GTE Gran Tierra Energy Inc.

Gran Tierra Energy Inc. (“Gran Tierra” or the “Company”) (NYSE American:GTE) (TSX:GTE) (LSE:GTE) announced the Company’s financial and operating results for the quarter ended September 30, 2024 (“the Quarter”). All dollar amounts are in United States dollars, and production amounts are on an average working interest (“WI”) before royalties basis unless otherwise indicated. Per barrel (“bbl”) and bbl per day (“BOPD”) amounts are based on WI sales before royalties. For per bbl amounts based on net after royalty (“NAR”) production, see Gran Tierra’s Quarterly Report on Form 10-Q filed November 4, 2024.

Message to Shareholders

“On October 31, 2024 we were excited to have announced the close of our acquisition of i3 Energy plc (“i3 Energy”). We believe the purchase of i3 Energy uniquely positions Gran Tierra as a premier diversified oil and gas company with assets in Canada, Colombia, and Ecuador. The i3 Energy acquisition has diversified Gran Tierra into Canada and has added 253 net booked drilling locations(1), 77% operated production totaling approximately 18,000 bbls of oil equivalent per day, almost 1.2 million acres (0.6 million acres net) including 53 gross sections in the Montney and 144 gross sections in the Clearwater, two of the most prolific plays in North America. The i3 Energy acquisition has increased Gran Tierra’s PDP reserves(1) by 42 million bbls of oil equivalent (“MMBOE”) or 96%, 1P(1) by 88 MMBOE an increase of 97%, and 2P(1) by 174 MMBOE an increase of 119%. We believe the currently depressed natural gas pricing we see in Western Canada will be alleviated as major Liquified Natural Gas projects including LNG Canada are brought online. In the short term, Gran Tierra will focus on developing the significant oil weighted assets in its Canadian and South American portfolio.

We would like to take this opportunity to welcome our new shareholders in Gran Tierra and look forward to engaging with, and updating them on the Company's strategy in the coming months. We look forward to the integration of our teams and are confident the combined company will have top tier technical and operational skill sets across a broad portfolio. We are eager to implement industry leading technology currently used in Canada in both our Ecuador and Colombia operations, and are equally looking forward to bringing our reservoir modeling, exploration knowledge and asset management expertise into Canada. Combined we are a much stronger company.

Additionally, having our six consecutive discovery in Ecuador and reaching the milestone of 1 million cumulative bbls of oil produced from our operations in Ecuador is a significant achievement for Gran Tierra, highlighting our strong presence and success in the region. The productivity of the Ecuador wells is a testament to the geology in the Oriente and Putumayo Basins, and underpins a key pillar of growth going forward. We remain excited about the potential of the Arawana-Bocachico play, and the two remaining Zabaleta wells to be drilled by the end of the year that will provide essential insights into the size and scope of this promising opportunity”, commented Gary Guidry, President and Chief Executive Officer of Gran Tierra.

Operational Update:

• Acquisition of i3 Energy
  • On October 31, 2024, Gran Tierra completed its acquisition of i3 Energy. Gran Tierra is integrating the Canadian operations and are forecasting an active Q4 2024, including drilling 19 gross wells (8.4 net), targeting each of its core operating areas in Central AB, Simonette, Clearwater and Wapiti.
  • The Company drilled 2 gross (2 net) horizontal Dunvegan oil wells at Simonette. These high-impact 2-mile wells are currently being stimulated and are expected to be brought on stream in late November. With success, Gran Tierra can drill 2 additional Dunvegan development wells in 2025.
  • Clearwater activity commenced in mid-October with the Company’s first operated Clearwater multilateral well at Dawson (100% working interest). The 8-leg multilateral horizontal well (11,870 m of total lateral length) was a follow-up to the Company’s initial 6-leg (7,500 m of total lateral length) discovery at Dawson. The 8-leg well follow-up multilateral was located structurally up-dip of the discovery well and encountered high quality reservoir throughout while drilling. The well will be placed on production imminently as the rig has skidded to and spud the third Clearwater well from the same pad. The Company has been working to secure multiple pad sites at East Dawson to facilitate future expansion of the field, upon further operational success. Following these two wells the rig will move to Walrus and drill 2 prospective Falher sands.
  • In addition to the operated capital program, Gran Tierra plans to participate in 10 gross (1.67 net) non-operated partner horizontal wells across its land base.
  • In connection with i3 Energy acquisition closing on October 31, 2024, the Company amended and restated the existing revolving credit facility agreement of i3 Energy Canada Ltd. (“i3 Energy Canada”) with National Bank of Canada dated March 22, 2024. As a result of the amendment and restatement, among other things, the borrowing base was revised to C$100.0 million (US$74.1 million) with available commitment of a C$50.0 million (US$37.0 million) revolving credit facility comprised of C$35.0 million (US$25.9 million) syndicated facility and C$15.0 million (US$11.1 million) of operating facility. Subject to the next borrowing base redetermination which will occur on or before June 30, 2025, the revolving credit facility is available until October 31, 2025 with a repayment date of October 31, 2026, which may be extended by further periods of up to 364 days, subject to lender approval. The facility is undrawn.
• Exploration
  • Gran Tierra has successfully drilled its sixth consecutive oil discovery in Ecuador, the Charapa-B7 well. The wells drilled in Ecuador continue to yield strong results producing over 1 million cumulative bbls of oil to date which highlights the exceptional potential of the Oriente and Putumayo basins.

