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.