Exhibit 99.2

This Management’s Discussion and Analysis (“MD&A”) of the financial condition and results of operations of Greenfire Resources Inc. (“Greenfire” or the “Company”) is dated August 14, 2023, which is the date this MD&A was approved by the Board of Directors of the Company, and should be read in conjunction with the Company’s unaudited interim consolidated financial statements and notes for the period ended June 30, 2023, as well as the audited consolidated financial statements and notes for the year ended December 31, 2022 and the 2022 annual MD&A. The financial statements, including the comparative figures, were prepared in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board (“IFRS”).

This MD&A contains forward looking information based on the Company’s current expectations and projections. For information on the material factors and assumptions underlying such forward-looking information, refer to the “Forward Looking Statements” section within this MD&A.

Production volumes and per unit statistics are presented throughout this MD&A on a “net of the Company’s working interest” and “before royalty basis”.

Dollar per barrel ($/bbl) figures are based upon sold bitumen barrels unless otherwise noted. The Company monitors and reviews financial information on a per barrel basis for comparability to prior period results and to analyze the Company’s competitiveness relative to its peer group.

All financial information included in this MD&A is presented in Canadian dollars (“CAD”), unless otherwise noted. Certain dollar amounts have been rounded to the nearest million dollars or thousand dollars, as noted, and tables may not add due to rounding.

The Company’s non-GAAP Measures are detailed in the non-GAAP Measures section of this report. They include Excess Cash Flow, adjusted EBITDA, adjusted EBITDA per barrel ($/bbl), adjusted funds flow, adjusted funds flow per barrel ($/bbl), adjusted working capital and net debt.

Key Factors Affecting Operating Results

The Company believes its performance depends on several factors that present significant opportunities for it but also pose risks and challenges.

Commodity Prices

Prices for crude oil, condensate and natural gas have historically been volatile. This volatility is expected to continue due to the many uncertainties associated with the global political and economic environment, including the supply of, and demand for, crude oil and natural gas and the availability of other energy supplies, both regionally and internationally, as well as the relative competitive relationships of the various energy sources in the view of consumers and other factors.

The market prices of crude oil, condensate and natural gas impact the amount of cash generated from Greenfire’s operating activities, which, in turn, impact Greenfire’s financial position and results of operations.

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Competition

The petroleum industry is competitive in all its phases. Greenfire competes with numerous other entities in the exploration, development, production and marketing of oil. Greenfire’s competitors include oil and natural gas companies that have substantially greater financial resources, workforce and facilities than those of Greenfire. Some of these companies not only explore for, develop and produce oil, but also carry on refining operations and market oil and natural gas on an international basis. As a result of these complementary activities, some of these competitors may have greater and more diverse competitive resources to draw on than Greenfire. Greenfire’s ability to increase its reserves in the future will depend not only on its ability to explore and develop its present properties, but also on its ability to select and acquire other suitable producing properties or prospects for exploratory drilling. Competitive factors in the distribution and marketing of oil include price, process, and reliability of delivery and storage.

Greenfire also faces competition from companies that supply alternative resources of energy, such as wind or solar power. Other factors that could affect competition in the marketplace include additional discoveries of hydrocarbon reserves by Greenfire’s competitors, changes in the cost of production, and political and economic factors and other factors outside of Greenfire’s control.

The petroleum industry is characterized by rapid and significant technological advancements and introductions of new products and services utilizing new technologies that may increase the viability of reserves or reduce production costs. Other companies may have greater financial, technical and personnel resources that allow them to implement and benefit from such technological advantages. Greenfire may not be able to respond to such competitive pressures and implement such technologies on a timely basis, or at an acceptable cost. If Greenfire does implement such technologies, Greenfire may not do so successfully. One or more of the technologies currently utilized or implemented in the future by Greenfire may become obsolete or uneconomic. If Greenfire is unable to employ the most advanced commercially available technology, or is unsuccessful in implementing certain technologies, its business, financial condition and results of operations could also be adversely affected in a material way.

Royalty Regimes

Greenfire pays royalties in accordance with the established royalty regime in the Province of Alberta. Greenfire’s royalties are paid to the Crown, which are based on government pre and post payout royalty rates determined on sliding scales and dependent on commodity prices. The Government of Alberta may adopt new royalty regimes, or modify the existing royalty regime, which may have an impact on the economics of Greenfire’s projects. An increase in royalties would reduce Greenfire’s earnings and could make future capital investments, or Greenfire’s operations, less economic. For more information see the subsection 4.4 Royalties.

Impact of COVID-19

The COVID-19 pandemic, which began in early 2020, continues to create uncertainty and negatively impact the commodity price environment by suppressing the continued recovery in global economic activity and demand for hydrocarbon product. It continues to be difficult to forecast and account for the risk posed by the COVID-19 pandemic.

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CONTENTS

1.	BACKGROUND AND HISTORY		6
2.	OUTLOOK AND OBJECTIVES		6
3.	PERFORMANCE HIGHLIGHTS		7
4.	RESULTS OF OPERATIONS		12
	4.1	Production	12
	4.2	Commodity Prices	12
	4.3	Oil Sales	15
	4.4	Royalties	16
	4.5	Risk Management Contracts	17
	4.6	Diluent Expense	19
	4.7	Transportation and Marketing Expense	19
	4.8	Operating Expenses	20
	4.9	Production Costs	21
	4.10	General & Administrative Expenses	22
	4.11	Interest and Finance Expenses	22
	4.12	Depletion and Depreciation	23
	4.13	Exploration Expenses	24
	4.14	Other (Income) and Expense	24
	4.15	Foreign Exchange Loss (Gain)	24
	4.16	Decommissioning Liability	25
	4.17	Net Income (Loss) and Comprehensive Income (Loss) and Adjusted EBITDA	25
5.	CAPITAL RESOURCES AND LIQUIDITY		26
	5.1	Long Term Debt	27
	5.2	Term Loan	27
	5.3	Working Capital (Deficit) and Adjusted Working Capital(1)	28
	5.4	Restricted Cash and Letter of Credit Facilities	28
	5.5	Expansion Marketing Contract	29
	5.6	Demo Marketing Contract	29
	5.7	Share Capital and Warrants	29
	5.8	Cash Flow Summary	31
	5.9	Property, Plant and Equipment Expenditures	32
	5.10	Cash Provided by Operating Activities and Adjusted Funds Flow(1)	33
6.	NON-GAAP MEASURES		34
7.	COMMITMENTS AND CONTINGENCIES		38
8.	ACCOUNTS RECEIVABLE		38
9.	CRITICAL ACCOUNTING POLICIES AND ESTIMATES		38
10.	OFF-BALANCE SHEET ARRANGEMENTS		39
11.	FORWARD LOOKING STATEMENTS		39
12.	ADDITIONAL INFORMATION		40

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FIGURES

Figure 1:	Financial & Operational Highlights	11
Figure 2:	Liquidity and Balance Sheet	11
Figure 3:	Production and Steam-Oil Ratio	12
Figure 4:	Benchmark Pricing	15
Figure 5:	Oil Sales	16
Figure 6:	Royalties	16
Figure 7:	Financial Management Contracts	17
Figure 8:	Outstanding Financial Risk Management Contracts at June 30, 2023	18
Figure 9:	Outstanding Physical Contracts at June 30, 2023	18
Figure 10:	Realized and Unrealized Gain (Loss) on Commodity Price Risk Management Contracts	19
Figure 11:	Diluent Expense	19
Figure 12:	Transportation and Marketing Expenses	20
Figure 13:	Operating Expenses	21
Figure 14:	Production Costs	22
Figure 15:	General & Administrative Expenses	22
Figure 16:	Interest and Finance Expenses	23
Figure 17:	Depletion and Depreciation Expense	24
Figure 18:	Exploration Expenses	24
Figure 19:	Other (Income) and Expense	24
Figure 20:	Foreign Exchange Loss (Gain)	25
Figure 21:	Reconciliation of Decommissioning Liability	25
Figure 22:	Net Income (Loss) and Comprehensive Income (Loss) and Adjusted EBITDA	26
Figure 23:	Reconciliation of Working Capital (Deficit) to Adjusted Working Capital(1)	28
Figure 24:	Outstanding Common Shares	30
Figure 25:	Weighted Average Shares Outstanding	30
Figure 26:	Bondholder Warrants Outstanding	31
Figure 27:	Performance Warrants Outstanding	31
Figure 28:	Cash Flow Summary	32
Figure 29:	Property, Plant and Equipment Expenditures	33
Figure 30:	Reconciliation of Cash Provided by Operating Activities to Adjusted Funds Flow(1)	34
Figure 31:	Reconciliation of Change in Cash and Cash Equivalents to Excess Cash Flow	35
Figure 32:	Reconciliation of Long-Term Debt to Net Debt	36
Figure 33:	Summary of Quarterly Results	37
Figure 34:	Commitments	38
Figure 35:	Accounts Receivable	38

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1. BACKGROUND AND HISTORY

Greenfire and its subsidiaries are based in Canada. The Company’s registered office is located in Calgary, Alberta. The Company’s principal business is the sustainable production and development of upstream energy resources from the oil sands in Canada, using in situ thermal oil production extraction techniques such as steam assisted gravity drainage (“SAGD”). Since 2020, Greenfire has acquired multiple assets through a sequence of business combinations and amalgamations. The assets acquired pursuant to such acquisitions are currently held in a newly formed partnership structure within Greenfire.

Greenfire Hangingstone Operating Corporation (“GHOPCO”) was an unaffiliated corporation that acquired the Hangingstone Demonstration Facility (the “Demo Asset”) from Japan Canada Oil Sands Limited (“JACOS”) in 2018. Prior thereto, JACOS operated the Demo Asset since 1999, before shutting down operations in 2016 during the wildfires in Alberta that year. The Demo Asset is a SAGD bitumen production facility with an estimated debottlenecked capacity of 7,500 barrels per day (“bbls/d”), located approximately 50 kilometers southwest of Fort McMurray, Alberta, Canada. GHOPCO successfully restarted production in 2018 and operated the facility until May 2020, when GHOPCO shutdown operations subsequent to the onset of the COVID-19 global pandemic and formally filed for insolvency on October 8, 2020.

Greenfire Acquisition Corporation (“GAC”), was incorporated on November 2, 2020 for the purpose of acquiring the Demo Asset out of GHOPCO’s insolvency proceedings. On April 5, 2021, GAC closed the acquisition of the Demo Asset from GHOPCO. The majority of former GHOPCO employees were successfully retained as part of the acquisition and transition through the insolvency process. GAC was subsequently amalgamated with Greenfire Resources Operating Corporation, a wholly owned subsidiary of the Company.

On September 17, 2021, Greenfire closed the acquisition of JACOS. JACOS’s primary asset was a 75% working interest in the Hangingstone Expansion Facility (the “Expansion Asset”). The majority of former JACOS employees were successfully retained as part of the acquisition and subsequent integration of operations. The Expansion Asset is a SAGD bitumen production facility with an estimated debottlenecked capacity of 35,000 bbls/d, located approximately five kilometers to the southeast of the Demo Asset.

Greenfire is currently an intermediate sized and low-cost oil sands producer focused on responsible energy development in Canada. Greenfire remains an operationally focused company, with an emphasis on an entrepreneurial environment and employee ownership. Greenfire continues to seek a range of attractive investment opportunities in the oil and gas sector in Canada.

2. OUTLOOK AND OBJECTIVES

Greenfire plans to continue to sustainably increase production at the Expansion Asset by optimizing the site’s existing infrastructure, while employing a safe, efficient, and capital-disciplined operating approach that the Company has demonstrated at the Demo Asset. Leveraging its oil sands operating expertise, Greenfire expects that over time these improvements should lead to an enhancement in profitability.

Supported by operational strength and based on current forecasted prices, Greenfire plans to further deleverage its balance sheet in the near term, while in the mid to longer term, the Company will continue to evaluate potential avenues for capital acceleration to attain additional step change growth, whether internally or externally.

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During the three months ended June 30, 2022, the Company amended its indenture governing the “Notes”⁽¹⁾ (please see subsection 5.1 Long Term Debt) to allow for an incremental US$60 million in capital investment to be spent over a period of 24 months, which is expected to be directed toward further debottlenecking the Company’s existing surface facilities to sustain higher production rates. This capital plan includes alleviating current restrictions on water handling, as well as a reduction in inlet pressure and temperature to facilitate greater drawdown on existing wells at the Expansion Asset. Additionally, capital will be spent on debottlenecking non- condensable gas (“NCG”) co-injection capability at the Expansion Asset, providing additional cooling to the production emulsion stream at the Demo Asset and the Expansion Asset, a partial recommissioning of an existing plant at the Demo Asset to increase oil handling capacity, as well as an expansion of pipeline egress capacity at the Expansion Asset. Furthermore, the aforementioned capital plan will include investment in drilling five redevelopment infill wells⁽²⁾ (“Refill Wells”) at the Expansion Asset that are anticipated to have higher production rates, combined with lower produced water ratios relative to existing producing wells. Additionally, the Company expects to recognize savings on drilling, wellhead, and facilities costs on the Refill Wells, compared to standard infill producer wells.