Well	Zone	OnstreamDate	IP30(BOPD)1	IP90(BOPD)2	IP30BS&W3	API	GOR(scf/stb)4	CumulativeProduction toDate (Mbbl)5
Charapa-B5	Hollin	11/9/2022	1,092	910	2%	28	160	307
Bocachico-J1	Basal Tena	5/30/2023	1,296	1,146	<1%	20	204	449
Arawana-J1	Basal Tena	5/17/2024	1,182	970	<1%	20	264	131
Bocachico Norte-J1	T-Sand	8/1/2024	833	519	3%	35	361	47
Charapa-B6	Hollin	8/7/2024	1,645	-	21%	28	49	77
Charapa-B7	Basal Tena	8/30/2024	2,043	-	<1%	25	153	112

    1. Average initial 30-day production per well.    2. Average initial 90-day production per well.    3. Percentage of basic sediment and water in the initial 30-day production.    4. Gas-oil ratio and standard cubic feet per stock tank barrel.    5. Thousand bbls of oil and based on production up to November 1, 2024.

• The drilling rig has been moved from the Charapa Block and mobilized to the Chanangue Block to drill two wells - the Zabaleta-K1 and Zabaleta Oeste-K1 exploration wells. The Zabaleta-K1 well is located four kilometers (“km”) to the east of the Arawana-J1 well drilled earlier this year and is 200 feet up structure. The well spud on October 22 2024, and we have currently drilled to 9,488 feet. Both wells will target the Basal Tena formation as well as assess potential in the T-Sand, U-Sand and B-Limestone.
• During the Quarter, the 238 km2 3D seismic program of the Charapa Block was completed, the data has been processed and is currently being interpreted. Preliminary interpretations of the high-quality 3D data confirm potential prospectivity and additional areas of interest identified on seismic, including better definition over the Charapa structure. The 3D data will further delineate reserves, underpin future drilling locations scheduled for 2025 and support future development planning.

• Development
  • The planning, civil works, and facility construction at Cohembi in the Suroriente Block are progressing, paving the way for drilling operations to commence in late Q4 2024.
  • Acordionero water treatment facilities expansion is expected to be completed mid-December which will result in an addition of 21,500 bbls of water handling per day which represents a 35% increase in water treatment capacity. This will allow for further well optimizations to increase injection and associated oil production. Gran Tierra continues to steadily increased total fluid production and water injection by ~18% per year to continue growing and maintaining oil production while improving sweep efficiencies and recoveries.

Key Highlights of the Quarter:

• Production: Gran Tierra’s total average WI production, which is before the i3 acquisition that has an effective date of October 31, 2024, was 32,764 BOPD, which was consistent with the second quarter 2024 (“the Prior Quarter”). During the Quarter the Company had lower volumes in the Acordionero field caused by downtime related to workovers, partially offset by higher production in the Costayaco field in Colombia, and increased production from the Chanangue and Charapa Blocks in Ecuador as a result of a successful exploration drilling campaign.
• Net Income: Gran Tierra incurred net income of $1 million, compared to a net income of $36.4 million in the Prior Quarter and a net income of $7 million in the third quarter of 2023.
• Adjusted EBITDA(2): Adjusted EBITDA(2) was $93 million compared to $103 million in the Prior Quarter and $119 million in the third quarter of 2023. Twelve month trailing Net Debt(2) to Adjusted EBITDA(2) was 1.3 times and the Company continues to have a long term target of 1.0 times.
• Funds Flow from Operations(2): Funds flow from operations(2) was $60 million ($1.96 per share), up 31% from the Prior Quarter and down 24% from the third quarter of 2023.
• Cash and Debt: As of September 30, 2024, the Company had a cash balance of $278 million, total debt of $787 million and net debt(2) of $509 million. During the Quarter, the Company issued additional $150 million of 9.50% Senior Notes due October 2029 and received cash proceeds of $140 million. Of the total amount of proceeds received, $100 million has been used for financing the purchase price and transaction costs related to the i3 Energy acquisition with the remainder to be used for general corporate purposes.
• Share Buybacks: As a result of the i3 Energy acquisition announced on August 19, 2024, Gran Tierra was required to pause its share buyback program resulting in only 371,130 shares repurchased during the Quarter. From January 1, 2023 to September 30, 2024, the Company repurchased approximately 4.0 million shares, or 12% of shares issued and outstanding at January 1, 2023, from free cash flow(2).
• Return on Average Capital Employed(2): The Company achieved return on average capital employed(2) of 17% during the Quarter and 16% over the trailing 12 months.

