13,354	)			—				—				—				682				(26,860	)			(39,532	)
Net (loss) income from operations before provision for income taxes / Revenues in excess of direct operating expenses			(39,867	)			(9,971	)			358,624				(67,778	)			8,135				(26,860	)			222,283
Provision for income taxes			—				—				—				(51,131	)(d)			—				—				(51,131	)
Net (loss) income attributable to Prairie Operating Co.		$	(39,867	)		$	(9,971	)		$	358,624			$	(118,909	)		$	8,135			$	(26,860	)		$	171,152
Series F Preferred Stock dividends			—				—				—				—				—				(6,000	)(h)			(6,000	)
Net (loss) income attributable to Prairie Operating Co. common stockholders		$	(39,867	)		$	(9,971	)		$	358,624			$	(118,909	)		$	8,135			$	(32,860	)		$	165,152
Earnings (loss) per common share:
Income (loss) per share, basic		$	(2.58	)																						$	6.07
Income (loss) per share, diluted		$	(2.58	)																						$	4.12
Weighted average common shares outstanding, basic			15,453,502												2,876,301	(a)			2,118,862	(f)			6,748,570	(h)			27,197,235
Weighted average common shares outstanding, diluted			15,453,502												2,876,301	(a)			2,118,862	(f)			19,621,714	(h)			40,070,379

 

 

Note 1 — Basis of Pro Forma Presentation

 

The Bayswater Acquisition is expected to be accounted for as an asset acquisition in accordance with ASC 805. The estimated fair value of the consideration paid by the Company and the allocation of that amount to the underlying assets acquired, on a relative fair value basis, will be recorded on the Company’s books as of the closing date of the Bayswater Acquisition. Additionally, costs directly related to the Bayswater Acquisition are expected to be capitalized as a component of the Bayswater Purchase Price.

 

The NRO Acquisition was accounted for as an asset acquisition in accordance with ASC 805. The estimated fair value of the consideration paid by the Company and allocation of that amount to the underlying assets acquired, on a relative fair value basis, were recorded on the Company’s books as of the Acquisition Closing Date. Additionally, costs directly related to the NRO Acquisition were capitalized as a component of the Final Purchase Price.

 

The unaudited pro forma condensed combined balance sheet as of December 31, 2024 combines the historical balance sheet of the Company as of December 31, 2024 on a pro forma basis in accordance with Article 11 of Regulation S—X, as amended, as if the Bayswater Acquisition, the Subsequent Events, described in Note 3 – Subsequent Events below, and the Financing Transactions described in Note 5 – Financing had been consummated on December 31, 2024.

 

The unaudited pro forma condensed combined statement of operations for the year ended December 31, 2024 combines the historical statements of operations of the Company, the adjusted historical consolidated statement of operations of NRO for January 1, 2024 through September 30, 2024, described in Note 2 – NRO Acquisition below, and the historical statement of revenue and direct operating expenses of Bayswater, as applicable, on a pro forma basis as if the Bayswater Acquisition, the NRO Acquisition, the Subsequent Events described in Note 3 – Subsequent Events below, and the Financing Transactions described in Note 5 – Financing below had been consummated on January 1, 2024.

 

The pro forma basic and diluted earnings (loss) per share amounts presented in the unaudited pro forma condensed combined statement of operations are based upon the number of shares of Common Stock outstanding, assuming the Bayswater Acquisition, the Subsequent Events described in Note 3 – Subsequent Events below, and the Financing Transactions described in Note 5 – Financing below, occurred on January 1, 2024.

 

The unaudited pro forma condensed combined financial information is based on, and should be read in conjunction with, (i) the audited historical financial statements of the Company as of and for the year ended December 31, 2024 and the notes thereto, as well as the disclosures contained in the section “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in the Company’s Annual Report on Form 10—K for the fiscal year ended December 31, 2024, filed with the SEC on March 6, 2025; (ii) NRO’s unaudited consolidated financial statements for the nine months ended September 30, 2024, included in the Company’s Current Report on Form 8—K, filed with the SEC on November 27, 2024; (iii) the exhibit entitled “Information About NRO.” included in the Company’s Current Report on Form 8—K, filed with the SEC on February 7, 2025; and (iv) the exhibit entitled “Management’s Discussion and Analysis of Results of Operations of the Acquired Properties” included in the Company’s Current Report on Form 8—K, filed with the SEC on March 24, 2025.