In December 2022, the Company and M3-Brigade Acquisition III Corp., a New York Stock Exchange listed special purpose acquisition company, entered into a definitive agreement for a business combination (the “Business Combination”), which valued Greenfire at US$950 million total enterprise value. Following completion of the Business Combination, Greenfire Resources Ltd. (the “Combined Company”) is expected to continue to be managed by Greenfire’s current executive team. On April 21, 2023, we filed a Registration Statement on Form F- 4 with the United States Securities and Exchange Commission related to the Business Combination. We currently anticipate the completion of the Business Combination in the third quarter of 2023 and commencement of trading on the New York Stock Exchange. The Combined Company expects to remain focused on optimizing Greenfire’s existing production and facilities, with the objective of further enhancing its adjusted funds flow⁽³⁾, deleverage its balance sheet in the near term and return capital to its stakeholders over time.

3. PERFORMANCE HIGHLIGHTS

For the three months ended June 30, 2023, operational and financial highlights include:

● The Company achieved production of 18,036 bbls/d with a steam-oil ratio⁽⁴⁾ of 4.16 for the three months ended June 30, 2023, compared to 21,740 bbls/d with a steam-oil ratio⁽⁴⁾ of 3.45 from the same period of 2022. The decrease in production during the three months ended June 30, 2023, relative to the same period in 2022, was due to a combination of declining reservoir pressure resulting from short-term limitations of NCG availability for reservoir injection and unplanned downtime at the Expansion Asset. The Company’s current capital plan includes debottlenecking NCG co-injection at the Expansion Asset to increase the reservoir pressure and drilling of five Refill Wells. The decrease in production for the three months ended June 30, 2023 compared to the same period in 2022 was partially offset by a slight increase in production at the Demo Asset, mainly due to the continued optimization of water disposal wells that debottleneck water handling capabilities.

⁽¹⁾ During the year ended December 31, 2021, the Company issued US$312.5 million of senior secured notes (the “Notes”).

⁽²⁾ Re-enter the existing steam-assisted gravity drainage (‘SAGD’) producers to drill new refill producers between two existing wellpairs to produce incremental pre-heated bitumen SAGD wellpairs.

⁽³⁾ Non-GAAP measures do not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Non-GAAP Measures section in this MD&A for further information.

⁽⁴⁾ Steam-oil ratio is the amount of steam used in operations for injection into the bitumen reservoir divided by the amount of bitumen produced.

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● Oil sales for the three months ended June 30, 2023 was $173.6 million, which was lower than $315.8 million in the same period of 2022, was primarily due to lower Western Canadian Select (“WCS”) benchmark oil prices and lower production, which was a result of declining reservoir pressure resulting from short-term limitations of NCG availability for reservoir injection and unplanned downtime at the Expansion Asset.

● Operating expenses during the three months ended June 30, 2023 was $21.79/bbl compared to $22.89/bbl in the same period in 2022. The lower operating expenses per barrel in the second quarter of 2023 relative to the same period in 2022, was primarily the result of lower natural gas prices in 2023, partially offset by the recognition of higher greenhouse gas emission fees of $1.21/bbl and lower sales volumes in 2023.

● Cash provided by operating activities during the three months ended June 30, 2023 was $23.6 million, compared to cash provided by operating activities of $67.5 million in the same period of 2022. Cash provided by operating activities in the three months ended June, 30 2023 was less than cash provided by operating activities in the same period of 2022, primarily due to lower oil sales and WCS benchmark oil prices. Lower oil sales was a result of declining reservoir pressure resulting from short-term limitations of NCG availability for reservoir injection and unplanned downtime at the Expansion Asset. Cash provided by operating activities is the most directly comparable GAAP measure for adjusted funds flow⁽¹⁾, which is a non-GAAP measure.

o Adjusted funds flow⁽¹⁾ for the three months ended June 30, 2023 was $19.6 million, compared to $50.0 million from the same period in 2022. The decrease in adjusted funds flow⁽¹⁾ during the second quarter of 2023 was primarily the result of lower oil sales and WCS benchmark oil prices. Lower oil sales was a result of declining reservoir pressure resulting from short-term limitations of NCG availability for reservoir injection and unplanned downtime at the Expansion Asset. The decrease in adjusted funds flow⁽¹⁾ was partially offset by lower property, plant and equipment spend during the three months ended June 30, 2023.

● Net income (loss) and comprehensive income (loss) is the most directly comparable GAAP measure for adjusted EBITDA⁽¹⁾, which is a non-GAAP measure. See the section entitled “Non-GAAP Measures and Other Performance Measures” for a discussion of adjusted EBITDA⁽¹⁾ and other non-GAAP measures. Adjusted EBITDA⁽¹⁾ for the three months ended June 30, 2023 was $34.4 million compared to $70.5 million in the same period of 2022. The decrease in adjusted EBITDA⁽¹⁾ in the second quarter of 2023, relative to the same period in 2022, was primarily the result of lower oil sales and lower WCS benchmark oil prices. Lower oil sales was a result of declining reservoir pressure resulting from short-term limitations of NCG availability for reservoir injection and unplanned downtime at the Expansion Asset.

● Property, plant and equipment expenditures were $1.9 million for the three months ended June 30, 2023 compared to $7.7 million in the same period of 2022.

o Of the total property, plant and equipment expenditures during the three months ended June 30, 2023, $1.0 million was spent on initiating a Refill Well program at the Expansion asset which is designed to allow incremental bitumen production. Additionally, $0.4 million in property, plant and equipment expenditures was spent to refurbish and restart oil handling equipment at the Demo Asset in order to process greater production volume.

⁽¹⁾ Non-GAAP measures do not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Non-GAAP Measures section in this MD&A for further information.

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● Change in cash and cash equivalents during the three months ended June 30, 2023 was an increase of $14.5 million, compared to a decrease of $10.4 million in the same period in 2022. Despite higher commodity prices and production during the three months ended June 30, 2022, relative to the same period in 2023, change in cash and cash equivalents was higher in the second quarter of 2023 primarily due to a debt principal repayment on May 26, 2022 of approximately $60.7 million whereas there was no debt principal repayment in the second quarter of 2023. In addition, change in cash and cash equivalents during the second quarter of 2023 was depressed by lower oil sales and lower WCS benchmark oil prices. Lower oil sales was a result of declining reservoir pressure resulting from short-term limitations of NCG availability for reservoir injection and unplanned downtime at the Expansion Asset. Change in cash and cash equivalents is the most directly comparable GAAP measure to excess cash flow⁽¹⁾⁽²⁾, which is a non-GAAP measure. Excess cash flow⁽¹⁾⁽²⁾ was $22.5 million during the three months ended June 30, 2023, compared to $58.4 million in the same period in 2022, primarily due to lower oil sales and lower WCS benchmark oil prices. Lower oil sales was a result of declining reservoir pressure resulting from short-term limitations of NCG availability for reservoir injection and unplanned downtime at the Expansion Asset.

For the six months ended June 30, 2023, operational and financial highlights include:

● The Company achieved production of 19,304 bbls/d with a steam-oil ratio⁽³⁾ of 3.94 for the six months ended June 30, 2023, compared to 22,321 bbls/d with a steam-oil ratio⁽³⁾ of 3.35 from the same period in 2022. The decrease in production during the six months ended June 30, 2023, was due to a combination declining reservoir pressure resulting from short-term limitations of NCG availability for reservoir injection and unplanned downtime at the Expansion Asset. The Company’s current capital plan includes debottlenecking NCG co-injection at the Expansion Asset to increase the reservoir pressure and drilling of five Refill Wells. The decrease in production for the six months ended June 30, 2023 compared to the same period in 2022 was partially offset by a slight increase in production at the Demo Asset, mainly due to the continued optimization of water disposal wells that debottleneck water handling capabilities.

● Oil sales for the six months ended June 30, 2023 was $353.3 million, which was lower than $608.6 million in the same period of 2022, primarily due to lower oil sales and lower WCS benchmark oil prices. Lower oil sales was a result of declining reservoir pressure resulting from short-term limitations of NCG availability for reservoir injection and unplanned downtime at the Expansion Asset.

● Operating expenses during the six months ended June 30, 2023 was $21.29/bbl compared to $20.04/bbl in the same period of 2022. The higher operating expenses per barrel in the six months ended June 30, 2023 relative to the same period of 2022, was primarily the result of the recognition of higher greenhouse gas emission fees of $1.25/bbl, as well as lower sales volumes, partially offset by lower natural gas prices in 2023.

⁽¹⁾ Non-GAAP measures do not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Non-GAAP Measures section in this MD&A for further information.

⁽²⁾ If the Company and its Restricted Subsidiaries have excess cash flow for any six-month period, then, within 65 days after the end of any such applicable period, the Company will be required to redeem the maximum principal amount of Notes that may be redeemed with 75% of such excess cash flow for such period.

⁽³⁾ Steam-oil ratio is the amount of steam used in operations for injection into the bitumen reservoir divided by the amount of bitumen produced.

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● Cash provided by operating activities during the six months ended June 30, 2023 was $19.1 million, compared to cash provided by operating activities of $98.2 million in the same period of 2022. Cash provided by operating activities in the six months ended June, 30 2023 was less than cash provided by operating activities in the same period in 2022, primarily due to lower oil sales and lower WCS benchmark oil prices. Lower oil sales was a result of declining reservoir pressure resulting from short-term limitations of NCG availability for reservoir injection and unplanned downtime at the Expansion Asset. Cash provided by operating activities is the most directly comparable GAAP measure for adjusted funds flow⁽¹⁾, which is a non-GAAP measure.

o Adjusted funds flow⁽¹⁾ for the six months ended June 30, 2023 was $17.8 million, compared to $106.7 million from the same period in 2022. The decrease in adjusted funds flow⁽¹⁾ during the six months ended June 30, 2023, compared to the same period in 2022, was primarily the result of lower oil sales and lower WCS benchmark oil prices. Lower oil sales was a result of declining reservoir pressure resulting from short-term limitations of NCG availability for reservoir injection and unplanned downtime at the Expansion Asset. The decrease was partially offset by lower property, plant and equipment spend during the six months ended June 30, 2023.

● Net income (loss) and comprehensive income (loss) is the most directly comparable GAAP measure for adjusted EBITDA⁽¹⁾, which is a non-GAAP measure. See the section entitled “Non-GAAP Measures and Other Performance Measures” for a discussion of adjusted EBITDA⁽¹⁾ and other non-GAAP measures. Adjusted EBITDA⁽¹⁾ for the six months ended June 30, 2023 was $47.4 million compared to $146.9 million in the same period of 2022. The decrease in adjusted EBITDA⁽¹⁾ for the six months ended June 30, 2023, relative to 2022, was primarily the result of lower oil sales and lower WCS benchmark oil prices. Lower oil sales was a result of declining reservoir pressure resulting from short-term limitations of NCG availability for reservoir injection and unplanned downtime at the Expansion Asset.

● Property, plant and equipment expenditures were $4.4 million for the six months ended June 30, 2023 compared to $12.9 million in the same period of 2022.

o Of the total property, plant and equipment expenditures in the six months ended June 30, 2023, $2.1 million was spent on various small projects at both the Expansion Asset and Demo Asset. Additionally, $1.3 million was spent to refurbish and restart oil handling equipment at the Demo Asset in order to process greater production volume, as well as $1.0 million was spent on initiating a Refill Well program at the Expansion asset that should facilitate incremental bitumen production.

● Change in cash and cash equivalents during the six months ended June 30, 2023 was an increase of $1.5 million, compared to an increase of $12.5 million in the same period in 2022. Change in cash and cash equivalents was lower during the six months ended June 30, 2023 relative to the same period in 2022, primarily due to lower oil sales and lower WCS benchmark oil prices. Lower oil sales was a result of declining reservoir pressure resulting from short-term limitations of NCG availability for reservoir injection and unplanned downtime at the Expansion Asset. Change in cash and cash equivalents is the most directly comparable GAAP measure to excess cash flow⁽¹⁾⁽²⁾, which is a non-GAAP measure. Excess cash flow⁽¹⁾⁽²⁾ was $13.6 million during the six months ended June 30, 2023, compared to $86.5 million in the same period in 2022, primarily due to lower oil sales and lower WCS benchmark oil prices. Lower oil sales was a result of declining reservoir pressure resulting from short-term limitations of NCG availability for reservoir injection and unplanned downtime at the Expansion Asset.

⁽¹⁾ Non-GAAP measures do not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Non-GAAP Measures section in this MD&A for further information.

⁽²⁾ If the Company and its Restricted Subsidiaries have excess cash flow for any six-month period, then, within 65 days after the end of any such applicable period, the Company will be required to redeem the maximum principal amount of Notes that may be redeemed with 75% of such excess cash flow for such period.