Additional Key Financial Metrics:

• Capital Expenditures: Capital expenditures of $53 million were lower than the $61 million in the Prior Quarter due to only operating one drilling rig during the Quarter compared to two in the Prior Quarter. Capital expenditures were up from $43 million compared to the third quarter of 2023 as a result of a more active exploration program in the Quarter when compared to the third quarter of 2023.
• Oil Sales: Gran Tierra generated oil sales of $151 million, down 16% from the third quarter of 2023 as a result of weaker Brent pricing, higher Castilla, Vasconia and Oriente oil differentials and 4% lower sales volumes as a result of lower production. Oil sales decreased 9% from the Prior Quarter primarily due to a 7% decrease in Brent price and higher Castilla, Oriente, and Vasconia oil differentials offset by 1% higher sales volumes.
• Quality and Transportation Discounts: The Company’s quality and transportation discounts per bbl were higher during the Quarter at $14.10, compared to $12.79 in the Prior Quarter and $11.83 in the third quarter of 2023. The Castilla oil differential per bbl widened to $8.83 from $8.21 in the Prior Quarter and from $6.64 in the third quarter of 2023 (Castilla is the benchmark for the Company’s Middle Magdalena Valley Basin oil production). The Vasconia differential per bbl widened to $5.07 from $4.00 in the Prior Quarter, and from $3.59 in the third quarter of 2023. Finally, the Ecuadorian benchmark, Oriente, per bbl was $9.15, up from $8.38 in the Prior Quarter, and up from $7.69 one year ago. The current(3) Castilla differential is approximately $8.50 per bbl, the Vasconia differential is approximately $5.00 per bbl and the Oriente differential is approximately $9.20 per bbl.
• Operating Expenses: Gran Tierra’s operating expenses decreased by 2% to $46 million, compared to the Prior Quarter primarily due to lower workover costs, offset by higher lifting costs primarily associated with inventory fluctuations in Ecuador. Compared to the third quarter of 2023, operating expenses decreased by 7% from $49 million, primarily due to lower lifting costs associated with power generation, equipment rental and road maintenance, partially offset by higher workover activities. On a per bbl basis, operating expense decreased by 2% when compared to the third quarter of 2023 and decreased by 4% when compared to the Prior Quarter.
• Transportation Expenses: The Company’s transportation expenses decreased by 31% to $4 million, compared to the Prior Quarter of $6 million and increased by 2% from the third quarter of 2023. Transportation expenses were higher than the same period in 2023 as a result of increases in trucking tariffs for Acordionero volumes and higher sales volumes transported in Ecuador during the Quarter. Transportation expenses, when compared to the Prior Quarter, were lower due to the utilization of shorter distance delivery points in the Quarter.
• Operating Netback(2)(4): The Company’s operating netback(2)(4) was $34.18 per bbl, down 12% from the Prior Quarter and down 16% from the third quarter of 2023 commensurate with the decrease in Brent Price and higher differentials.
• General and Administrative (“G&A”) Expenses: G&A expenses before stock-based compensation were $3.20 per bbl, down from $3.77 per bbl in the Prior Quarter due to lower consulting, business development and travel expenses and up from $2.68 per bbl, when compared to the third quarter of 2023.
• Cash Netback(2): Cash netback(2) per bbl was $20.34, compared to $15.85 in the Prior Quarter primarily as a result of lower current tax expenses of $5.13 per bbl compared to a current tax expense of $14.54 per bbl in the Prior Quarter as a result of a one time tax adjustment incurred in the Prior Quarter. Compared to one year ago, cash netback(2) per bbl decreased by $5.14 from $25.48 per bbl as a result of lower operating netback primarily due to lower Brent pricing and higher differentials.

Financial and Operational Highlights (all amounts in $000s, except per share and bbl amounts)