 

The unaudited pro forma condensed combined financial information has been presented for illustrative purposes only and does not necessarily reflect what the Company’s financial condition or results of operations would have been had the Bayswater Acquisition, the NRO Acquisition, Subsequent Events described in Note 3 – Subsequent Events below, or the Financing Transactions described in Note 5 – Financing below occurred on the dates indicated. Further, the unaudited pro forma condensed combined financial information does not project the Company’s future financial condition and results of operations. The actual financial position and results of operations may differ significantly from the pro forma amounts reflected herein due to a variety of factors. The unaudited pro forma adjustments represent management’s estimates based on information available as of the date of this filing and certain assumptions that management believes are factually supportable and are expected to have a continuing impact on the Company’s results of operations and are subject to change as additional information becomes available and analyses are performed.

 

 

Note 2 — NRO Acquisition

 

As previously disclosed, the Company entered into an asset purchase agreement, dated January 11, 2024 (the “NRO Agreement”), by and among the Company, NRO, and Prairie Operating Co., LLC (“Prairie LLC”), to acquire certain assets of NRO for total consideration of $94.5 million (the “Purchase Price”), subject to certain closing price adjustments and other customary closing conditions. The Purchase Price consisted of $83.0 million in cash and $11.5 million in deferred cash payments. The Company deposited $9.0 million of the Purchase Price into an escrow account on January 11, 2024. On October 1, 2024, the Company closed the NRO Acquisition and paid $49.6 million to the sellers in cash reflecting the purchase price as adjusted for the Deposit and customary closing price adjustments. In December 2024, the Company completed the final settlement with NRO, resulting in NRO paying the Company $2.6 million.

 

As discussed above, the NRO Acquisition closed on October 1, 2024 and was accounted for as an asset acquisition in accordance with ASC 805. The estimated fair value of the consideration paid by the Company and the allocation of that amount to the underlying assets acquired, on a relative fair value basis, were recorded on the Company’s books as of October 1, 2024, the closing date of the NRO Acquisition. Additionally, costs directly related to the NRO Acquisition were capitalized as a component of the Purchase Price.

 

The Company’s condensed balance sheet as of December 31, 2024 includes the NRO Assets as of October 1, 2024 and its condensed statement of operations for the year ended December 31, 2024 includes the result of operations related to the NRO assets for October 1, 2024 through December 31, 2024. As such, for pro forma purposes herein, the Company has included the NRO Acquisition results of operations for the nine months ended September 30, 2024, as adjusted to remove the impact of assets not acquired using the information provided by NRO, in the Pro Forma Condensed Combined Statement of Operations for the year ended December 31, 2024.

 

The following table presents NRO’s statement of operations for the nine months ended September 30, 2024 and the adjustments needed to reflect just the items related to the NRO Assets purchased by the Company:

 

		Nine Months Ended September 30, 2024				Adjustments				As Adjusted
		(In thousands)
Revenue:
Oil and gas sales		$	30,781			$	—			$	30,781
Total revenues			30,781				—				30,781
Operating costs and expenses:
Lease operating expense			4,169				—				4,169
Production taxes			1,939				(453	)			1,486
Depreciation, depletion and amortization			10,726				(8,366	)			2,360
General and administrative			3,018				—				3,018
Impairment of oil and natural gas properties			29,719				—				29,719
Total operating expenses			49,571				(8,819	)			40,752
(Loss) income from operations			(18,790	)			8,819				(9,971	)
Other expenses:
Interest expense			(975	)			975				—
Realized gain on derivative instruments			223				(223	)			—
Unrealized loss on derivative instruments			(271	)			271				—
Gain on sale of oil and gas properties			5,373				(5,373	)			—
Other expenses			1				(1	)			—
Total other expenses			4,352				(4,352	)			—
(Loss) income from operations before provision for income taxes			(14,438	)			4,467				(9,971	)
Provision for income taxes			—				—				—
(Loss) income from continuing operations		$	(14,438	)		$	4,467			$	(9,971	)

 

 

Note 3 — Subsequent Events

 

Acquisition of DrillCo Interest

 

In conjunction with the Bayswater Acquisition, the Company is expected to acquire an interest in DrillCo not owned by Bayswater within 45 days of closing of the Bayswater Acquisition for $15.0 million. Bayswater does not currently own this interest, but is expected to acquire this interest within 45 days of closing of the Bayswater Acquisition. As such, DrillCo was not included in the historical financial results of Bayswater.