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Figure 1: Financial & Operational Highlights

	Three months ended June 30,					Six months ended June 30,
($ thousands, unless otherwise noted)	2023		2022			2023		2022
Expansion
Bitumen production (bbls/d)		13,939		17,910			15,114		18,309
Demo
Bitumen production (bbls/d)		4,097		3,830			4,190		4,012
Consolidated
Bitumen production (bbls/d)		18,036		21,740			19,304		22,321
Steam-oil ratio		4.16		3.45			3.94		3.35
Bitumen sales (bbls/d)		17,992		21,331			19,573		22,573
Oil sales		173,605		315,794			353,273		608,558
Oil sales ($/bbl)		75.78		120.99			70.38		109.40
Cash provided (used) by operating activities		23,640		67,553			19,144		98,241
Property, plant and equipment expenditures		1,911		7,706			4,428		12,906
Adjusted funds flow(1)		19,634		50,039			17,846		106,669
Change in cash and cash equivalents		14,479		(10,399	)		1,519		12,506
Excess cash flow(1)		22,479		58,392			13,569		86,514
Net Income (loss) and Comprehensive Income (Loss)		24,355		45,592			7,677		(56,953	)
Per share – basic		2.72		5.08			0.86		(6.36	)
Per share – diluted		1.89		3.53			0.60		(6.36	)
Adjusted EBITDA(1)		34,389		70,445			47,447		146,854
Common shares outstanding, end of period		8,951,624		8,951,624			8,951,624		8,951,624
Weighted average shares outstanding- diluted		12,890,944		12,878,977			12,888,851		12,707,754

⁽¹⁾ Non-GAAP measures do not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Non-GAAP Measures section in this MD&A for further information.

Figure 2: Liquidity and Balance Sheet

	As at		As at
	June 30,		December 31,
As at ($ thousands)	2023		2022
Cash and cash equivalents		36,882		35,363
Restricted cash		47,363		35,313
Face value of Long-term debt(1)		288,547		295,173

⁽¹⁾ As at June 30, 2023, the Notes were translated in Canadian dollars at the period end exchange rate of US$1.00 = CAD$1.3240 (As at December 31, 2022 – US$1.00 = CAD$1.3544).

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4. RESULTS OF OPERATIONS

4.1 Production

The Company’s average bitumen production of 18,036 bbls/d for the three months ended June 30, 2023 was lower than 21,740 bbls/d from the same period in 2022.

The Expansion Asset’s average bitumen production of 13,939 bbls/d for the three months ended June 30, 2023 was lower than 17,910 bbls/d from the same period in 2022, due to a combination of declining reservoir pressure resulting from short-term limitations and NCG availability for reservoir injection and unplanned downtime at the Expansion Asset.

The Demo Asset’s average bitumen production of 4,097 bbls/d for the three months ended June 30, 2023 was higher than 3,830 bbls/d from the same period in 2022. The Company has been able to maintain relatively flat to slightly higher production levels at the Demo Asset primarily as a result of its continued efforts in optimizing water disposal wells and facilities.

The Company’s average bitumen production of 19,304 bbls/d for the six months ended June 30, 2023 was lower than 22,321 bbls/d from the same period in 2022.

The Expansion Asset’s average bitumen production of 15,114 bbls/d for the six months ended June 30, 2023 was lower than 18,309 bbls/d from the same period in 2022, due to a combination of declining reservoir pressure resulting from short-term limitations and NCG availability for reservoir injection and unplanned downtime at the Expansion Asset.

The Demo Asset’s average bitumen production of 4,190 bbls/d for the six months ended June 30, 2023 was higher than 4,012 bbls/d from the same period in 2022. The Company has been able to maintain relatively flat to slightly higher production levels at the Demo Asset primarily as a result of its continued efforts in optimizing water disposal wells and facilities.

Figure 3: Production and Steam-Oil Ratio

	Three months ended June 30,				Six months ended June 30,
(Average barrels per day, unless otherwise noted)	2023		2022		2023		2022
Expansion
Bitumen production		13,939		17,910		15,114		18,309
Steam-oil ratio		3.81		2.95		3.54		2.90
Demo
Bitumen production		4,097		3,830		4,190		4,012
Steam-oil ratio		5.73		6.51		5.85		6.07
Consolidated
Bitumen production		18,036		21,740		19,304		22,321
Steam-oil ratio		4.16		3.45		3.94		3.35

4.2 Commodity Prices

The prices received for Greenfire’s crude oil production directly impact earnings, cash flow and financial position.

Greenfire Resources Inc. 2023 Q2 Management’s Discussion and Analysis | 12

WTI

The price of West Texas Intermediate (“WTI”) is the current benchmark for mid-continent North American crude oil prices at Cushing Oklahoma. Crude oil prices strengthened through the first half of 2022 as the global recovery from the Covid-19 pandemic continued, and the price of WTI further increased after the Russia and Ukraine conflict began in February 2022, which disrupted global oil supplies as a result of sanctions applied to Russian oil production and geopolitical uncertainty. In the second quarter of 2023, WTI prices declined compared with the first quarter of 2023 and all quarters in 2022 due to concerns over a slowdown in the global economy and further increases in interest rates in the United States and Europe. The average price of WTI for the three months ended June 30, 2023, was the lowest since the outbreak of the Russia-Ukraine war after the conflict put upward pressure on commodity prices. WTI pricing weakened further in the first half of 2023 due to these recessionary concerns and the potential negative impact on oil demand as a result. The average US$ WTI benchmark price dropped to US$73.78/bbl for the three months ended June 30, 2023 compared to US$108.41/bbl in the same period in 2022. For the six months ended June 30, 2023 the average US$ WTI benchmark price dropped to US$74.95/bbl compared to US$101.35/bbl in the same period in 2022.

WCS

Canadian heavy oil trades at a discount to WTI, with WCS the broadly used benchmark that reflects heavy oil prices at Hardisty, Alberta. WCS differentials⁽¹⁾ for Canadian oil prices relative to WTI fluctuate from period to period based on production, inventory levels, infrastructure egress capacity, and refinery demand in Canada and the United States, among other factors. Year over year, the WCS heavy oil price decreased to US$58.64/bbl during the three months ended June 30, 2023 from US$95.61/bbl in the same period in 2022. For the six months ended June 30, 2023, the WCS heavy oil price decreased to US$54.94 compared to US$87.68/bbl in the same period in 2022.

The primary factor for the lower WCS oil price during the three months ended June 30, 2023 was weaker WTI pricing. In the six months ended June 30, 2023 the WTI-WCS differential widened to US$20.01/bbl compared to US$13.67/bbl in the same period in 2022 largely as a result of reduced demand due to Strategic Petroleum Reserve releases, and unplanned refinery outages. The WCS differential to WTI of US$15.14/bbl during the three months ended June 30, 2023 was wider than the differential of US$12.80/bbl during the same period in 2022. Strong refinery demand, limited Enbridge mainline apportionment and demand for heavy oil in the US Gulf Coast contributed to the strength in the WCS differential in the three months ended June 30, 2022. WCS differentials were reasonably strong in the second quarter of 2023 as reduced apportionment, increased Gulf Coast demand and refineries returning from unplanned shutdowns helped improve the market for Canadian heavy compared to the winter months.

WDB

Greenfire produces Western Canada Dilbit Blend (“WDB”) at the Expansion Asset. WDB as a blended stream was introduced in late 2017, and is a blend comprised of Sunrise Dilbit Blend (“SDB”), Hangingstone Dilbit Blend (“HDB”), and Leismer Corner Blend (“LCB”). These streams are produced using SAGD in-situ extraction methods from the Athabasca region and transported to Enbridge’s Edmonton Terminal where it is blended. WDB is not part of the Enbridge Pooling Program and is a heavier blend than WCS. WDB typically trades at a differential below the WCS benchmark price and has generally correlated with WCS differential movements. The WDB price was US$56.30/bbl for the three months ended June 30, 2023, compared to US$93.92/bbl during the same period in 2022. The WDB price was US$52.34/bbl for the six months ended June 30, 2023, compared to US$85.84/bbl during the same period in 2022.

⁽¹⁾ WCS Differential represents the benchmark for diluted bitumen produced out of the oil sands and trades in reference to the WTI benchmark price.

Greenfire Resources Inc. 2023 Q2 Management’s Discussion and Analysis | 13

Condensate

In order to facilitate pipeline transportation of bitumen, the Company uses condensate as diluent for blending at the Expansion Asset. Condensate is locally sourced at Edmonton and delivered to the Expansion facility via the Inter Pipeline Polaris Pipeline. The price of condensate has generally correlated with the price of WTI and on average is within +5%/-5% of the WTI price. There has been less seasonality in recent pricing, however, demand for condensate as a diluent has generally been higher in the winter months due to increased diluent requirements in colder temperatures relative to warmer summer months. The Edmonton Condensate (C5+) price for the three months ended June 30, 2023 was US$72.40/bbl, compared to US$108.33/bbl during the same period in 2022. The C5+ price for the six months ended June 30, 2023 was US$76.19/bbl, compared to US$102.35/bbl during the same period in 2022. The lower condensate pricing for the second quarter and the first half of 2023 relative to 2022 was primarily a result of lower WTI pricing combined with a reduction in international demand.

Non-Diluted Bitumen

Greenfire produces non-diluted bitumen at the Demo Asset. Each barrel can be transported from the Demo Asset to several locations, including both pipeline and rail sales points, depending on the economics of each option at the time of sale. At pipeline connected sales points, the Demo Asset bitumen is blended with diluent to reach pipeline specifications. At rail connected terminals, the Demo Asset bitumen is moved into railcars and transported to its final sales destination, generally without the need to blend with diluent. The pricing of the Demo Asset sales bitumen is dependent on quality differentials, condensate pricing, pipeline and rail transportation costs and trucking distance that apply at each sales point. In mid-October 2022, the Company commissioned the bitumen truck off-loading facility (“Truck Rack”) at the Expansion Asset that can receive up to approximately 5,000 bbls/d of bitumen production from the Demo Asset that is then transported via pipeline. In the three months ended June 30, 2023, the Company transported 3,134 bbls/d to the Expansion Asset Truck Rack at more favourable economics than transporting to long-haul pipeline connected destinations due to reduced transportation costs.

Natural Gas

Natural gas is a primary energy input cost for the Company, which is used as fuel to generate steam for SAGD operations. Greenfire purchases Alberta Energy Company (“AECO”) gas, which is the Western Canadian benchmark for natural gas. The AECO Hub gas storage facility in southern Alberta is one of the largest natural gas trading hubs in North America, with its substantial production and storage capability and extensive network of export pipelines. This hub serves as the reference point for establishing the NOVA Inventory Transfer (“AB- NIT”) price for users of the transmission pipelines in the province. Gas prices are often quoted in terms of the basis differential between AECO prices and Henry Hub prices in Louisiana, United States. The AECO natural gas price decreased to $2.32 per gigajoule (“GJ”) during the three months ended June 30, 2023, compared to $6.86 per GJ during the same period in 2022. The AECO natural gas price also decreased to $2.67 per GJ during the six months ended June 30 2023, compared to $5.68 per GJ during the same period in 2022. The decrease in gas prices was primarily due to lower global gas prices after a warmer-than-forecasted winter of 2022/2023 and anticipated high storage inventories during the 2023 inventory building season.

Greenfire Resources Inc. 2023 Q2 Management’s Discussion and Analysis | 14

Power

Electric power prices impact energy operating expenses. The Alberta power pool price increased to $159.87 per megawatt hour (“MWH”) during the three months ended June 30, 2023 compared to $121.51 per MWH during the same period in 2022. Power pool prices also increased to $150.64 per MWH during the six months ended June 30, 2023 compared to $105.99 per MWH during the same period in 2022. The return of Power Purchase Agreements (“PPAs”) to suppliers in 2019 has allowed generators to more competitively tender their power, higher carbon tax costs, and the average power demands for Alberta have been increasing while traditional supply sources such as coal have been retired, which has resulted in higher prices overall. Wind comprises approximately one-third of the current power generation market in Alberta and reduced supply may also continue to have a meaningful impact on power prices.

Figure 4: Benchmark Pricing

	Three months ended June 30,						Six months ended June 30,
Benchmark Pricing	2023			2022			2023			2022
Crude oil (US$/bbl)
WTI(1)		73.78			108.41			74.95			101.35
WCS differential to WTI		(15.14	)		(12.80	)		(20.01	)		(13.67	)
WCS(2)		58.64			95.61			54.94			87.68
WDB(3)		56.30			93.92			52.34			85.84
Condensate at Edmonton		72.40			108.33			76.19			102.35
Natural gas ($/GJ)
AECO 5A		2.32			6.86			2.69			5.68
Electricity ($/MWh)
Alberta power pool		159.87			121.51			150.64			105.99
Foreign exchange rate(4)
US$:CAD$		1.3430			1.2766			1.3475			1.2714

⁽¹⁾ As per NYMEX oil futures contract

⁽²⁾ Reflects heavy oil prices at Hardisty, Alberta

⁽³⁾ Blend stream comprised of Sunrise Dilbit Blend, Hangingstone Dilbit Blend, and Leismer Corner Blend.

⁽⁴⁾ Annual or quarterly average exchange rates as per the Bank of Canada.

4.3 Oil Sales

Oil Sales

Greenfire’s oil sales include WDB from the Expansion Asset and non-diluted bitumen sales from the Demo Asset. Commencing in the fourth quarter of 2022, a portion of the Demo Asset’s bitumen production was sold into the WDB stream via the newly commissioned Truck Rack with the balance trucked to other pipeline connected sales streams.

During the three months ended June 30, 2023, the Company recorded oil sales of $173.6 million, compared to $315.8 million during the same period in 2022. Lower oil sales was a result of lower WCS benchmark prices and lower production, due to a combination of declining reservoir pressure resulting from short-term limitations and NCG availability for reservoir injection and unplanned downtime at the Expansion Asset.