	Three Months EndedSeptember 30,			ThreeMonthsEndedJune 30,		Nine Months EndedSeptember 30,
	2024	2023		2024		2024	2023
Net Income (Loss)	$1,133	$6,527		$36,371		$37,426	$(13,998)
Per Share - Basic and Diluted(5)	$0.04	$0.20		$1.16		$1.20	$(0.42)
Oil Sales	$151,373	$179,921		$165,609		$474,559	$482,013
Operating Expenses	(46,060)	(49,367)		(47,035)		(141,561)	(139,227)
Transportation Expenses	(3,911)	(3,842)		(5,690)		(14,185)	(10,599)
Operating Netback(2)(4)	$101,402	$126,712		$112,884		$318,813	$332,187
G&A Expenses Before Stock-Based Compensation	$9,491	$8,307		$10,967		$31,240	$29,052
G&A Stock-Based Compensation (Recovery) Expense	(3,145)	1,931		6,160		6,376	3,748
G&A Expenses, Including Stock Based Compensation	$6,346	$10,238		$17,127		$37,616	$32,800
Adjusted EBITDA(2)	$92,794	$119,235		$103,004		$290,590	$306,391
EBITDA(2)	$97,365	$115,382		$101,187		$290,443	$294,391
Net Cash Provided by Operating Activities	$78,654	$70,381		$73,233		$212,714	$157,511
Funds Flow from Operations(2)	$60,338	$79,000		$46,167		$180,812	$192,122
Capital Expenditures	$52,921	$43,080		$61,273		$169,525	$179,707
Free Cash Flow(2)	$7,417	$35,920		$(15,106)		$11,287	$12,415
Average Daily Volumes (BOPD)
WI Production Before Royalties	32,764	33,940		32,776		32,595	33,098
Royalties	(6,776)	(7,164)		(6,774)		(6,650)	(6,592)
Production NAR	25,988	26,776		26,002		25,945	26,506
(Increase) Decrease in Inventory	(524)	(380)		(811)		(367)	(222)
Sales	25,464	26,396		25,191		25,578	26,284
Royalties, % of WI Production Before Royalties	21%	21%		21%		20%	20%
Per bbl
Brent	$78.71	$85.92		$85.03		$81.82	$81.94
Quality and Transportation Discount	(14.10)	(11.83)		(12.79)		(14.11)	(14.76)
Royalties	(13.58)	(16.06)		(15.31)		(13.97)	(13.58)
Average Realized Price	51.03	58.03		56.93		53.74	53.60
Transportation Expenses	(1.32)	(1.24)		(1.96)		(1.61)	(1.18)
Average Realized Price Net of Transportation Expenses	49.71	56.79		54.97		52.13	52.42
Operating Expenses	(15.53)	(15.92)		(16.17)		(16.03)	(15.48)
Operating Netback(2)(4)	34.18	40.87		38.80		36.10	36.94
G&A Expenses Before Stock-Based Compensation	(3.20)	(2.68)		(3.77)		(3.54)	(3.23)
Transaction Costs	(0.49)	—		—		(0.17)	—
Realized Foreign Exchange Gain (Loss)	0.34	(0.64)		0.37		0.07	(1.77)
Interest Expense, Excluding Amortization of Debt Issuance Costs	(5.66)	(3.84)		(5.38)		(5.38)	(3.85)
Interest Income	0.23	0.09		0.35		0.27	0.19
Net Lease Payments	0.07	0.18		0.02		0.07	0.17
Current Income Tax Expense	(5.13)	(8.50)		(14.54)		(6.96)	(7.08)
Cash Netback(2)	$20.34	$25.48		$15.85		$20.46	$21.37
Share Information (000s)
Common Stock Outstanding, End of Period(5)	30,651	33,288		31,022		30,651	33,288
Weighted Average Number of Shares of Common Stock Outstanding - Basic(5)	30,733	33,287		31,282		31,274	33,675
Weighted Average Number of Shares of Common Stock Outstanding - Diluted(5)	30,733	33,350		31,282		31,274	33,675

(1) Based on the i3 Energy GLJ Report report dated July 31, 2024. See “Presentation of Oil and Gas Information”.(2) Funds flow from operations, operating netback, net debt, cash netback, return on average capital employed, earnings before interest, taxes and depletion, depreciation and accretion (“DD&A”) (“EBITDA”) and EBITDA adjusted for non-cash lease expense, lease payments, foreign exchange gains or losses, stock-based compensation expense, other gains or losses, transaction costs and financial instruments gains or losses (“Adjusted EBITDA”), cash flow and free cash flow are non-GAAP measures and do not have standardized meanings under generally accepted accounting principles in the United States of America (“GAAP”). Cash flow refers to funds flow from operations. Free cash flow refers to funds flow from operations less capital expenditures. Refer to “Non-GAAP Measures” in this press release for descriptions of these non-GAAP measures and, where applicable, reconciliations to the most directly comparable measures calculated and presented in accordance with GAAP.(3) Gran Tierra’s fourth quarter-to-date 2024 total average differentials are for the period from October 1 to October 31, 2024.(4) Operating netback as presented is defined as oil sales less operating and transportation expenses. See the table titled Financial and Operational Highlights above for the components of consolidated operating netback and corresponding reconciliation.(5) Reflects our 1-for-10 reverse stock split that became effective May 5, 2023 and not inclusive of shares of common stock issued in connection with the i3 Energy acquisition on October 31, 2024.

Conference Call Information:

Gran Tierra will host its third quarter 2024 results conference call on Monday, November 4, 2024, at 9:00 a.m. Mountain Time, 11:00 a.m. Eastern Time. Interested parties may access the conference call by registering at the following link: https://https://register.vevent.com/register/BIc9cc718f582741cbbf0eb2cfe5a231b1. The call will also be available via webcast at www.grantierra.com.

Corporate Presentation:

Gran Tierra’s Corporate Presentation has been updated and is available on the Company website at www.grantierra.com.

Contact Information

For investor and media inquiries please contact:

Gary Guidry President & Chief Executive Officer

Ryan Ellson Executive Vice President & Chief Financial Officer

+1-403-265-3221

info@grantierra.com

About Gran Tierra Energy Inc.Gran Tierra Energy Inc. together with its subsidiaries is an independent international energy company currently focused on oil and natural gas exploration and production in Canada, Colombia and Ecuador. The Company is currently developing its existing portfolio of assets in Canada, Colombia and Ecuador and will continue to pursue additional new growth opportunities that would further strengthen the Company’s portfolio. The Company’s common stock trades on the NYSE American, the Toronto Stock Exchange and the London Stock Exchange under the ticker symbol GTE. Additional information concerning Gran Tierra is available at www.grantierra.com. Except to the extent expressly stated otherwise, information on the Company’s website or accessible from our website or any other website is not incorporated by reference into and should not be considered part of this press release. Investor inquiries may be directed to info@grantierra.com or (403) 265-3221.