 

Credit Facility Borrowings

 

On February 3, 2025, the Company entered into the First Amendment, which among other things, increased the borrowing base and the aggregate elected commitments to $60.0 million. As of March 1, 2025, $47.0 million of revolving borrowings and no letters of credit were outstanding under the Existing Credit Agreement.

 

Senior Convertible Note

 

In December 2024, and in conjunction with the Existing Credit Agreement, the Company made a $3.7 million payment on the Senior Convertible Note, resulting in a principal balance of $11.3 million as of December 31, 2024. Additionally, in January and February 2025, Yorkville converted the remaining $11.3 million of the Senior Convertible Note in exchange for 2.1 million shares of Common Stock.

 

Note 4 — Bayswater Acquisition

 

The preliminary allocation of the total Bayswater Purchase Price in the Bayswater Acquisition, on a relative fair value basis, is based upon management’s estimates of and assumptions related to the fair value of assets acquired and liabilities assumed as of the closing date using currently available information. Because the unaudited pro forma condensed combined financial information has been prepared based on these preliminary estimates, the final purchase price allocation and the resulting effect on the Company’s financial position and results of operations may differ significantly from the pro forma amounts included herein.

 

The preliminary purchase price allocation is subject to change due to several factors, including but not limited to changes in the estimated fair value of assets acquired and liabilities assumed as of the closing date, which could result from changes in future oil and natural gas commodity prices, reserve estimates, interest rates, as well as other factors.

 

The consideration transferred, assets acquired, and liabilities assumed by the Company are expected to be initially recorded as follows:

 

		(In thousands)
Consideration:
Cash consideration (1)		$	467,455
Direct transaction costs (2)			7,900
Common stock issued to the sellers (3)			16,000
Total consideration		$	491,355
Assets acquired:
Oil and gas properties		$	546,769
Other assets			18,415
		$	565,184
Liabilities assumed:
Accounts payable and accrued expenses (4)		$	(71,948	)
Asset retirement obligation, long-term			(1,881	)
		$	(73,829	)

 

(1)	Includes customary purchase price adjustments.
(2)	Represents estimated transaction costs associated with the Bayswater Acquisition which will be capitalized in accordance with ASC 805-50.
(3)	Represents approximately 2.9 million shares of common stock issued to the sellers.
(4)	Represents the amounts associated with the assets acquired in the Bayswater Acquisition unpaid at the closing date and primarily relates to ad valorem tax and severance tax liabilities of $27.1 million and suspended revenues of $44.8 million.

 

 

This preliminary allocation does not include the DrillCo acquisition, which will be included in the Bayswater Acquisition upon its closing and is currently estimated to increase oil and gas properties by $15.0 million and asset retirement obligation by $52.0 thousand, see Note 3 – Subsequent Events.

 

The consideration is allocated to the assets acquired and liabilities assumed on a relative fair value basis. The fair value measurements of assets acquired and liabilities assumed, on a relative fair value basis, are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair value of oil and gas properties and asset retirement obligations were measured using the discounted cash flow technique of valuation.

 

Significant inputs to the valuation of oil and gas properties include estimates of: (i) reserves, (ii) future operating and development costs, (iii) future commodity prices, (iv) future plugging and abandonment costs, (v) estimated future cash flows, and (vi) a market—based weighted average cost of capital rate. These inputs require significant judgments and estimates and are the most sensitive and subject to change.

 

Note 5 — Financing

 

Debt Financing

 

In connection with the Bayswater Acquisition, the Company has entered into the Commitment Letter with Citibank, N.A. and the other lenders party thereto, which is referred to as the Commitment Letter, pursuant to which the Company has received commitments to amend and restate its Existing Credit Agreement, which is referred to as the New Credit Agreement, to increase the borrowing base to $475.0 million as of the closing of the Bayswater Acquisition and extend its maturity date to four years after the closing date. The Company also expects that the New Credit Agreement will include changes to certain provisions of its Existing Credit Agreement, subject to agreement with the lenders, to take into account the Bayswater Acquisition. The Company expects to enter into its New Credit Agreement prior to or substantially concurrently with the closing of the Bayswater Acquisition and intends to fund a portion of the purchase price of the Bayswater Acquisition using borrowings under its New Credit Agreement, resulting in a total outstanding balance of approximately $377.0 million. However, there can be no assurance that the Company will enter into its New Credit Agreement within the anticipated time frame, or at all. Additionally, the Company expects to incur $9.8 million in deferred financing costs which it will amortize on a straight-line basis over the life of the Credit Facility.