During the six months ended June 30, 2023, the Company recorded oil sales of $353.3 million, compared to

$608.6 million during the same period in 2022. Lower oil sales was a result of lower WCS benchmark prices and lower production, due to a combination of declining reservoir pressure resulting from short-term limitations and NCG availability for reservoir injection and unplanned downtime at the Expansion Asset.

Greenfire Resources Inc. 2023 Q2 Management’s Discussion and Analysis | 15

Figure 5: Oil Sales

	Three months ended June 30,				Six months ended June 30,
($ thousands, unless otherwise noted)	2023		2022		2023		2022
Oil Sales		173,605		315,794		353,273		608,558
- ($/bbl)		75.78		120.99		70.38		109.40

4.4 Royalties

Royalties paid by the Company are crown royalties to the Province of Alberta. Alberta oil sands royalty projects are based on government prescribed pre and post payout⁽¹⁾ royalty rates, which are determined on a sliding scale using the Canadian dollar equivalent WTI benchmark price.

Royalties for a pre-payout project are based on a monthly calculation that applies a royalty rate (ranging from one percent to nine percent, based on the Canadian dollar equivalent WTI benchmark price) to the gross revenues from the project. Gross revenues are a function of sales revenues less diluent costs and transportation costs. The Expansion Asset is a pre-payout project.

Royalties for a post-payout project are based on an annualized calculation that uses the greater of: (1) the gross revenues multiplied by the applicable royalty rate (one percent to nine percent, based on the Canadian dollar equivalent WTI benchmark price); or (2) the net revenues of the project multiplied by the applicable royalty rate (25 percent to 40 percent, based on the Canadian dollar equivalent WTI benchmark price). Net revenues are a function of sales revenues less diluent costs, transportation costs, and allowable operating and capital costs. While the Demo Asset is a post-payout project, due to the carry forward of previous years costs, it is currently assessed under scenario (1) discussed above. The Company’s Demo Asset may become assessable under scenario (2) in 2024, depending on actual production performance, oil prices and costs.

Royalties for the three months ended June 30, 2023 of $3.54/bbl were lower compared to the same period in 2022 at $9.68/bbl, primarily due to lower WTI benchmark oil prices.

Royalties for the six months ended June 30, 2023 of $2.91/bbl were lower compared to the same period in 2022 at

$7.50/bbl, primarily due to lower WTI benchmark oil prices.

Figure 6: Royalties

	Three months ended June 30,				Six months ended June 30,
($ thousands, unless otherwise noted)	2023		2022		2023		2022
Royalties		5,793		18,788		10,295		30,628
- ($/bbl)		3.54		9.68		2.91		7.50

⁽¹⁾ The payout status will either be pre-payout (when cumulative costs exceed cumulative revenues) or post-payout (once cumulative revenues first equal or exceed cumulative costs).

Greenfire Resources Inc. 2023 Q2 Management’s Discussion and Analysis | 16

4.5 Risk Management Contracts

The Company utilizes risk management contracts to manage commodity price risk on oil sales and operating expenses. The calculated fair value of the risk management contracts relies on external observable market data including quoted forward commodity prices. The resulting fair value estimates may not be indicative of the amounts realized at settlement and as such are subject to measurement uncertainty.

During the three months ended September 30, 2022, the Company’s obligations under its Notes, as outlined in subsection 5.1 Long Term Debt, were updated to include a requirement to implement a 12-month (previously 18- month) forward commodity price risk management program encompassing not less than 50% (previously 75%) of the hydrocarbon output under the proved developed producing reserves forecast in the most recent reserves report, as determined by a qualified and independent reserves evaluator. This obligation is tested at the end of every fiscal quarter for the duration of time that the Notes remain outstanding.

The Company’s commodity price risk management program does not involve margin accounts that require posting of margin with increased volatility in underlying commodity prices. Financial risk management contracts are measured at fair value, with gains and losses on re-measurement included in the consolidated statements of comprehensive income (loss) in the period in which they arise.

Financial contracts

The Company’s financial risk management contracts are subject to master netting agreements that create the legal right to settle the instruments on a net basis. The fair value of the risk management contracts resulted in a net current liability of $10.8 million at June 30, 2023.

The following table summarizes the gross asset and liability positions of the Company’s individual risk management contracts that are offset in the consolidated balance sheets:

Figure 7: Financial Management Contracts

	As at June 30,							As at December 31,
		2023						2022
($ thousands)		Asset			Liability			Asset			Liability
Gross amount			104			(10,951	)		(21,375	)		(48,379	)
Amount offset			(104	)		104			21,375			21,375
Risk management contracts			-			(10,847	)		-			(27,004	)

Financial contracts settled in the period result in realized gains or losses based on the market price compared to the contract price and the notional volume outstanding. Changes in the fair value of unsettled financial contracts are reported as unrealized gains or losses in the period as the forward markets for commodities fluctuate and as new contracts are executed.

Greenfire Resources Inc. 2023 Q2 Management’s Discussion and Analysis | 17

Figure 8: Outstanding Financial Risk Management Contracts at June 30, 2023

	Natural Gas- Fixed Price Swap
Term	Volume (GJ/day)		Swap Price ($/GJ)
Q4 2023		305,000		2.97
Q1 2024		455,000		2.97

⁽¹⁾ Presented as weighted average prices.

	WTI- Put Options						WTI- Costless Collar
Term	Volume (bbls)		Strike Price (US$/bbl)		Volume (bbls)		Put Strike Price (US$/bbl)		Call Strike Price (US$/bbl)
Q3 2023		1,278,551	$	50.00		-		-		-
Q4 2023		371,169	$	50.00		742,337	$	50.00	$	108.25
Q1 2024		-		-		877,968	$	60.00	$	77.00
Q2 2024		-		-		877,968	$	60.00	$	74.55

Physical delivery purchase and sales contracts

The Company has entered into forward, fixed-priced, physical delivery, purchase and sales contracts to manage commodity price risk. These contracts are not considered to be derivatives and therefore not recorded at fair value. They are considered purchase and sales contracts for the Company’s own use and are recorded at cost at the time of transaction. Greenfire’s outstanding physical contracts are summarized in Figure 9.

Figure 9: Outstanding Physical Contracts at June 30, 2023

	WCS Differential- Fixed Price Swap					AECO- Fixed Price Swap
Term	Volume (bbls)		Swap Price(1) US$/bbl			Volume (GJ/day)		Swap Price ($/GJ)
Q3 2023		379,000	$	(14.92	)		-		-

⁽¹⁾ Presented as weighted average prices.

Realized and Unrealized Risk Management Contracts

In the three months ended June 30, 2023, we recorded total risk management contract gains of $4.4 million compared to total risk management contract losses of $29.1 million for the same period in 2022. The realized risk management contracts loss for the three months ended June 30, 2023 of $6.8 million ($57.3 million realized loss in the same period of 2022) was primarily a result of the market prices for WTI settling at levels above those set in the Company’s risk management contracts outstanding during the quarter, partially offset by gains due to the widening of WCS differentials. The unrealized gain on risk management contracts of $11.1 million for the three months ended June 30, 2023 ($28.2 million unrealized gain in the same period of 2022) was primarily a result of the settlement of the risk management contracts realized during the second quarter of 2023.

In the six months ended June 30, 2023, we recorded total risk management contract gains of $9.2 million compared to total risk management contract losses of $205.5 million for the same period in 2022. The realized risk management contracts loss for the six months ended June 30, 2023 of $7.0 million ($91.0 million realized loss in the same period of 2022) was primarily a result of the market prices for WTI settling at levels above those set in the Company’s risk management contracts outstanding during the first six months of 2022, partially offset by gains due to the widening of WCS differentials. The unrealized gain on risk management contracts of $16.2 million for the six months ended June 30, 2023 ($114.4 million unrealized loss in the same period of 2022) was primarily a result of the settlement of the risk management contracts realized during the first and second quarter of 2023. Please see subsection 4.5 Risk Management Contracts.

Greenfire Resources Inc. 2023 Q2 Management’s Discussion and Analysis | 18

Figure 10: Realized and Unrealized Gain (Loss) on Commodity Price Risk Management Contracts

	Three months ended June 30,						Six months ended June 30,
($ thousands)	2023			2022			2023			2022
Realized gain (loss)		(6,777	)		(57,263	)		(6,957	)		(91,043	)
Unrealized gain (loss)		11,134			28,182			16,157			(114,411	)
Risk management contracts gains (losses)		4,357			(29,081	)		9,200			(205,454	)
Realized gain (loss) ($/bbl)		(4.14	)		(29.50	)		(1.96	)		(22.28	)
Unrealized gain (loss) ($/bbl)		6.80			14.52			4.56			(28.00	)
Risk management contracts gains (losses) ($/bbl)		2.66			(14.98	)		2.60			(50.28	)

4.6 Diluent Expense

In order to facilitate pipeline transportation of bitumen, the Company uses condensate as diluent for blending at the Expansion Asset and for trucked volumes from the Demo Asset that are delivered to the Truck Rack that is located at Expansion. Greenfire’s diluent expense includes the cost of diluent plus the pipeline transportation of the diluent from Edmonton to the Expansion facility via the Inter Pipeline Polaris Pipeline.

Figure 11 shows the Company’s diluent expense for the three months and six months ended June 30, 2023 at $14.96/bbl and $20.31/bbl, respectively, which was higher than the comparative periods in 2022 at $12.49/bbl and $13.36/bbl, respectively. The factors driving the cost of diluent pricing are discussed in subsection 4.2 Commodity Prices.

Figure 11: Diluent Expense

	Three months ended June 30,				Six months ended June 30,
($ thousands, unless otherwise noted)	2023		2022		2023		2022
Diluent expense		74,027		105,195		175,883		216,176
- ($/bbl)		14.96		12.49		20.31		13.36

4.7 Transportation and Marketing Expense

Transportation expense at the Expansion Asset includes the costs to move production from the facility to the sales point in Edmonton, Alberta, via the Enbridge Lateral Pipeline and Enbridge Waupisoo Pipeline. At the Demo Asset, transportation expenses relate to the trucking of bitumen from the facility to various pipeline and rail sales points, including to the Truck Rack commissioned at the Expansion facility on October 12, 2022.

The Company’s Petroleum Marketer⁽¹⁾ provided debtor in possession financing during GHOPCO’s insolvency process, which the Company assumed the outstanding balance as a term loan upon the closing of the acquisition of the Demo Asset on April 5, 2021. The petroleum marketing contract with the Petroleum Marketer were for the exclusive petroleum production marketing rights over the production at the Demo Asset, whereby in addition to marketing fees, additional costs associated with the marketing contract include royalty incentive and performance fees, which are oil price and production volume dependent for the term of three years, ending on April 1, 2024.

⁽¹⁾ The Company entered into an arrangement whereby a large reputable international energy marketing company (“Petroleum Marketer”) would market and sell all production as per defined terms of agreement outlined in section 5.2 Term Loan, section 5.5 Expansion Marketing Contract, and section 5.6 Demo Marketing Contract.

Greenfire Resources Inc. 2023 Q2 Management’s Discussion and Analysis | 19

The Company also entered into a marketing contract with the Petroleum Marketer following the acquisition of JACOS for the exclusive petroleum production marketing rights of the production at the Expansion Asset’s marketing services, including the facilitation of all pipeline transportation and storage costs. This marketing contract has a term of five years after the first delivery of blend, which occurred in October 2021. Please see subsection 5.5 Expansion Marketing Contract for further discussion on the Company’s petroleum marketing contracts.

The Company’s transportation and marketing expense for the three months and six months ended June 30, 2023 was $8.30/bbl and $8.36/bbl, respectively, which was lower than the comparative periods in 2022 of $8.97/bbl and $8.80/bbl, respectively. The decrease was primarily due to lower oil transportation costs at the Demo Asset from utilizing the Truck Rack during the first and second quarters of 2023, which materially reduced trucking distances.

Figure 12: Transportation and Marketing Expenses

	Three months ended June 30,				Six months ended June 30,
($ thousands, unless otherwise noted)	2023		2022		2023		2022
Marketing fees(1)		3,005		3,306		6,005		6,863
Oil transportation expense		10,581		14,103		23,594		29,073
Transportation and marketing		13,586		17,409		29,600		35,936
Marketing fees(1) ($/bbl)		1.84		1.70		1.70		1.68
Oil transportation expense ($/bbl)		6.46		7.27		6.66		7.12
Transportation and marketing ($/bbl)		8.30		8.97		8.36		8.80

⁽¹⁾ Marketing fees include marketing fees paid to the Petroleum Marketer and terminal fees.

4.8 Operating Expenses

Operating expenses include energy operating expenses and non-energy operating expenses. Energy operating expenses reflect the cost of natural gas to generate steam and electricity to operate the Company’s facilities. Non-energy operating expenses relate to production-related operating activities, including staff, contractors and associated travel and camp costs, chemicals and treating, insurance, property tax, greenhouse gas fees, equipment rentals, maintenance and site administration, among other costs.

The Company’s energy operating expenses for the three months and six months ended June 30, 2023 were $8.72/bbl and $8.86/bbl, respectively, which was lower than the comparative periods in 2022 of $12.89/bbl and $10.86/bbl, respectively. The lower per barrel energy operating expenses in 2023, were primarily related to lower natural gas prices as prices were high in 2022 due to the onset of the conflict in Ukraine, which was partially offset by higher power prices in 2023. Please see subsection 4.2 Commodity Prices for a discussion on energy costs.