Gran Tierra’s Securities and Exchange Commission (the “SEC”) filings are available on the SEC website at http://www.sec.gov. The Company’s Canadian securities regulatory filings are available on SEDAR+ at http://www.sedarplus.ca and UK regulatory filings are available on the National Storage Mechanism website at https://data.fca.org.uk/#/nsm/nationalstoragemechanism.

Forward Looking Statements and Legal Advisories:This press release contains opinions, forecasts, projections, and other statements about future events or results that constitute forward-looking statements within the meaning of the United States Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, and financial outlook and forward looking information within the meaning of applicable Canadian securities laws (collectively, “forward-looking statements”). All statements other than statements of historical facts included in this press release regarding our business strategy, plans and objectives of our management for future operations, capital spending plans and benefits of the changes in our capital program or expenditures, our liquidity and financial condition, and those statements preceded by, followed by or that otherwise include the words “expect,” “plan,” “can,” “will,” “should,” “guidance,” “forecast,” “budget,” “estimate,” “signal,” “progress” and “believes,” derivations thereof and similar terms identify forward-looking statements. In particular, but without limiting the foregoing, this press release contains forward-looking statements regarding: the Company’s leverage ratio target, the Company’s plans regarding strategic investments, acquisitions, including the anticipated benefits and operating synergies expected from the acquisition of i3 Energy, and growth, the Company’s drilling program and capital expenditures and the Company’s expectations of commodity prices, including future gas pricing in Canada, exploration and production trends and its positioning for 2024. The forward-looking statements contained in this press release reflect several material factors and expectations and assumptions of Gran Tierra including, without limitation, that Gran Tierra will continue to conduct its operations in a manner consistent with its current expectations, pricing and cost estimates (including with respect to commodity pricing and exchange rates), the ability of Gran Tierra to successfully integrate the assets and operations of i3 Energy or realize the anticipated benefits and operating synergies expected from the acquisition of i3 Energy, the general continuance of assumed operational, regulatory and industry conditions in Canada, Colombia and Ecuador, and the ability of Gran Tierra to execute its business and operational plans in the manner currently planned.

Among the important factors that could cause our actual results to differ materially from the forward-looking statements in this press release include, but are not limited to: certain of our operations are located in South America and unexpected problems can arise due to guerilla activity, strikes, local blockades or protests; technical difficulties and operational difficulties may arise which impact the production, transport or sale of our products; other disruptions to local operations; global health events; global and regional changes in the demand, supply, prices, differentials or other market conditions affecting oil and gas, including inflation and changes resulting from a global health crisis, geopolitical events, including the conflicts in Ukraine and the Gaza region, or from the imposition or lifting of crude oil production quotas or other actions that might be imposed by OPEC and other producing countries and the resulting company or third-party actions in response to such changes; changes in commodity prices, including volatility or a prolonged decline in these prices relative to historical or future expected levels; the risk that current global economic and credit conditions may impact oil prices and oil consumption more than we currently predict. which could cause further modification of our strategy and capital spending program; prices and markets for oil and natural gas are unpredictable and volatile; the effect of hedges; the accuracy of productive capacity of any particular field; geographic, political and weather conditions can impact the production, transport or sale of our products; our ability to execute our business plan, which may include acquisitions, and realize expected benefits from current or future initiatives; the risk that unexpected delays and difficulties in developing currently owned properties may occur; the ability to replace reserves and production and develop and manage reserves on an economically viable basis; the accuracy of testing and production results and seismic data, pricing and cost estimates (including with respect to commodity pricing and exchange rates); the risk profile of planned exploration activities; the effects of drilling down-dip; the effects of waterflood and multi-stage fracture stimulation operations; the extent and effect of delivery disruptions, equipment performance and costs; actions by third parties; the timely receipt of regulatory or other required approvals for our operating activities; the failure of exploratory drilling to result in commercial wells; unexpected delays due to the limited availability of drilling equipment and personnel; volatility or declines in the trading price of our common stock or bonds; the risk that we do not receive the anticipated benefits of government programs, including government tax refunds; our ability to access debt or equity capital markets from time to time to raise additional capital, increase liquidity, fund acquisitions or refinance debt; our ability to comply with financial covenants in our indentures and make borrowings under any future credit agreement; and the risk factors detailed from time to time in Gran Tierra’s periodic reports filed with the Securities and Exchange Commission, including, without limitation, under the caption “Risk Factors” in Gran Tierra’s Annual Report on Form 10-K for the year ended December 31, 2023 filed February 20, 2024 and its other filings with the SEC. These filings are available on the SEC website at http://www.sec.gov and on SEDAR+ at www.sedarplus.ca.