 

Additionally, the Company will use a portion of the additional Credit Facility borrowing to repay the outstanding $3.0 million balance of its subordinated promissory note with First Idea Ventures LLC and The Hideaway Entertainment LLC.

 

Preferred Stock Issuance

 

The Company expects to issue Series F convertible preferred stock with a par value of $0.01 and a stated value of $1,000 per share, which are convertible into shares of Common Stock (“Series F Preferred Stock”) to High Trail Capital LP or an affiliate thereof (the “Series F Preferred Stock Investor”) for total proceeds of $150.0 million. After deducting offering expenses payable by the Company, the total net proceeds are expected to be approximately $140.8 million.

 

The Series F Preferred Stock Investor is entitled to quarterly dividends beginning on June 1, 2025 at a rate of 12.0% per annum from; provided that, from, including and after the date that is the six month anniversary of the maturity of the Existing Credit Agreement, the dividend rate will be 25.0%. The Company has the option to pay these dividends by issuing Common Stock provided certain equity conditions are satisfied, which it plans to do; therefore, it has included the shares of Common Stock related to the Series F Preferred Stock dividend in its weighted average shares outstanding.

 

 

The Company has determined that some of the Series F Preferred Stock conversion features have debt-like characteristics, therefore, it has presented the Series F Preferred Stock in Mezzanine Equity on the unaudited pro forma condensed combined balance sheet as of December 31, 2024.

 

Equity Financing

 

The Company expects to generate gross proceeds of $35.0 million (before underwriting discounts and commissions and offering expenses) from the sale of its Common Stock, which it intends to use to fund a portion of the cash consideration in the Bayswater Acquisition. After deducting the underwriting discounts and commissions and offering expenses payable by the Company, the total net proceeds are expected to be approximately $32.1 million. Based on the closing price of the Company’s Common Stock on March 14, 2025 of $5.72, it expects to issue approximately 6.1 million shares of Common Stock (assuming no exercise of the underwriters’ option to purchase additional shares) and an additional 2.9 million shares of Common Stock to the sellers.

 

The following table summarizes the estimated Common Stock to be issued resulting from a 10% fluctuation in the market price of the shares of Common Stock:

 

		Share Price				Common Stock Issued
As presented		$	5.72				6,118,881
10% increase		$	6.29				5,562,619
10% decrease		$	5.15				6,798,757

 

Note 6 — Unaudited Pro Forma Adjustments

 

The pro forma adjustments included in the unaudited pro forma condensed combined balance sheet as of December 31, 2024 and in the unaudited pro forma condensed combined statement of operations for the year ended December 31, 2024 are as follows:

 

(a)	Reflects the adjustment to record the assets acquired and liabilities assumed, on a relative fair value basis, in the Bayswater Acquisition along with transfer of consideration, inclusive of common shares issued to the sellers and transaction costs associated with the acquisition (see Note 4 – Bayswater Acquisition).
(b)	Reflects the adjustment for depreciation, depletion and amortization expense associated with the assets acquired in the Bayswater Acquisition.
(c)	Reflects the reclassification of oil sales, natural gas and liquids sales, lease operating expenses - related party and oil gathering expenses to conform to the Company’s financial statement presentation.
(d)	Reflects the estimated combined Company income tax expense resulting from the impact of including the revenue in excess of direct operating expenses from the Bayswater Acquisition to the Company’s income from continuing operations before income taxes.
(e)	Reflects the adjustment to record the January and February 2025 borrowings of $19.0 million, under the Existing Credit Agreement and the associated increase in interest expense along (see Note 3 – Subsequent Events).
(f)	Reflects the adjustment to record Yorkville’s conversion of the Senior Convertible Note during January and February 2025 and the associated decrease in loss of adjustment to fair value and interest expense (see Note 3 – Subsequent Events).
(g)	Reflects the adjustment to record the additional borrowing under the New Credit Agreement to fund the Bayswater Acquisition, the deferred financing costs for the additional borrowing, and the associated amortization of deferred financing fees and the increase in interest expense (see Note 5 – Financing).

 

 

(h)	Reflects the adjustment to record the issuance of common stock and Series F Preferred Stock to fund the Bayswater Acquisition, net the underwriting discounts and commissions and offering expenses payable by the Company (see Note 5 – Financing).