The Company’s non-energy operating expenses for the three months and six months ended June 30, 2023 were $13.06/bbl and $12.43/bbl, respectively, which was higher than the comparative periods in 2022 of $10.00/bbl and $9.18/bbl, respectively. The higher per barrel non-energy operating expenses in 2023 was primarily due to the recognition of greenhouse gas emission fees of $1.21/bbl for the three months ended June 30, 2023 and $1.25/bbl for the six months ended June 30, 2023, as well as inflationary pressures on the costs of goods and services combined with lower sales volumes.

Greenfire Resources Inc. 2023 Q2 Management’s Discussion and Analysis | 20

Figure 13: Operating Expenses

	Three months ended June 30,				Six months ended June 30,
($ thousands, unless otherwise noted)	2023		2022		2023		2022
Operating expenses - energy		14,285		25,020		31,396		44,392
Operating expenses - non-energy		21,389		19,416		44,043		37,498
Operating expenses		35,675		44,436		75,439		81,890
Operating expenses - energy ($/bbl)		8.72		12.89		8.86		10.86
Operating expenses - non-energy ($/bbl)		13.06		10.00		12.43		9.18
Operating expenses ($/bbl)		21.79		22.89		21.29		20.04

4.9 Production Costs

Production costs include operating expenses as set forth above but excludes ad valorem, severance, and similar production related taxes.

The Company’s energy production costs for the three months and six months ended June 30, 2023 were $8.72/bbl and $8.86/bbl, respectively, which was lower than the comparative periods in 2022 of $12.89/bbl and $10.86/bbl, respectively. The lower per barrel energy production costs in 2023, was primarily related to lower natural gas prices compared to 2022, which saw the onset of the conflict in Ukraine and was partially offset by higher power prices in 2023. Please see subsection 4.2 Commodity Prices for a discussion on energy costs.

The Company’s non-energy production costs for the three months and six months ended June 30, 2023 were $11.48/bbl and $11.99/bbl, respectively, which was higher than the comparative periods in 2022 of $9.64/bbl and $8.82/bbl, respectively. The higher per barrel non-energy operating expenses in 2023 was primarily due to the recognition of greenhouse gas emission fees of $1.21/bbl for the three months ended June 30, 2023 and $1.25/bbl for the six months ended June 30, 2023, as well as inflationary pressures on the costs of goods and services combined with lower sales volumes.

Greenfire Resources Inc. 2023 Q2 Management’s Discussion and Analysis | 21

Figure 14: Production Costs

	Three months ended June 30,				Six months ended June 30,
($ thousands, unless otherwise noted)	2023		2022		2023		2022
Production costs – energy		14,285		25,020		31,396		44,392
Production costs – non-energy		20,603		18,707		42,471		36,045
Production costs(1)		34,888		43,726		73,867		80,437
Production costs – energy ($/bbl)		8.72		12.89		8.86		10.86
Production costs – non-energy ($/bbl)		11.48		9.64		11.99		8.82
Production costs(1) ($/bbl)		20.20		22.53		20.85		19.69

⁽¹⁾ Production costs excludes ad valorem, severance, and similar production related taxes.

4.10 General & Administrative Expenses

General and administrative (“G&A”) expenses include head office and corporate costs such as salaries and employee benefits, office rent, independent third-party audit and engineering services, and administrative recoveries earned for operating exploration and development activities on behalf of the Company’s working interest partners, among other costs. G&A expenses primarily fluctuates with head office staffing levels and the level of operated exploration and development activity during the period. G&A may also include expenses related to corporate strategic initiatives, if any.

G&A expenses of $1.62/bbl for the three months ended June 30, 2023, were higher than $1.03/bbl for the comparative period in 2022. The increase in G&A was primarily due to the Company going through cost allocation amendments in the second quarter of 2022 between G&A and operating costs, which resulted in lower G&A costs in the second quarter of 2022, compared to subsequent periods. Additionally, the increase in G&A was due to the company recording $0.3 million of stock-based compensation related to the performance warrant plan, as well as lower sales volumes in the second quarter of 2023 compared to the same period in 2022.

G&A expenses of $1.55/bbl for the six months ended June 30, 2023, were higher than $1.31/bbl for the comparative period in 2022. The increase was primarily due to the Company recording $0.7 million of stock-based compensation related to the performance warrant plan, as well as lower sales volumes in the six months ended June 30, 2023 compared to the same period in 2022.

Figure 15: General & Administrative Expenses

	Three months ended June 30,				Six months ended June 30,
($ thousands, unless otherwise noted)	2023		2022		2023		2022
General and administrative expenses		2,657		2,008		5,483		5,350
- ($/bbl)		1.62		1.03		1.55		1.31

4.11 Interest and Finance Expenses

Interest and finance expenses includes coupon interest, amortization of debt issue costs, issuer discount and the equity related to the bondholder warrants, redemption premiums on long term debt, interest on letter of credit facilities and other interest charges. Coupon interest and required redemption premiums related to long term debt are accrued and paid according to the indenture that governs the Notes.

Greenfire Resources Inc. 2023 Q2 Management’s Discussion and Analysis | 22

In the three months and six months ended June 30, 2023, total interest and finance expenses were $5.4 million and $20.7 million, respectively, compared to $22.2 million and $45.3 million in the comparative periods in 2022. The decrease was primarily related to the Company revising the estimated timing of the future debt principal repayments that resulted in lower amortization of debt issuance costs, debt issuer discount and bondholder warrant equity. Additionally, there was lower interest incurred on the Notes from less outstanding debt as a result of debt principal repayments on May 26, 2022 and November 28, 2022.

Refer to section 5 Capital Resources and Liquidity in this MD&A for more details of Greenfire’s long-term debt and letter of credit facilities.

Figure 16: Interest and Finance Expenses

	Three months ended June 30,				Six months ended June 30,
($ thousands)	2023		2022		2023		2022
Accretion on long-term debt	$	4,870	$	21,398	$	19,714	$	43,703
Other interest		305		573		560		1,210
Accretion of decommissioning obligations		223		189		440		348
Total interest and finance expenses	$	5,398	$	22,160	$	20,714	$	45,261

4.12 Depletion and Depreciation

The Company depletes crude oil properties on a unit-of-production basis over estimated total recoverable proved plus probable (2P) reserves. The depletion base consists of the historical net book value of capitalized costs, plus the estimated future costs required to develop the Company’s estimated recoverable proved plus probable reserves. The depletion base excludes exploration and the cost of assets that are not yet available for use.

The unit-of-production rate accounts for expenditures incurred to date, together with estimated future development expenditures required to develop those proved reserves. This rate, calculated at a facility level, is then applied to sales volume to determine depletion each period. The Company believes that this method of calculating depletion charges each barrel of crude oil equivalent sold with its proportionate share of the cost of capital invested over the total estimated life of the related asset as represented by 2P reserves.

The Company’s depletion and depreciation expense for the three and six months ended June 30, 2023 were $10.46/bbl and $10.74/bbl, respectively, which was higher than the comparative periods in 2022 of $8.92/bbl and $8.73/bbl, respectively. The higher per barrel depletion and depreciation expense in 2023, was primarily due to the capitalization of the planned major turnarounds at both the Expansion Asset and the Demo Asset that were completed during mid-to-late September 2022 and early October 2022, which resulted in higher depletion and depreciation expense in 2023. Additionally, depletion and depreciation expense increased in the three months and six months ended June 30, 2023 due to an increase in future development costs as represented by 2P reserves in the Company’s most recent reserve report, relative to the prior reserve report.

Greenfire Resources Inc. 2023 Q2 Management’s Discussion and Analysis | 23

Figure 17: Depletion and Depreciation Expense

	Three months ended June 30,				Six months ended June 30,
($ thousands, unless otherwise noted)	2023		2022		2023		2022
Depletion and depreciation expense		17,120		17,312		38,035		35,674
- ($/bbl)		10.46		8.92		10.74		8.73

4.13 Exploration Expenses

In the three months ended June 30, 2023, exploration expenses was $1.0 million, compared to $0.3 million for the comparative period in 2022. The increase was primarily due to the escalating mineral lease rentals, amongst other items.

In the six months ended June 30, 2023, exploration expenses was $2.8 million, compared to $0.7 million for the comparative period in 2022. The increase was primarily due to higher escalating mineral lease rentals during the first and second quarter of 2023, amongst other items.

Figure 18: Exploration Expenses

	Three months ended June 30,				Six months ended June 30,
($ thousands, unless otherwise noted)	2023		2022		2023		2022
Exploration expenses		1,026		250		2,819		681

4.14 Other (Income) and Expense

In the three months ended June 30, 2023, other (income) and expense was income of $0.5 million, compared to an expense of $0.6 million for the comparative period in 2022. The difference in other (income) and expense was mainly due to income of $0.6 million in interest earnings from savings accounts and short-term investments during the second quarter of 2023, as well as an expense of $0.6 million, incurred after the JACOS acquisition during the same period in 2022, amongst other items.

In the six months ended June 30, 2023, other (income) and expense was income of $0.7 million, compared to an expense of $1.4 million for the comparative period in 2022. The difference in other (income) and expense was mainly due to income of $0.8 million in interest earnings from savings accounts and short-term investments during the second quarter of 2023, as well as an expense of $1.3 million, incurred after the JACOS acquisition during the same period in 2022, amongst other items.

Figure 19: Other (Income) and Expense

	Three months ended June 30,					Six months ended June 30,
($ thousands, unless otherwise noted)	2023			2022		2023			2022
Other (income) and expenses		(458	)		620		(666	)		1,385

4.15 Foreign Exchange Loss (Gain)

The Company’s foreign exchange loss (gain) is driven by fluctuations in the US dollar to Canadian dollar exchange rate, as it relates to its long-term debt that is denominated in US dollars and is primarily related to the note principal and interest components of the Company’s US dollar denominated debt.

Greenfire Resources Inc. 2023 Q2 Management’s Discussion and Analysis | 24

In the three months ended June 30, 2023, foreign exchange loss (gain) was a gain of $6.2 million, compared to a loss of $13.1 million for the comparative period in 2022. The difference in foreign exchange loss (gain) during the second quarter of 2023, compared to the same period in 2022, was mainly due to the Canadian dollar strengthening relative to the US dollar.

In the six months ended June 30, 2023, foreign exchange loss (gain) was a gain of $6.5 million, compared to a loss of $7.1 million for the comparative period in 2022. The difference in foreign exchange loss (gain) during the first and second quarter of 2023, compared to the same period in 2022, was mainly due to the Canadian dollar strengthening relative to the US dollar.

Figure 20: Foreign Exchange Loss (Gain)

	Three months ended June 30,					Six months ended June 30,
($ thousands, unless otherwise noted)	2023			2022		2023			2022
Realized foreign exchange loss (gain)		-			1,512		-			1,509
Unrealized foreign exchange loss (gain)		(6,226	)		11,550		(6,529	)		5,567
Foreign exchange loss (gain)		(6,226	)		13,062		(6,529	)		7,076

4.16 Decommissioning Liability

The Company’s decommissioning liabilities result from net ownership interests in oil assets including well sites, gathering systems and processing facilities. The Company estimates the total undiscounted inflated amount of cash flows required to settle its decommissioning liabilities to be approximately $206.5 million (December 31, 2022- $206.5 million). A credit-adjusted discount rate of 12% (December 31, 2022 - 12%) and an inflation rate of 2.0% (December 31, 2022 - 2.0%) were used to calculate the decommissioning liabilities. A 1.0% change in the credit-adjusted discount rate would impact the discounted value of the decommissioning liabilities by approximately $1.1 million with a corresponding adjustment to PP&E. The decommissioning liabilities are estimated to be settled in periods up to year 2071.

Figure 21: Reconciliation of Decommissioning Liability

	Three months ended		Year ended
	June 30,		December 31,
($ thousands)	2023		2022
Balance, beginning of period		7,543		5,517
Revaluation		-		1,283
Accretion expense		440		743
Balance, end of period		7,983		7,543

4.17 Net Income (Loss) and Comprehensive Income (Loss) and Adjusted EBITDA⁽¹⁾

During the three months and six months ended June 30, 2023, the Company recorded net income of $24.4 million and $7.7 million, respectively, compared to net income of $45.5 million and net loss of $57.0 million, respectively, during the comparative periods in 2022. The decrease in net income in the first half and second quarter of 2023, relative to 2022, was primarily the result of lower oil sales and lower WCS benchmark oil prices. Lower oil sales was a result of declining reservoir pressure resulting from short-term limitations of NCG availability for reservoir injection and unplanned downtime at the Expansion Asset. Net income (loss) and comprehensive income (loss) is an IFRS measure, which is the most directly comparable GAAP measure to adjusted EBITDA⁽¹⁾, which is a non-GAAP measure. During the three months and six months ended June 30, 2023, Greenfire recorded adjusted EBITDA⁽¹⁾ of $34.4 million and $47.4 million, respectively, compared to $70.4 million and $146.9 million, respectively, during the same periods in 2022. The decrease in adjusted EBITDA⁽¹⁾ in the first and second quarter of 2023, relative to 2022, was primarily the result of lower oil sales and lower WCS benchmark oil prices. Lower oil sales was a result of declining reservoir pressure resulting from short-term limitations of NCG availability for reservoir injection and unplanned downtime at the Expansion Asset.