The forward-looking statements contained in this press release are based on certain assumptions made by Gran Tierra based on management’s experience and other factors believed to be appropriate. Gran Tierra believes these assumptions to be reasonable at this time, but the forward-looking statements are subject to risk and uncertainties, many of which are beyond Gran Tierra’s control, which may cause actual results to differ materially from those implied or expressed by the forward looking statements. The risk that the assumptions on which the 2024 outlook are based prove incorrect may increase the later the period to which the outlook relates. All forward-looking statements are made as of the date of this press release and the fact that this press release remains available does not constitute a representation by Gran Tierra that Gran Tierra believes these forward-looking statements continue to be true as of any subsequent date. Actual results may vary materially from the expected results expressed in forward-looking statements. Gran Tierra disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as expressly required by applicable law. In addition, historical, current and forward-looking sustainability-related statements may be based on standards for measuring progress that are still developing, internal controls and processes that continue to evolve, and assumptions that are subject to change in the future.

Following Gran Tierra’s acquisition of i3 Energy, investors should not rely on Gran Tierra’s previously issued financial and production guidance for 2024, which is no longer applicable on a combined company basis.

Non-GAAP Measures

This press release includes non-GAAP financial measures as further described herein. These non-GAAP measures do not have a standardized meaning under GAAP. Investors are cautioned that these measures should not be construed as alternatives to net income or loss, cash flow from operating activities or other measures of financial performance as determined in accordance with GAAP. Gran Tierra’s method of calculating these measures may differ from other companies and, accordingly, they may not be comparable to similar measures used by other companies. Each non-GAAP financial measure is presented along with the corresponding GAAP measure so as to not imply that more emphasis should be placed on the non-GAAP measure.

Operating netback, as presented, is defined as oil sales less operating and transportation expenses. See the table entitled Financial and Operational Highlights above for the components of consolidated operating netback and corresponding reconciliation.

Return on average capital employed as presented is defined as earnings before interest and taxes ("EBIT"; annualized, if the period is other than one year) divided by average capital employed (total assets minus cash and current liabilities; average of the opening and closing balances for the period).

		Three Months EndedSeptember 30,				Twelve Month TrailingSeptember 30,				As at September 30,
Return on Average Capital Employed - (Non-GAAP) Measure ($000s)			2024				2024				2024
Net Income		$	1,133			$	45,137
Adjustments to reconcile net income to EBIT:
Interest Expense			19,892				74,503
Income Tax Expense			20,767				34,589
EBIT		$	41,792			$	154,229
Total Assets										$	1,533,378
Less Current Liabilities											263,492
Less Cash and Cash Equivalents											277,645
Capital Employed										$	992,241
Annualized EBIT*		$	167,168
Divided by Average Capital Employed			992,241				992,241
Return on Average Capital Employed			17	%			16	%

*Annualized EBIT was calculated for the three months ended September 30, 2024, by multiplying the quarter-to-date EBIT by 4.

Cash netback as presented is defined as net income or loss adjusted for DD&A expenses, deferred tax expense or recovery, stock-based compensation expense or recovery, amortization of debt issuance costs, non-cash lease expense, lease payments, unrealized foreign exchange gain or loss and other gain or loss. Management believes that operating netback and cash netback are useful supplemental measures for investors to analyze financial performance and provide an indication of the results generated by Gran Tierra’s principal business activities prior to the consideration of other income and expenses. A reconciliation from net income or loss to cash netback is as follows:

	Three Months EndedSeptember 30,							ThreeMonthsEndedJune 30,				Nine Months EndedSeptember 30,
Cash Netback - (Non-GAAP) Measure ($000s)		2024			2023				2024				2024			2023
Net Income (Loss)	$	1,133		$	6,527			$	36,371			$	37,426		$	(13,998	)
Adjustments to reconcile net income (loss) to cash netback
DD&A expenses		55,573			55,019				55,490				167,213			163,424
Deferred tax expense (recovery)		5,550			13,990				(51,361	)			(32,332	)		43,242
Stock-based compensation (recovery) expense		(3,145	)		1,931				6,160				6,376			3,748
Amortization of debt issuance costs		3,109			1,594				2,760				9,175			3,394
Non-cash lease expense		1,370			1,235				1,381				4,164			3,488
Lease payments		(1,171	)		(676	)			(1,311	)			(3,540	)		(1,918	)
Unrealized foreign exchange gain		(2,081	)		(266	)			(3,323	)			(7,670	)		(7,814	)
Other gain		—			(354	)			—				—			(1,444	)
Cash netback	$	60,338		$	79,000			$	46,167			$	180,812		$	192,122

EBITDA, as presented, is defined as net income or loss adjusted for DD&A expenses, interest expense and income tax expense or recovery. Adjusted EBITDA, as presented, is defined as EBITDA adjusted for non-cash lease expense, lease payments, foreign exchange gain or loss, stock-based compensation expense, transaction costs and other gain or loss. Management uses this supplemental measure to analyze performance and income generated by our principal business activities prior to the consideration of how non-cash items affect that income, and believes that this financial measure is useful supplemental information for investors to analyze our performance and our financial results. A reconciliation from net income or loss to EBITDA and adjusted EBITDA is as follows:

	Three Months EndedSeptember 30,							ThreeMonthsEndedJune 30,				Nine Months EndedSeptember 30,
EBITDA - (Non-GAAP) Measure ($000s)		2024			2023				2024				2024			2023
Net Income (Loss)	$	1,133		$	6,527			$	36,371			$	37,426		$	(13,998	)
Adjustments to reconcile net income (loss) to EBITDA and Adjusted EBITDA
DD&A expenses		55,573			55,019				55,490				167,213			163,424
Interest expense		19,892			13,503				18,398				56,714			38,017
Income tax expense (recovery)		20,767			40,333				(9,072	)			29,090			106,948
EBITDA	$	97,365		$	115,382			$	101,187			$	290,443		$	294,391
Non-cash lease expense		1,370			1,235				1,381				4,164			3,488
Lease payments		(1,171	)		(676	)			(1,311	)			(3,540	)		(1,918	)
Foreign exchange (gain) loss		(3,084	)		1,717				(4,413	)			(8,312	)		8,126
Stock-based compensation expense		(3,145	)		1,931				6,160				6,376			3,748
Transaction costs		1,459			—				—				1,459			—
Other loss (gain)		—			(354	)			—				—			(1,444	)
Adjusted EBITDA	$	92,794		$	119,235			$	103,004			$	290,590		$	306,391

Funds flow from operations, as presented, is defined as net income or loss adjusted for DD&A expenses, deferred tax expense or recovery, stock-based compensation expense, amortization of debt issuance costs, non-cash lease expense, lease payments, unrealized foreign exchange gain, and other gain or loss. Management uses this financial measure to analyze performance and income or loss generated by our principal business activities prior to the consideration of how non-cash items affect that income or loss, and believes that this financial measure is also useful supplemental information for investors to analyze performance and our financial results. Free cash flow, as presented, is defined as funds flow from operations adjusted for capital expenditures. Management uses this financial measure to analyze cash flow generated by our principal business activities after capital requirements and believes that this financial measure is also useful supplemental information for investors to analyze performance and our financial results. A reconciliation from net income or loss to both funds flow from operations and free cash flow is as follows:

	Three Months EndedSeptember 30,							ThreeMonthsEndedJune 30,				Nine Months EndedSeptember 30,
Funds Flow From Operations - (Non-GAAP) Measure ($000s)		2024			2023				2024				2024			2023
Net Income (Loss)	$	1,133		$	6,527			$	36,371			$	37,426		$	(13,998	)
Adjustments to reconcile net income (loss) to funds flow from operations
DD&A expenses		55,573			55,019				55,490				167,213			163,424
Deferred tax expense (recovery)		5,550			13,990				(51,361	)			(32,332	)		43,242
Stock-based compensation (recovery) expense		(3,145	)		1,931				6,160				6,376			3,748
Amortization of debt issuance costs		3,109			1,594				2,760				9,175			3,394
Non-cash lease expense		1,370			1,235				1,381				4,164			3,488
Lease payments		(1,171	)		(676	)			(1,311	)			(3,540	)		(1,918	)
Unrealized foreign exchange gain		(2,081	)		(266	)			(3,323	)			(7,670	)		(7,814	)
Other loss (gain)		—			(354	)			—				—			(1,444	)
Funds flow from operations	$	60,338		$	79,000			$	46,167			$	180,812		$	192,122
Capital expenditures	$	52,921		$	43,080			$	61,273			$	169,525		$	179,707
Free cash flow	$	7,417		$	35,920			$	(15,106	)		$	11,287		$	12,415

Net debt as of September 30, 2024, was $509 million, calculated using the sum of the aggregate principal amount of 6.25% Senior Notes, 7.75% Senior Notes, and 9.50% Senior Notes outstanding, excluding deferred financing fees, totaling $787 million, less cash and cash equivalents of $278 million.

Presentation of Oil and Gas Information

All reserves value and ancillary information contained in this press release regarding Gran Tierra (not including reserves value and ancillary information regarding i3 Energy) have been prepared by the Company’s independent qualified reserves evaluator McDaniel & Associates Consultants Ltd. (“McDaniel”) in a report with an effective date of December 31, 2023 (the “Gran Tierra McDaniel Reserves Report”) and calculated in compliance with Canadian National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) and the Canadian Oil and Gas Evaluation Handbook (“COGEH”), unless otherwise expressly stated. All reserves value and ancillary information contained in this press release regarding i3 Energy have been prepared by i3 Energy’s independent qualified reserves evaluator GLJ Ltd. (“GLJ”) in a fair market value report with an effective date of July 31, 2024 (the “i3 Energy GLJ Report”) and calculated in compliance with NI 51-101 and COGEH, unless otherwise expressly stated.

Barrel of oil equivalents (“boe”) have been converted on the basis of six thousand cubic feet (“Mcf”) natural gas to 1 bbl of oil. Boe’s may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In addition, given that the value ratio based on the current price of oil as compared with natural gas is significantly different from the energy equivalent of six to one, utilizing a boe conversion ratio of 6 Mcf: 1 bbl would be misleading as an indication of value.