 

The Company’s diluted weighted average shares outstanding for the year ended December 31, 2024 include the following potentially dilutive securities:

 

Potentially Dilutive Security		Quantity				Stated Value Per Share				Total Value or Stated Value				Assumed Conversion Price				Resulting Common Shares
Merger Options, restricted stock units, and performance stock units (1)			9,337,631			$	—			$	—			$	—				1,337,631
Common stock warrants			227,148,205				—				—				—				8,494,177
Series D Preferred Stock			14,457				1,000				14,456,680				5.00				2,891,336
Total																			12,723,144

 

⁽¹⁾ Not exercisable or vested as of December 31, 2024.

 

Additionally, the 150,000 shares of Series F Preferred Stock issued in connection with the Bayswater Acquisition would be included in the Company’s diluted weighted average shares outstanding and the related dividends of 629,689 common stock shares would be included in both the Company’s basic and diluted weighted average common shares outstanding (see Note 5 – Financing).

 

(i)	Reflects the adjustment to record the net proceeds received from the additional borrowing under the New Credit Agreement, the issuance of common stock, and issuance of the Series F Preferred Stock (see notes (g) and (h) above).
(j)	Reflects the repayment of the subordinated promissory note and the associated decrease in loss of adjustment to fair value, loss on debt issuance, and interest expense (see Note 5 – Financing).
(k)	Reflects the adjustments to record the acquisition of DrillCo and the required adjustments (see Note 3 – Subsequent Events).

 

 

 

 

Exhibit 99.5

 

 

March 17, 2025

 

Mr. Bryan Freeman

Executive Vice President, Operations

Prairie Operating Co.

55 Waugh Drive, Suite 400

Houston, TX 77007

 

	Re:	Evaluation Summary - SEC Price
		Prairie Operating Co. Interests
		Total Proved Reserves
		Certain Properties in Weld Co., CO
		As of December 31, 2024
		Pursuant to the Guidelines of the Securities and
		Exchange for Reporting Corporate Reserves and
		Future Net Revenue

 

Dear Mr. Freeman:

 

As requested, this report was completed on March 17, 2025 for the purpose of submitting our estimates of proved reserves and forecasts of economics attributable to the Prairie Operating Co. (“Prairie”) interests and for inclusion as an exhibit in a filing made with the U.S. Securities and Exchange Commission (“SEC”). We evaluated 100% of the Prairie total proved reserves in Weld County, Colorado, as per information from Prairie. This evaluation utilized an effective date of December 31, 2024, was prepared using constant prices and costs, and conforms to Item 1202(a)(8) of Regulation S-K and other rules of the SEC. The results of this evaluation are presented in the composite summary below:

 

				Proved				Proved Developed
				Developed				Non-				Proved				Proved				Total
				Producing				Producing				Developed				Undeveloped				Proved
Net Reserves
Oil		- Mbbl			23,195.0				3,951.2				27,146.1				21,762.8				48,908.9
Gas		- MMcf			112,033.2				7,350.8				119,384.1				64,931.6				184,315.6
NGL		- Mbbl			14,604.0				914.8				15,518.9				8,078.8				23,597.7
Net Revenue
Oil		- M$			1,681,079.3				289,769.6				1,970,849.0				1,597,849.6				3,568,698.4
Gas		- M$			36,202.3				7,985.6				44,187.9				59,909.2				104,097.1
NGL		- M$			328,986.8				20,117.9				349,104.7				178,771.4				527,876.1
Severance Taxes		- M$			7,775.8				1,207.9				8,983.7				6,978.8				15,962.6
Ad Valorem Taxes		- M$			134,948.2				20,963.2				155,911.4				121,116.3				277,027.6
Future Production Costs		- M$			518,475.0				57,253.8				575,728.8				385,930.1				961,659.1
Future Development Costs		- M$			0.0				29,740.2				29,740.2				563,670.1				593,410.3
Abandonment Costs		- M$			18,739.8				998.8				19,738.6				6,695.8				26,434.2
Net Operating Income (BFIT)		- M$			1,366,329.6				207,709.2				1,574,039.2				752,138.6				2,326,177.8
Discounted @ 10%		- M$			835,118.0				140,024.8				975,142.6				382,418.0				1,357,561.1

 

 

Future Revenue is prior to deducting state production taxes and ad valorem taxes. Future net cash flow (net operating income) is after deducting these taxes, future capital costs and operating expenses, but before consideration of federal income taxes. In accordance with SEC guidelines, the future net cash flow has been discounted at an annual rate of ten (10) percent to determine present worth. The present worth is shown to indicate the effect of time on the value of money and should not be construed as being the fair market value of the properties by Cawley, Gillespie & Associates, Inc. (“CG&A”).