⁽¹⁾ Non-GAAP measures do not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Non-GAAP Measures section in this MD&A for further information.

Greenfire Resources Inc. 2023 Q2 Management’s Discussion and Analysis | 25

The following table is a reconciliation of net income (loss) net income (loss) and comprehensive income (loss) to adjusted EBITDA⁽¹⁾:

Figure 22: Net Income (Loss) and Comprehensive Income (Loss) and Adjusted EBITDA⁽¹⁾

	Three months ended June 30,						Six months ended June 30,
($ thousands)	2023			2022			2023			2022
Net income (loss) and comprehensive income (loss)		24,355			45,473			7,677			(56,953	)
Add (deduct):
Income tax recovery		3,095			-			(518	)		-
Unrealized (gain) loss risk management contracts		(11,134	)		(28,182	)		(16,157	)		114,410
Transaction costs		1,914			-			4,241			-
Stock based compensation		325			-			650			-
Depletion and depreciation		17,120			17,312			38,035			35,674
Financing and interest		5,398			22,160			20,714			45,261
Foreign exchange loss		(6,226	)		13,062			(6,529	)		7,076
Gain on acquisitions		-			-			-			-
Other income and expenses		(458	)		620			(666	)		1,386
Adjusted EBITDA(1)		34,389			70,445			47,447			146,854
Net income (loss) and comprehensive income (loss) ($/bbl)		14.88			23.43			2.17			(13.94	)
Add (deduct):
Income tax recovery ($/bbl)		1.89			-			(0.15	)		-
Unrealized (gain) loss risk management contracts ($/bbl)		(6.80	)		(14.52	)		(4.56	)		28.00
Transaction costs ($/bbl)		1.17			-			1.20			-
Stock based compensation ($/bbl)		0.20			-			0.18			-
Depletion and depreciation ($/bbl)		10.46			8.92			10.74			8.73
Financing and interest ($/bbl)		3.30			11.42			5.85			11.08
Foreign exchange loss ($/bbl)		(3.80	)		6.73			(1.84	)		1.73
Gain on acquisitions ($/bbl)		-			-			-			-
Other income and expenses ($/bbl)		(0.28	)		0.32			(0.19	)		0.34
Adjusted EBITDA(1) ($/bbl)		21.02			36.30			13.40			35.94

⁽¹⁾ Non-GAAP measures do not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Non-GAAP Measures section in this MD&A for further information.

5. CAPITAL RESOURCES AND LIQUIDITY

The Company’s capital management objective is to maintain financial flexibility and sufficient liquidity to execute on planned capital programs, while meeting short and long-term commitments, including servicing and repaying long term debt. The Company strives to actively manage its capital structure in response to changes in economic conditions and further deleverage its balance sheet.

⁽¹⁾ Non-GAAP measures do not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Non-GAAP Measures section in this MD&A for further information.

Greenfire Resources Inc. 2023 Q2 Management’s Discussion and Analysis | 26

At June 30, 2023, the Company’s capital structure summarized in Figure 2 primarily comprised of cash and cash equivalents, restricted cash and long-term debt.

Management believes its current capital resources and its ability to manage cash flow and working capital levels will allow the Company to meet its current and future obligations, to make scheduled interest and principal payments, and to fund the other needs of the business.

5.1 Long Term Debt

During the year ended December 31, 2021, the Company issued US$312.5 million of senior secured Notes. The Notes had an original issuer discount of 3.5% and bear interest at the fixed rate of 12.00% per annum, payable semi-annually, and mature on August 15, 2025. The Notes are secured by a first priority lien on substantially all the assets of the Company and its wholly owned subsidiaries.

The proceeds of the Notes were used to purchase 100% of the outstanding share capital of JACOS in September 2021, as well as for general working capital purposes.

The Company is obligated to redeem a portion of the outstanding Notes equal to 75% of excess cash flow⁽¹⁾ in every six-month period at a price equal to 106% of the principal, plus accrued and unpaid interest (the “Excess Cash Flow Redemption”). In accordance with the indenture governing the Notes, the Company has up to 65 days after the end of each six-month period to affect the Excess Cash Flow Redemption, with a 30-day notice period.

The first Excess Cash Flow Redemption period began on March 31, 2022. The Company issued its first Excess Cash Flow Redemption on May 26, 2022, approximating $64.3 million, of which $60.7 million was principal repayment. A second Excess Cash Flow Redemption was issued on November 28, 2022, approximating $66.7 million, of which $62.9 million was principal repayment. There was no Excess Cash Flow Redemption for the period from October 1, 2022 to March 30, 2023. The current Excess Cash Flow Redemption period will be from April 1, 2023 to September 30, 2023, with an estimated redemption of $61.2 million. The forecasted Excess Cash Flow Redemptions during the subsequent twelve months are recorded on the Company’s financial statements as a current liability.

Greenfire is in compliance with all debt covenants under the indenture governing the Notes at June 30, 2023.

5.2 Term Loan

On April 5, 2021, via a court supervised insolvency process, GAC acquired the Demo Asset from GHOPCO and assumed the associated debtor-in-possession financing amount of $19.7 million (the “Term Loan”). The Term Loan was underwritten by the Petroleum Marketer and incurred interest of LIBOR plus 9.0% that was payable monthly, as well as an equal monthly principal amortization of $714,286. The Petroleum Marketer was provided exclusive petroleum production marketing rights over the Company’s production at the Demo Asset for a term of three years, ending April 1, 2024. This petroleum production marketing contract includes marketing, royalty, incentive and performance fees, some of which are oil price dependent. In December 2022, the Company entered into an agreement to amend the petroleum marketing contract, which extended the term of the contract by one year, contingent upon the closing of the proposed transaction with M3-Brigade Acquisition III Corp.

⁽¹⁾ Non-GAAP measures do not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Non-GAAP Measures section in this MD&A for further information.

Greenfire Resources Inc. 2023 Q2 Management’s Discussion and Analysis | 27

On August 6, 2021, GAC received an additional advance of $9.0 million under the Term Loan that was used to purchase a US$7.0 million compound put option with a hedging counterparty to facilitate the closing of the issuance of the Notes. Between April 5, 2021 and September 17, 2021, the date that the Company closed the acquisition of JACOS, the Company made principal repayments under the Term Loan of $2.3 million. On September 17, 2021, the remaining principal balance of $26.7 million under the Term Loan was redeemed in exchange for an aggregate principal amount of Notes of US$22 million.

5.3 Working Capital (Deficit) and Adjusted Working Capital⁽¹⁾

Working capital (deficit) is a GAAP measure that is the most directly comparable measure to adjusted working capital⁽¹⁾. Adjusted working capital⁽¹⁾ is comprised of current assets less current liabilities on the Company’s balance sheet, and excludes the current portion of long-term debt and current portion of risk management contracts. Adjusted working capital⁽¹⁾ is included within the non-GAAP measures because it is a less volatile measure of current assets and current liabilities, after isolating for current portion of long-term debt and current portion of risk management contracts. A surplus of adjusted working capital⁽¹⁾ will result in a future net cash inflow to the business. Available funding allows management and other users to evaluate the Company’s short-term liquidity, and its capital resources available at a point in time.

As at June 30, 2023, working capital increased to $22.5 million from a working capital deficit of $13.4 million as at December 31, 2022, a difference of $35.9 million, primarily due to an increase in cash balances and inventories in 2023 from higher WCS benchmark oil prices, as well as a decrease to the current portion of risk management contracts.

As at June 30, 2023, adjusted working capital increased to $94.5 million from $76.9 million as at December 31, 2022, a difference of $17.6 million, primarily due to an increase in cash balances and inventories in 2023 from higher WCS benchmark oil prices.

Figure 23: Reconciliation of Working Capital (Deficit) to Adjusted Working Capital⁽¹⁾

	Three months ended			Year ended
	June 30,			December 31,
($ thousands)	2023			2022
Current assets		134,542			123,527
Current liabilities		(112,032	)		(136,921	)
Working capital (deficit)		22,510			(13,394	)
Current portion of risk management contracts		10,847			27,004
Current portion of long-term debt		61,156			63,250
Adjusted working capital(1)		94,513			76,860

⁽¹⁾ Non-GAAP measures do not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Non-GAAP Measures section in this MD&A for further information.

5.4 Restricted Cash and Letter of Credit Facilities

As at December 31, 2021, the Company had a $51.5 million credit facility with the Petroleum Marketer (“Credit Facility”) that was used to issue $51.5 million in letters of credit related to the Company’s long-term pipeline transportation agreements. Under the terms of the Credit Facility, over a period of 24 months and beginning in October 2021, the Company is required to contribute cash to a cash-collateral account (“Reserve Account”) until the balance of the Reserve Account is equal to 105% of the aggregate face value of the Credit Facility.

⁽¹⁾ Non-GAAP measures do not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Non-GAAP Measures section in this MD&A for further information.

Greenfire Resources Inc. 2023 Q2 Management’s Discussion and Analysis | 28

During the year ended December 31, 2022, the Company obtained a $15.0 million cash-collateralized, demand revolving credit facility (“Demand Facility”), to be exclusively used for issuing letters of credit, and bears interest at 1.5%. During the year ended December 31, 2022, the Company transferred $4.7 million in letters of credit and restricted cash collateral from the Credit Facility and the Reserve Account to the Demand Facility. There was no net change in restricted cash nor a change in unrestricted cash as a result of this transfer.

As at June 30, 2023, the Credit Facility had $46.8 million letter of credit outstanding, with restricted cash- collateral of $39.3 million, and the Demand Facility had $8.1 million in issued letters of credit and $8.1 million of restricted cash collateral, which consisted of $4.7 million transferred from the Credit Facility, and $3.4 million related to the Company’s credit cards and other operational commitments.

5.5 Expansion Marketing Contract

Following the acquisition of JACOS, an agreement was signed with the Petroleum Marketer for exclusive marketing services at the Expansion Asset, including:

● The purchase of all WDB produced by the Expansion Asset

● The supply of diluent to the facility; and

● The facilitation of all pipeline transportation and storage costs.

This petroleum contract has a term of five years after the first delivery of blend, which occurred in October 2021. In December 2022, the Company entered into an agreement to amend the petroleum marketing contract, which extended the term of the contract by one year, contingent upon the closing of the proposed transaction with M3- Brigade Acquisition III Corp.

5.6 Demo Marketing Contract

Following the acquisition of the Demo Asset, an agreement was signed with the Petroleum Marketer for exclusive marketing services at the Demo Asset, including:

● The purchase of all bitumen produced by the Demo Asset

● The facilitation of all bitumen transportation

This petroleum marketing contract has a term to April 2024. In December 2022, the Company entered into an agreement to amend the petroleum marketing contract, which extended the term of the contract by one year, contingent upon the closing of the proposed transaction with M3-Brigade Acquisition III Corp.

5.7 Share Capital and Warrants

Share Capital

At December 31, 2020, GAC had 1,000 issued and outstanding common shares held by the founding shareholders. The Company was subsequently incorporated on June 18, 2021 with the founding shareholders being issued 1,000 common shares, which were subsequently split to 7,500,000 common shares of the Company. Following the incorporation of the Company, GAC was amalgamated with Greenfire Resources Operating Corporation (a wholly owned subsidiary of the Company) pursuant to which the 1,000 common shares of GAC were cancelled and the founding shareholders were issued an additional 10 common shares in the Company. On September 16, 2021 an employee private placement resulted in 1,451,614 common shares being issued by the Company to employees and service providers of the Company. At June 30, 2023 and as at the date hereof, the Company’s authorized share capital consists of an unlimited number of common shares and there was a total of 8,951,624 common shares outstanding.

Greenfire Resources Inc. 2023 Q2 Management’s Discussion and Analysis | 29

Figure 24: Outstanding Common Shares

	Three months ended June 30,				Six months ended June 30,
	2023		2022		2023		2022
Shares outstanding
Balance, beginning of period		8,951,624		8,951,624		8,951,624		8,951,624
Stock issued		-		-		-		-
Balance, end of period		8,951,624		8,951,624		8,951,624		8,951,624

Figure 25: Weighted Average Shares Outstanding

	Three months ended June 30,				Six months ended June 30,
	2023		2022		2023		2022
Weighted average shares outstanding- basic		8,951,624		8,951,624		8,951,624		8,951,624
Dilutive effect of warrants		3,939,320		3,927,353		3,937,227		3,756,130
Weighted average shares outstanding- diluted		12,890,944		12,878,977		12,888,851		12,707,754

Bondholder Warrants

As at June 30, 2023, the Company had 312,500 Bondholder Warrants outstanding that entitled the holders of these warrants, in aggregate, the right to purchase 25% of the Company’s issued and outstanding common shares up to a maximum of 3,225,806 common shares at $0.01 per share. The Bondholder Warrants were exercisable and detachable 30 days post the closing of the JACOS acquisition. The Notes and Bondholder Warrants were separated on October 18, 2021. Based on the issued and outstanding common shares of the Company, bondholders have the right to acquire 2,983,866 common shares at $0.01 per share.