The following reserves categories are discussed in this press release: Proved (“1P”), 1P plus Probable (“2P”) and 2P plus Possible (“3P”) and Proved Developed Producing (“PDP”). Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves. Proved developed producing reserves are those proved reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty. Certain terms used in this press release but not defined are defined in NI 51-101, CSA Staff Notice 51-324 – Revised Glossary to NI 51-101 Standards of Disclosure for Oil and Gas Activities (“CSA Staff Notice 51-324”) and/or the COGEH and, unless the context otherwise requires, shall have the same meanings herein as in NI 51-101, CSA Staff Notice 51-324 and the COGEH, as the case may be.

Estimates of reserves for individual properties may not reflect the same level of confidence as estimates of reserves for all properties, due to the effect of aggregation. There is no assurance that the forecast price and cost assumptions applied by McDaniel or GLJ in evaluating Gran Tierra’s or i3 Energy’s reserves, respectively, will be attained and variances could be material. There are numerous uncertainties inherent in estimating quantities of crude oil and natural gas reserves. The reserves information set forth in the Gran Tierra McDaniel Reserves Report and the i3 Energy GLJ Report are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or less than the estimates provided therein. All reserves assigned in the Gran Tierra McDaniel Reserves Report are located in Colombia and Ecuador and presented on a consolidated basis by foreign geographic area.

Booked drilling locations of i3 Energy disclosed herein are derived from the i3 Energy GLJ Report and account for drilling locations that have associated 2P reserves.

References to a formation where evidence of hydrocarbons has been encountered is not necessarily an indicator that hydrocarbons will be recoverable in commercial quantities or in any estimated volume. Gran Tierra’s reported production is a mix of light crude oil and medium and heavy crude oil for which there is not a precise breakdown since the Company’s oil sales volumes typically represent blends of more than one type of crude oil. Well test results should be considered as preliminary and not necessarily indicative of long-term performance or of ultimate recovery. Well log interpretations indicating oil and gas accumulations are not necessarily indicative of future production or ultimate recovery. If it is indicated that a pressure transient analysis or well-test interpretation has not been carried out, any data disclosed in that respect should be considered preliminary until such analysis has been completed. References to thickness of “oil pay” or of a formation where evidence of hydrocarbons has been encountered is not necessarily an indicator that hydrocarbons will be recoverable in commercial quantities or in any estimated volume.

This press release contains certain oil and gas metrics, including operating netback and cash netback, which do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies and should not be used to make comparisons. These metrics are calculated as described in this press release and management believes that they are useful supplemental measures for the reasons described in this press release.

Such metrics have been included herein to provide readers with additional measures to evaluate the Company’s performance; however, such measures are not reliable indicators of the future performance of the Company and future performance may not compare to the performance in previous periods.

References in this press release to IP30, IP90 and other short-term production rates of Gran Tierra are useful in confirming the presence of hydrocarbons, however such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long-term performance or of ultimate recovery. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production of Gran Tierra. Gran Tierra cautions that such results should be considered to be preliminary.

Disclosure of Reserve Information and Cautionary Note to U.S. Investors

Unless expressly stated otherwise, all estimates of proved, probable and possible reserves and related future net revenue disclosed in this press release have been prepared in accordance with NI 51-101. Estimates of reserves and future net revenue made in accordance with NI 51-101 will differ from corresponding estimates prepared in accordance with applicable SEC rules and disclosure requirements of the U.S. Financial Accounting Standards Board (“FASB”), and those differences may be material. NI 51-101, for example, requires disclosure of reserves and related future net revenue estimates based on forecast prices and costs, whereas SEC and FASB standards require that reserves and related future net revenue be estimated using average prices for the previous 12 months. In addition, NI 51-101 permits the presentation of reserves estimates on a “company gross” basis, representing Gran Tierra's working interest share before deduction of royalties, whereas SEC and FASB standards require the presentation of net reserve estimates after the deduction of royalties and similar payments. There are also differences in the technical reserves estimation standards applicable under NI 51-101 and, pursuant thereto, the COGEH, and those applicable under SEC and FASB requirements.

In addition to being a reporting issuer in certain Canadian jurisdictions, Gran Tierra is a registrant with the SEC and subject to domestic issuer reporting requirements under U.S. federal securities law, including with respect to the disclosure of reserves and other oil and gas information in accordance with U.S. federal securities law and applicable SEC rules and regulations (collectively, “SEC requirements”). Disclosure of such information in accordance with SEC requirements is included in the Company's Annual Report on Form 10-K and in other reports and materials filed with or furnished to the SEC and, as applicable, Canadian securities regulatory authorities. The SEC permits oil and gas companies that are subject to domestic issuer reporting requirements under U.S. federal securities law, in their filings with the SEC, to disclose only estimated proved, probable and possible reserves that meet the SEC's definitions of such terms. Gran Tierra has disclosed estimated proved, probable and possible reserves in its filings with the SEC. In addition, Gran Tierra prepares its financial statements in accordance with United States generally accepted accounting principles, which require that the notes to its annual financial statements include supplementary disclosure in respect of the Company's oil and gas activities, including estimates of its proved oil and gas reserves and a standardized measure of discounted future net cash flows relating to proved oil and gas reserve quantities. This supplementary financial statement disclosure is presented in accordance with FASB requirements, which align with corresponding SEC requirements concerning reserves estimation and reporting.