 

The oil reserves include oil and condensate. Oil and natural gas liquid (NGL) volumes are expressed in barrels (42 U.S. gallons). Gas volumes are expressed in thousands of standard cubic feet (Mcf) at contract temperature and pressure base.

 

Hydrocarbon Pricing

 

The base SEC oil and gas prices calculated for December 31, 2024 were $75.48/bbl and $2.130/MMBTU, respectively. As specified by the SEC, a company must use a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. The base oil price is based upon WTI-Cushing spot prices (EIA) during 2024 and the base gas price is based upon Henry Hub spot prices (Platts Gas Daily) during 2024. Furthermore, NGL prices were adjusted on a per-property basis and averaged 30.7% of the proved net oil price on a composite basis.

 

Adjustments to oil and gas prices were made based upon data provided by your office and include adjustments for treating costs and/or crude quality and gravity corrections. After these adjustments, the net realized prices over the life of the proved properties were estimated to be $72.966 per barrel of oil, $0.565 per MCF of gas and $22.370 per barrel for NGL. All economic factors were held constant in accordance with SEC guidelines.

 

Economic Parameters

 

Oil and gas price differentials, gas shrinkage, ad valorem taxes, future production costs (lease operating expenses) and future development costs (capital investments) were calculated and prepared by Prairie and were audited by us at a summary level using historical lease operating statement data. Our audit determined that the commercial parameters being applied were reasonable and appropriate, and therefore no changes were made to cost parameters. Ownership was accepted as furnished and has not been independently confirmed. All economic parameters, including lease operating expenses (LOE) and investments, were held constant (not escalated) throughout the life of these properties in accordance with SEC guidelines.

 

LOE includes fixed and variable components. The fixed LOE costs represent all costs not tied to produced volumes. The variable costs consist of fees for gas compression, processing and transportation, and other variable expenses.

 

SEC Conformance and Regulations

 

Following this letter, the primary supervisor’s qualifications are listed. The reserve classifications and the economic considerations used herein conform to the criteria of the SEC as defined on pages seven (7) and eight (8) of this report letter. The reserves and economics are predicated on regulatory agency classifications, rules, policies, laws, taxes and royalties currently in effect except as noted herein. The possible effects of changes in legislation or other Federal or State restrictive actions which could affect the reserves and economics have not been considered. However, we do not anticipate nor are we aware of any legislative changes or restrictive regulatory actions that may impact the recovery of reserves.

 

 

CG&A evaluated 20 PDNP locations, of which 18 represent wells that are awaiting completion while two (2) are awaiting workovers, including tubing repair and plunger replacement. This evaluation also includes 170 PUD drilling locations. All locations are proposed as part of Prairie’s development plans, which was based upon Prairie’s go forward plan and accepted as furnished. In our opinion, Prairie and other working interest operators have indicated that they have every intent to complete this development plan within the next five (5) years, as scheduled. Furthermore, Prairie and other working interest operators have demonstrated that they have the proper company staffing, financial backing and prior development success to ensure this development plan will be fully executed.

 

Reserve Estimation Methods

 

The methods employed in estimating reserves are described on page six (6) of this report letter. All reserve estimates involve an assessment of the uncertainty relating to the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends mainly on the amount of the reliable geologic and engineering data available at the time of the estimate and the interpretation of such data, as well as the inherent uncertainties attributable to variations in reservoir and rock quality, offset drainage, mechanical wellbore integrity among others. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability.

 

Non-producing reserve estimates, for developed and undeveloped properties, were forecast using either volumetric or analogy methods, or a combination of both. These methods provide a relatively high degree of accuracy for predicting PDNP and PUD reserves for Prairie’s properties, due to the mature nature of their properties targeted for development and an abundance of subsurface control data. The assumptions, data, methods and procedures used herein are appropriate for the purpose served by this report.

 

General Discussion

 

The estimates and forecasts were based upon interpretations of data furnished by your office and available from our files. To some extent information from public records has been used to check and/or supplement these data. The basic engineering and geological data were subject to third party reservations and qualifications. Nothing has come to our attention, however, that would cause us to believe that we are not justified in relying on such data. All estimates represent our best judgment based on the data available at the time of preparation. Due to inherent uncertainties in future production rates, commodity prices and geologic conditions, it should be realized that the reserve estimates, the reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be more or less than the estimated amounts.