Greenfire Resources Inc. 2023 Q2 Management’s Discussion and Analysis | 30

Figure 26: Bondholder Warrants Outstanding

	Six months ended				Year ended
	June 30, 2023				December 31, 2022
	Number of warrants		Exercise price		Number of warrants		Exercise price
Bondholder warrants outstanding
Balance, beginning of period		312,500	$	0.01		312,500	$	0.01
Warrants Issued		-		-		-		-
Balance, end of period		312,500	$	0.01		312,500	$	0.01
Exchange ratio, end of year		9.55		-		9.55		-
Common shares issuable on exchange		2,983,866		-		2,983,866		-

Performance Warrants

In February 2022, the Company implemented a warrant plan as part of the Company’s long-term incentive plan for employees and service providers, whereby up to 725,806 warrants (“Performance Warrants”) are issuable under the plan. These Performance Warrants have both performance and time vesting criteria before there is the ability to exercise the option to purchase one common share of the Company for each Performance Warrant. As of the date of these consolidated financial statements, the vesting criteria was met for approximately 36,849 performance warrants, which can be converted into 36,849 common shares. All Performance Warrants expire 10 years after issuance.

Figure 27: Performance Warrants Outstanding

	Six months ended					Year ended
	June 30, 2023					December 31, 2022
	Number of warrants			Weighted Average Exercise price		Number of warrants			Weighted Average Exercise price
Performance warrants outstanding
Balance, beginning of period		712,930		$	15.79		-		$	-
Performance warrants issued		8,526			58.67		761,264			15.88
Performance warrants forfeited		(3,528	)		14.18		(48,334	)		17.12
Balance, end of period		716,878		$	16.26		712,930		$	15.79
Common shares issuable upon vesting		716,878			-		712,930			-

5.8 Cash Flow Summary

Cash Flow – Operating Activities

During the three months ended June 30, 2023, cash provided by operating activities was $23.6 million compared to $67.6 million in the same period in 2022, a decrease of $44.0 million, and was primarily due to lower oil sales and lower WCS benchmark oil prices. Lower oil sales was a result of declining reservoir pressure resulting from short-term limitations of NCG availability for reservoir injection and unplanned downtime at the Expansion Asset.

During the six months ended June 30, 2023, cash provided by operating activities was $19.1 million compared to $98.2 million in the same period in 2022, a decrease of $79.1 million, and was primarily due to lower oil sales and lower WCS benchmark oil prices. Lower oil sales was a result of declining reservoir pressure resulting from short- term limitations of NCG availability for reservoir injection and unplanned downtime at the Expansion Asset.

Greenfire Resources Inc. 2023 Q2 Management’s Discussion and Analysis | 31

Based on current and forecasted production levels, operating expenses, property, plant and equipment expenditures, existing commodity price risk management contracts and current outlook for commodity prices, the Company expects cash from operating activities will be sufficient to cover its operational commitments and financial obligations under its Notes and letters of credit in the next 12 months.

Cash Flow – Financing Activities

During the three months ended June 30, 2023, cash used by financing activities was nil compared to $60.7 million in the same period in 2022, a difference of $60.7 million, and was due to a debt principal repayment of $60.7 million in the three months ended June 30, 2022.

During the six months ended June 30, 2023, cash used by financing activities was nil compared to $60.7 million in the same period in 2022, a difference of $60.7 million, and was due to a debt principal repayment of $60.7 million in the six months ended June 30, 2022.

Cash Flow – Investing Activities

During the three months ended June 30, 2023, cash used in investing activities was $9.1 million compared to $15.4 million in the same period in 2022, a difference of $6.4 million, and was primarily due to a deferment of property, plant, and equipment expenditures commencing in current and preceding periods, which was in turn a result of lower commodity prices.

During the six months ended June 30, 2023, cash used in investing activities was $17.6 million compared to $23.1 million in the same period in 2022, a difference of $5.5 million, and was primarily due to a deferment of property, plant, and equipment expenditures in current and preceding periods, which was in turn a result of lower commodity prices.

Figure 28: Cash Flow Summary

	Three months ended June 30,						Six months ended June 30,
($ thousands, unless otherwise noted)	2023			2022			2023			2022
Cash provided by (used in):
Operating activities		23,640			67,553			19,144			98,241
Financing activities		(6	)		(60,709	)		(12	)		(60,709	)
Investing activities		(9,066	)		(15,420	)		(17,586	)		(23,079	)
Exchange rate impact on cash and cash equivalents held in foreign currency		(89	)		(1,823	)		(27	)		(1,947	)
Change in cash and cash equivalents		14,479			(10,399	)		1,519			12,506

5.9 Property, Plant and Equipment Expenditures

Total property, plant and equipment expenditures for the three months ended June 30, 2023 was $1.9 million (2022 - $7.7 million), consisting primarily of the following;

● Refill Well Program - $1.0 million was spent on initiating a Refill Well program at the Expansion asset which will allow incremental bitumen production.

● Demo Asset Plant 1 - $0.4 million in capital spend for a project which is part of the overall capital program to debottleneck the Demo Asset facility to process additional production volumes by refurbishing and restarting an existing plant at the Demo Asset. The project’s primary objective is to utilize existing oil handling equipment in order to process greater production volume.

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Total property, plant and equipment expenditures for the six months ended June 30, 2023 was $4.4 million (2022 - $12.9 million), consisting primarily of the following;

● Small Projects and Sustaining Capital - $2.1 million for various capital projects at both Demo Asset and Expansion Asset.

● Demo Asset Plant 1 - $1.3 million in capital spend for a project which is part of the overall capital program to debottleneck the Demo Asset facility to process additional production volumes by refurbishing and restarting an existing plant at the Demo Asset. The project’s primary objective is to utilize existing oil handling equipment in order to process greater production volume.

● Refill Well Program - $1.0 million was spent on initiating a Refill Well program at the Expansion asset which will allow incremental bitumen production.

Figure 29 summarizes the Company’s property, plant and equipment expenditures:

Figure 29: Property, Plant and Equipment Expenditures

	Three months ended June 30,				Six months ended June 30,
($ thousands)	2023		2022		2023		2022
Total property, plant and equipment expenditures		1,911		7,706		4,428		12,906
- $/bbl		1.17		3.97		1.25		3.16

5.10 Cash Provided by Operating Activities and Adjusted Funds Flow⁽¹⁾

During the three months and six months ended June 30, 2023, the Company had cash provided by operating activities of $23.6 million and $19.1 million, respectively, compared to cash provided by operating activities of $67.6 million and $98.2 million, during the comparative periods in 2022. Cash provided by operating activities is the most directly comparable GAAP measure for adjusted funds flow⁽¹⁾, which is a non-GAAP measure. During the three months and six months ended June 30, 2023, Greenfire recorded adjusted funds flow⁽¹⁾ of $19.6 million and $17.8 million, respectively, compared to $50.0 million and $106.7 million, during the same periods in 2022. The lower adjusted funds flow⁽¹⁾ during the first and second quarters of 2023, was primarily a result of lower oil sales and lower WCS benchmark oil prices. Lower oil sales was a result of declining reservoir pressure resulting from short-term limitations of NCG availability for reservoir injection and unplanned downtime at the Expansion Asset, which was partially offset by lower property, plant and equipment expenditures.

⁽¹⁾ Non-GAAP measures do not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Non-GAAP Measures section in this MD&A for further information.

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Figure 30: Reconciliation of Cash Provided by Operating Activities to Adjusted Funds Flow⁽¹⁾

	Three months ended June 30,						Six months ended June 30,
($ thousands)	2023			2022			2023			2022
Cash provided by (used in) operating activities		23,640			67,553			19,144			98,241
Changes in non-cash working capital		(2,095	)		(9,808	)		3,130			21,334
Property, plant and equipment expenditures		(1,911	)		(7,706	)		(4,428	)		(12,906	)
Adjusted funds flow(1)		19,634			50,039			17,846			106,669
Cash provided by (used in) operating activities ($/bbl)		14.44			34.80			5.40			24.04
Changes in non-cash working capital ($/bbl)		(1.28	)		(5.05	)		0.88			5.22
Property, plant and equipment expenditures ($/bbl)		(1.17	)		(3.97	)		(1.25	)		(3.16	)
Adjusted funds flow(1) ($/bbl)		11.99			25.78			5.04			26.11

⁽¹⁾ Non-GAAP measures do not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Non-GAAP Measures section in this MD&A for further information.

6. NON-GAAP MEASURES

In this MD&A, we refer to certain specified financial measures (such as excess cash flow, adjusted EBITDA, adjusted EBITDA per barrel ($/bbl), adjusted funds flow and adjusted funds flow per barrel ($/bbl) which do not have any standardized meaning prescribed by IFRS. While these measures are commonly used in the oil and natural gas industry, the Company’s determination of these measures may not be comparable with calculations of similar measures presented by other reporting issuers. This MD&A also contains the terms “adjusted working capital” and “net debt” which are non-GAAP measures. We believe that the inclusion of these specified financial measures provides useful information to financial statement users when evaluating the financial results of Greenfire.

Non-GAAP Financial Measures

Excess Cash Flow

Change in cash and cash equivalents is an IFRS measure in the Company’s consolidated statement of cash flows, which is the most directly comparable financial statement measure to excess cash flow. A reconciliation from change in cash and cash equivalents to excess cash flow has been provided in Figure 31 below. These measures are not intended to represent change in cash and cash equivalents, net earnings or other measures of financial performance calculated in accordance with IFRS.

Excess cash flow is a non-GAAP financial measure that allows the Company to determine the amount of scheduled bond principal repayments. Under section 4.19 of the indenture that governs the Notes, the Company is obligated to redeem a portion of the outstanding 2025 Senior Secured Notes equal to 75% of its excess cash flow in every six-month period, with the first six-month period beginning on the date the Company completed the acquisition of all the issued and outstanding shares of JACOS on September 17, 2021 (“JACOS Closing Date”) and ending March 31, 2022. Figure 31 shows that the excess cash flow during the three months and six months ended June 30, 2023 were $22.5 million and $13.6 million, respectively, compared to excess cash flow of $58.4 million and $86.5 million, respectively, during the comparative periods in 2022.

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Figure 31: Reconciliation of Change in Cash and Cash Equivalents to Excess Cash Flow

	Three months ended June 30,					Six months ended June 30
($ thousands)	2023		2022			2023		2022
Change in cash and cash equivalents		14,479		(10,399	)		1,519		12,506
Change in restricted cash		8,000		8,100			12,050		13,317
Repayment of long-term debt		-		60,691			-		60,691
Excess cash flow		22,479		58,392			13,569		86,514

Adjusted EBITDA

Net income (loss) and comprehensive income (loss) is the most directly comparable GAAP measure for adjusted EBITDA, which is a non-GAAP measure. Adjusted EBITDA is calculated as net income (loss) before interest and financing expenses, income taxes, depletion, depreciation and amortization, and is adjusted for certain non-cash items, or other items that are not considered part of normal business operations. Adjusted EBITDA is used to measure Greenfire’s profitability from its underlying asset base on a continuing basis. This measure is not intended to represent net income (loss) and comprehensive income (loss) in accordance with IFRS.

Please see Figure 22 for a reconciliation of net income (loss) and comprehensive income (loss) to adjusted EBITDA.

Adjusted Funds Flow

Cash provided by operating activities is the most directly comparable GAAP measure for adjusted funds flow, which is a non-GAAP measure. Management uses adjusted funds flow as an indicator of the efficiency and liquidity of Greenfire’s business, measuring its funds after capital investment that is available to manage debt levels and return capital to stakeholders. This measure is not intended to represent cash provided by operating activities, net earnings or other measures of financial performance calculated in accordance with IFRS. We compute adjusted funds flow as cash provided by operating activities, excluding the impact of changes in non-cash working capital, less property, plant and equipment expenditures. By removing the impact of current period property, plant and equipment expenditures, management monitors Greenfire’s adjusted funds flow to inform its capital allocation decisions.

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Please see Figure 30 for a reconciliation of cash provided by operating activities to adjusted funds flow.

Adjusted Working Capital

Working capital (deficit) is a GAAP measure that is the most directly comparable measure to adjusted working capital. These measures are not intended to represent current assets, net earnings or other measures of financial performance calculated in accordance with IFRS. Adjusted working capital is comprised of current assets less current liabilities on the Company’s balance sheet, and excludes the current portion of risk management contracts and current portion of long-term debt, the latter of which is subject to estimates in future commodity prices, production levels and expenses, among other factors. See Figure 23 for a reconciliation of working capital (deficit) to adjusted working capital. Adjusted working capital is included within the non-GAAP measures because it is a less volatile measure of current assets and current liabilities, after isolating for current portion of long-term debt and current portion of risk management contracts, a surplus of adjusted working capital will result in a future net cash inflow to the business that can be used by management to evaluate the Company’s short-term liquidity and its capital resources available at a point in time. A deficiency of adjusted working capital will result in a future net cash outflow, which may result in the Company not being able to settle short-term liabilities more than current assets.

Net debt

Long-term debt is a GAAP measure that is the most directly comparable financial statement measure to net debt. These measures are not intended to represent long-term debt calculated in accordance with IFRS. Net debt is comprised of long-term debt, adjusted for current assets and current liabilities on the Company’s balance sheet, and excludes the current portion of risk management contracts. See Figure 32 for a reconciliation of long-term debt to net debt. Management uses net debt to monitor the Company’s current financial position and to evaluate existing sources of liquidity. Net debt is used to estimate future liquidity and whether additional sources of capital are required to fund planned operations.