 

An on-site field inspection of the properties has not been performed nor has the mechanical operation or condition of the wells and their related facilities been examined, nor have the wells been tested by Cawley, Gillespie & Associates, Inc. Possible environmental liability related to the properties has not been investigated nor considered. The cost of plugging and the salvage value of equipment at abandonment have been considered in this evaluation.

 

 

Cawley, Gillespie & Associates, Inc. is a Texas Registered Engineering Firm (F-693), made up of independent registered professional engineers and geologists that have provided petroleum consulting services to the oil and gas industry for over 60 years. We do not own an interest in the properties or Prairie Operating Co. and are not employed on a contingent basis. We have used all methods and procedures that we consider necessary under the circumstances to prepare this report. Our work-papers and related data utilized in the preparation of these estimates are available in our office.

 

	Yours very truly,
	Cawley, Gillespie & Associates, Inc.
	Texas Registered Engineering Firm F-693
	W. Todd Brooker, P.E.
	President
	Thomas M. Barr
	Senior Engineer

 

 

Professional Qualifications of W. Todd Brooker, P.E.

Primary Technical Person

 

The evaluation summarized by this report was conducted by a proficient team of geologists and reservoir engineers who integrate geological, geophysical, engineering and economic data to produce high quality reserve estimates and economic forecasts. This report was supervised by Todd Brooker, President of Cawley, Gillespie & Associates, Inc. (CG&A).

 

Prior to joining CG&A, Mr. Brooker worked in Gulf of Mexico drilling and production engineering at Chevron USA. Mr. Brooker has been an employee of CG&A since 1992 and became President in 2017. His responsibilities include reserve and economic evaluations, fair market valuations, expert reporting and testimony, field/reservoir studies, pipeline resource assessments, field development planning and acquisition/divestiture analysis. His reserve reports are routinely used for public company U.S. Securities and Exchange Commission (SEC) disclosures. His experience includes significant projects in both conventional and unconventional resources in every major U.S. producing basin and abroad, including oil and gas shale plays, coalbed methane fields, waterfloods and complex, faulted structures.

 

Mr. Brooker graduated with honors from the University of Texas at Austin in 1989 with a Bachelor of Science degree in Petroleum Engineering. He is a registered Professional Engineer in the State of Texas (License #83462), and a member of the Society of Petroleum Engineers (SPE) and a Board member of the Society of Petroleum Evaluation Engineers (SPEE).

 

Based on his educational background, professional training and more than 30 years of experience, Mr. Brooker and CG&A continue to deliver independent, professional, ethical and reliable engineering and geological services to the petroleum industry.

 

CAWLEY, GILLESPIE & ASSOCIATES, INC.

Texas Registered Engineering Firm F-693

 

 

APPENDIX

 

Methods Employed in the Estimation of Reserves

 

The four methods customarily employed in the estimation of reserves are (1) production performance, (2) material balance, (3) volumetric and (4) analogy. Most estimates, although based primarily on one method, utilize other methods depending on the nature and extent of the data available and the characteristics of the reservoirs.

 

Basic information includes production, pressure, geological and laboratory data. However, a large variation exists in the quality, quantity and types of information available on individual properties. Operators are generally required by regulatory authorities to file monthly production reports and may be required to measure and report periodically such data as well pressures, gas-oil ratios, well tests, etc. As a general rule, an operator has complete discretion in obtaining and/or making available geological and engineering data. The resulting lack of uniformity in data renders impossible the application of identical methods to all properties, and may result in significant differences in the accuracy and reliability of estimates.

 

A brief discussion of each method, its basis, data requirements, applicability and generalization as to its relative degree of accuracy follows:

 

Production performance. This method employs graphical analyses of production data on the premise that all factors which have controlled the performance to date will continue to control and that historical trends can be extrapolated to predict future performance. The only information required is production history. Capacity production can usually be analyzed from graphs of rates versus time or cumulative production. This procedure is referred to as “decline curve” analysis. Both capacity and restricted production can, in some cases, be analyzed from graphs of producing rate relationships of the various production components. Reserve estimates obtained by this method are generally considered to have a relatively high degree of accuracy with the degree of accuracy increasing as production history accumulates.