Figure 32: Reconciliation of Long-Term Debt to Net Debt

	As at			As at
	June 30,			December 31,
($ thousands)	2023			2022
Long-term debt		(185,649	)		(191,158	)
Current assets		134,542			123,527
Current liabilities		(112,032	)		(136,921	)
Current portion of risk management contracts		10,847			27,004
Net debt		(152,292	)		(177,548	)

Non-GAAP Financial Ratios

Adjusted EBITDA ($/bbl)

Net income (loss) and comprehensive income (loss) is the most directly comparable GAAP measure for adjusted EBITDA ($/bbl), which is a non-GAAP measure. Adjusted EBITDA ($/bbl) is used to measure Greenfire’s profitability from its underlying asset base on a continuing basis. This measure is not intended to represent net income (loss) and comprehensive income (loss) in accordance with IFRS. Adjusted EBITDA ($/bbl) is calculated by dividing adjusted EBITDA by the Company’s total sales volume in a specified period.

Please see Figure 22 for a reconciliation of net income (loss) and comprehensive income (loss) to adjusted EBITDA.

Adjusted Funds Flow ($/bbl)

Cash provided by operating activities is the most directly comparable GAAP measure for adjusted funds flow ($/bbl), which is a non-GAAP measure. Management uses adjusted funds flow ($/bbl) as an indicator of the efficiency and liquidity of Greenfire’s business, measuring its funds after capital investment that is available to manage debt levels and return capital to stakeholders. This measure is not intended to represent cash provided by operating activities, net earnings or other measures of financial performance calculated in accordance with IFRS. Adjusted funds flow ($/bbl) is calculated by dividing adjusted funds flow by the Company’s total oil sales volume in a specified period.

Please see Figure 30 for a reconciliation of cash provided by operating activities to adjusted funds flow.

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Figure 33: Summary of Quarterly Results

	2023					2022									2021(3)
($ thousands, unless otherwise noted)	Q2		Q1			Q4		Q3		Q2		Q1			Q4			Q3		Q2
BUSINESS ENVIRONMENT(1)
WTI (US$/bbl)		73.78		76.13			82.65		91.55		108.41		94.29			77.19			70.56		66.07
WTI (CAD$/bbl)		99.09		102.93			112.21		119.54		138.39		119.38			97.25			88.91		81.11
WCS (CAD$/bbl)		78.75		69.29			77.05		93.48		122.04		100.96			78.67			71.77		66.96
AECO (CAD$/GJ)		2.32		3.05			4.85		3.95		6.86		4.49			4.41			3.41		2.93
FX (USD:CAD)(2)		1.343		1.352			1.358		1.306		1.277		1.266			1.26			1.26		1.228
Operational – Expansion
Bitumen production (bbls/d)		13,939		16,302			15,710		14,926		17,910		18,714			19,155			2,076		-
Operational – Demo
Bitumen production (bbls/d)		4,097		4,284			3,869		2,922		3,830		4,196			3,909			3,286		3,384
Operational – Consolidated
Bitumen production (bbls/d)		18,036		20,586			19,579		17,848		21,740		22,909			23,064			5,362		3,384
Bitumen sales volumes (bbls/d)		17,992		21,171			19,501		17,727		21,331		23,829			22,614			5,465		3,344
Steam-oil ratio (SOR)		4.16		3.72			3.66		3.57		3.45		3.25			3.08			3.28		3.25
OPERATING RESULTS
Oil sales		173,605		179,668			180,741		209,550		315,794		292,764			215,985			37,943		16,746
Net income (loss)		24,355		(16,678	)		87,995		100,656		45,473		(102,426	)		(10,315	)		564,696		107,063
Cash flow provided by operating activities		23,640		(4,495	)		17,322		49,164		67,553		30,688			41,129			27,546		(1,358	)
Property, plant and equipment expenditures		1,911		2,518			12,361		14,325		7,706		5,200			2,399			1,509		687
FINANCIAL POSITION
Cash and cash equivalents		36,882		22,403			35,363		99,822		73,375		83,774			60,869			32,019		277
Restricted cash		47,363		39,363			35,313		27,413		22,017		13,917			8,700			560		60
Total assets		1,153,021		1,147,984			1,174,258		1,158,367		1,174,634		1,182,168			1,129,080			1,107,261		163,480
Total debt		246,805		259,555			254,408		320,607		289,604		329,689			325,569			369,647		19,286
Shareholders’ equity		846,098		821,418			837,771		748,593		647,937		602,464			704,890			671,714		107,003

⁽¹⁾ These benchmark prices are not the Company’s realized sales prices and represent approximate values.

⁽²⁾ Annual or quarterly average exchange rates as per the Bank of Canada.

⁽³⁾ Results are from operations that began at the Expansion Asset after the acquisition of JACOS on September 17, 2021 and at the Demo Asset when it was acquired on April 5, 2021.

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7. COMMITMENTS AND CONTINGENCIES

The Company has lease commitments related to pipeline transportation services, and credit facility commitments associated with its pipeline transportation commitments. Future minimum amounts payable under these commitments are as follows:

Figure 34: Commitments

(thousands)	2023		2024		2025		2026		2027		Beyond 2027		Total
Credit facility		9,784		-		-		-		-		-		9,784
Transportation		16,205		31,880		30,561		28,956		29,044		232,368		369,014
Total		25,989		31,880		30,561		28,956		29,044		232,368		378,798

8. ACCOUNTS RECEIVABLE

Credit risk is the risk of financial loss to the Company if a customer or counterparty to a financial instrument fails to meet its contractual obligations and arises principally from the Company’s accounts receivable. The Company is primarily exposed to credit risk from receivables associated with its oil sales. The Company manages its credit risk exposure by transacting with high-quality credit worthy counterparties and monitoring credit worthiness and/or credit ratings on an ongoing basis. Trade receivables from oil sales are generally collected on the 25^th day of the month following production. Joint interest receivables are typically collected within one to three months of the invoice being issued. For the period ended June 30, 2023, the Company had oil sales to a single counterparty and has not previously experienced any material credit losses on the collection of accounts receivable.

At June 30, 2023 credit risk from the Company’s outstanding accounts receivable and joint interest receivable balances was considered low due to a history of collections and the receivables that were held by credit worthy counterparties. There were no overdue balances at June 30, 2023.

Figure 35: Accounts Receivable

	Three months ended		Year ended
	June 30,		December 31,
($ thousands)	2023		2022
Trade receivables		30,465		22,428
Joint interest receivables		6,046		11,880
Accounts receivable		36,511		34,308

9. CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The Company’s critical accounting policies and estimates are those estimates having a significant impact on the financial position and operations that require management to make judgements, assumptions and estimates in the application of IFRS. Judgements, assumptions and estimates are based on the historical experience and other factors that management believes to be reasonable under current conditions. As events occur and additional information becomes available, these judgements, assumptions and estimates may be subject to change. Detailed disclosure of the significant accounting policies and the significant accounting estimates, assumptions and judgements can be found in the Company’s financial statements for the period ended December 31, 2022.

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10. OFF-BALANCE SHEET ARRANGEMENTS

We do not have any off-balance sheet arrangements that have, or are reasonably likely to have, a material current or future effect on our financial condition, change in financial condition, revenues, expenses, results of operations, liquidity, capital expenditures or capital resources.

11. FORWARD LOOKING STATEMENTS

This MD&A contains “forward-looking information” within the meaning of applicable Canadian securities laws (forward-looking information being collectively hereinafter referred to as “forward-looking statements”). Such forward-looking statements are based on expectations, estimates and projections as at the date of this MD&A. Any statements that involve discussions with respect to predictions, expectations, beliefs, plans, projections, objectives, assumptions or future events or performance (often but not always using phrases such as “expects”, “is expected”, “anticipates”, “plans”, “budget”, “scheduled”, “forecasts”, “estimates”, “believes” or “intends”, or variations of such words and phrases (including negative and grammatical variations), or stating that certain actions, events or results “may”, “could”, “would”, “should”, “might” or “will” be taken, occur or be achieved) are not statements of historical fact and may be forward-looking statements and are intended to identify forward- looking statements. These forward-looking statements include, but are not limited to, statements and information concerning: the intentions, plans and future actions of the Company; Greenfire’s belief that there are a range of attractive investment opportunities in the oil and gas sector in Canada; Greenfire’s plans to continue to sustainably increase production at the Expansion Asset by optimizing the site’s existing infrastructure, while employing a safe, efficient, and capital-disciplined operating approach; Greenfire’s expectation that over time optimization improvements will lead to an enhancement in profitability; Greenfire’s plans to further deleverage its balance sheet in the near term, while in the mid to longer term, continuing to evaluate potential avenues for capital acceleration to attain additional step change growth; management’s intent to actively manage the Company’s capital structure in response to changes in economic conditions and its intention to further deleverage the Company’s balance sheet; management’s belief that the Company’s current capital resources and its ability to manage cash flow and working capital levels will allow the Company to meet its current and future obligations, to make scheduled interest and principal payments, and to fund the other needs of the business; the expectations relating to Excess Cash Flow and related redemption of Notes; and statements relating to the business and future activities of the Company after the date of this MD&A.

Forward-looking statements are based on the beliefs of the Company’s management, as well as on assumptions, which such management believes to be reasonable based on information available at the time such statements were made. In addition to other assumptions set out herein, the forward-looking statements contained herein are based on the following assumptions: Greenfire’s ability to compete with other companies; the anticipated future financial or operating performance of the Company; the expected results of operations; assumptions as to future drilling results; assumptions as to costs and commodity prices; the timing and amount of funding required to execute the Company’s business plans; assumptions about future capital expenditures; the effect on the Company of any changes to existing or new legislation or policy or government regulation; the length of time required to obtain permits, certifications and approvals; the availability of labor; estimated budgets; assumptions about future interest and currency exchange rates; requirements for additional capital; the timing and possible outcome of regulatory and permitting matters; goals; strategies; future growth; and the adequacy of financial resources. However, by their nature, forward-looking statements are based on assumptions and involve known and unknown risks, uncertainties and other factors which may cause the actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward- looking statements.

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Forward-looking statements are subject to a variety of risks, uncertainties and other factors which could cause actual results, performance or achievements to differ from those expressed or implied by the forward-looking statements, including, without limitation, a decline in oil prices or widening of differentials between various crude oil prices; lower than expected reservoir performance, including, but not limited to, lower oil production rates and/or higher SORs; the inability to recognize continued or increased efficiencies from the Company’s production enhancement program and processing plant enhancements, debottlenecking and brownfield expansions; reduced access to or an increase in the cost of diluent; an increase in the cost of natural gas; the reliability and maintenance of Greenfire’s facilities; supply chain disruption and risks of increases costs relating to inflation; the safety and reliability of pipelines and trucking services that transport Greenfire’s products; the need to replace significant portions of existing wells, referred to as “workovers”, or the need to drill additional wells; the cost to transport bitumen, diluent and bitumen blend, and the cost to dispose of certain by-products; the availability and cost of insurance and the inability to insure against certain types of losses; severe weather or catastrophic events such as fires, lightning, earthquakes, extreme cold weather, storms or explosions; seasonal weather patterns and the corresponding effects of the spring thaw on equipment on Greenfire’s properties; the availability of pipeline capacity and other transportation and storage facilities for the Company’s bitumen blend; the cost of chemicals used in Greenfire’s operations, including, but not limited to, in connection with water and/or oil treatment facilities; the impact of COVID-19 pandemic on the Company’s operations; the availability of and access to drilling equipment and key personnel; risks of cybersecurity threats including the possibility of potential breakdown, invasion, virus, cyber-attack, cyber-fraud, security breach, and destruction or interruption of the Company’s information technology systems; Canadian heavy and light oil export capacity constraints and the resulting impact on realized pricing; negative economic impacts as a result of the spread of COVID-19 (coronavirus); the Russia and Ukraine war including the resulting sanctions imposed on Russia and the impact on commodity pricing, global stability and the world economy; changes in the political landscape and/or legal, tax, royalty and regulatory regimes in Canada, and elsewhere; the cost of compliance with applicable regulatory regimes, including, but not limited to, environmental regulation and Government of Alberta production curtailments, if any; the ability to attract or access capital as a result of changing investor priorities and trends, including as a result of climate change, environmental, social and governance initiatives, the adoption of decarbonization policies and the general stigmatization of the oil and gas industry; hedging risks; variations in foreign exchange and interest rates; risks related to the Company’s indebtedness; failure to accurately estimate abandonment and reclamation costs; the potential for management estimates and assumptions to be inaccurate; and general economic, market and business conditions in Canada, the United States and globally.

The lists of risk factors set out in this MD&A or in the Company’s other public disclosure documents are not exhaustive of the factors that may affect any forward-looking statements of the Company. Forward-looking statements are statements about the future and are inherently uncertain. Actual results could differ materially from those projected in the forward-looking statements as a result of the matters set out in this MD&A generally and certain economic and business factors, some of which may be beyond the control of the Company. In addition, the global financial and credit markets have experienced significant debt and equity market and commodity price volatility which could have a particularly significant, detrimental and unpredictable effect on forward-looking statements. The Company does not intend, and does not assume any obligation, to update any forward-looking statements, other than as required by applicable law. For all of these reasons, the Company’s securityholders should not place undue reliance on forward-looking statements.

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