 

Material balance. This method employs the analysis of the relationship of production and pressure performance on the premise that the reservoir volume and its initial hydrocarbon content are fixed and that this initial hydrocarbon volume and recoveries therefrom can be estimated by analyzing changes in pressure with respect to production relationships. This method requires reliable pressure and temperature data, production data, fluid analyses and knowledge of the nature of the reservoir. The material balance method is applicable to all reservoirs, but the time and expense required for its use is dependent on the nature of the reservoir and its fluids. Reserves for depletion type reservoirs can be estimated from graphs of pressures corrected for compressibility versus cumulative production, requiring only data that are usually available. Estimates for other reservoir types require extensive data and involve complex calculations most suited to computer models which makes this method generally applicable only to reservoirs where there is economic justification for its use. Reserve estimates obtained by this method are generally considered to have a degree of accuracy that is directly related to the complexity of the reservoir and the quality and quantity of data available.

 

Volumetric. This method employs analyses of physical measurements of rock and fluid properties to calculate the volume of hydrocarbons in-place. The data required are well information sufficient to determine reservoir subsurface datum, thickness, storage volume, fluid content and location. The volumetric method is most applicable to reservoirs which are not susceptible to analysis by production performance or material balance methods. These are most commonly newly developed and/or no-pressure depleting reservoirs. The amount of hydrocarbons in-place that can be recovered is not an integral part of the volumetric calculations but is an estimate inferred by other methods and a knowledge of the nature of the reservoir. Reserve estimates obtained by this method are generally considered to have a low degree of accuracy; but the degree of accuracy can be relatively high where rock quality and subsurface control is good and the nature of the reservoir is uncomplicated.

 

Analogy. This method, which employs experience and judgment to estimate reserves, is based on observations of similar situations and includes consideration of theoretical performance. The analogy method is a common approach used for “resource plays,” where an abundance of wells with similar production profiles facilitates the reliable estimation of future reserves with a relatively high degree of accuracy. The analogy method may also be applicable where the data are insufficient or so inconclusive that reliable reserve estimates cannot be made by other methods. Reserve estimates obtained in this manner are generally considered to have a relatively low degree of accuracy.

 

Much of the information used in the estimation of reserves is itself arrived at by the use of estimates. These estimates are subject to continuing change as additional information becomes available. Reserve estimates which presently appear to be correct may be found to contain substantial errors as time passes and new information is obtained about well and reservoir performance.

 

 

APPENDIX

 

Reserve Definitions and Classifications

 

The Securities and Exchange Commission, in SX Reg. 210-.4-10 dated November 18, 1981, as amended on September 19, 1989 and January 1, 2010, requires adherence to the following definitions of oil and gas reserves:

 

“(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations— prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

 

“(i) The area of a reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

 

“(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

 

“(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

 

“(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

 

“(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

 

“(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

 

“(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

 

“(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

 

“(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

 

“(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

 

“(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

 

“(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

 

 

“(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

 

“(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

 

“(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

 

“(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

 

“(iv) See also guidelines in paragraphs (17)(iv) and (17)(vi) of this section (below).

 

“(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

 

“(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

 

“(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

 

“(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

 

“(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

 

“(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

 

“(vi) Pursuant to paragraph (22)(iii) of this section (above), where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.”

 

Instruction 4 of Item 2(b) of Securities and Exchange Commission Regulation S-K was revised January 1, 2010 to state that “a registrant engaged in oil and gas producing activities shall provide the information required by Subpart 1200 of Regulation S–K.” This is relevant in that Instruction 2 to paragraph (a)(2) states: “The registrant is permitted, but not required, to disclose probable or possible reserves pursuant to paragraphs (a)(2)(iv) through (a)(2)(vii) of this Item.”

 

“(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

 

“Note to paragraph (26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).”

 

 

v3.25.1

Cover	Mar. 24, 2025
Cover [Abstract]
Document Type	8-K
Amendment Flag	false
Document Period End Date	Mar. 24, 2025
Entity File Number	001-41895
Entity Registrant Name	Prairie Operating Co.
Entity Central Index Key	0001162896
Entity Tax Identification Number	98-0357690
Entity Incorporation, State or Country Code	DE
Entity Address, Address Line One	55 Waugh Drive
Entity Address, Address Line Two	Suite 400
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77007
City Area Code	(713)
Local Phone Number	424-4247
Written Communications	false
Soliciting Material	false
Pre-commencement Tender Offer	false
Pre-commencement Issuer Tender Offer	false
Title of 12(b) Security	Common Stock, par value $0.01 per share
Trading Symbol	PROP
Security Exchange Name	NASDAQ
Entity Emerging Growth Company	false
Entity Information, Former Legal or Registered Name	Not Applicable

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