Open the filing on EDGARGran Tierra Energy Inc. Reports Third Quarter 2026 Results
- Delivered Total Company Average Third Quarter WI Production of 39,904 BOEPD, Including 12,852 BOEPD in Canada
- Ended the Quarter with $141 Million of Cash and Approximately $53 Million of Undrawn Credit Facility Availability
- Announced the Formal Ratification of its Exploration, Development and Production Sharing Agreement with SOCAR in Azerbaijan
- Obtained Requisite Consent for Amendments to the Indenture Governing its 9.75% Senior Secured Amortizing Notes due 2031
- Received Stockholder Approval for the Sale of Colombian and Ecuadorian Businesses
CALGARY, ALBERTA, November 5, 2026, 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, 2026 (the “Quarter”). All dollar amounts are in United States (“U.S.”) dollars and all production volumes are on an average working interest (“WI”) before royalties basis unless otherwise indicated. Production is expressed in barrels (“bbl”) of oil equivalent (“boe”) per day (“boepd” or “boe/d”), and per boe amounts are based on WI sales before royalties. For per boe amounts based on net after royalty (“NAR”) production, see Gran Tierra’s Quarterly Report on Form 10-Q filed November 5, 2026.
Message to Stockholders
Gary Guidry, President and Chief Executive Officer of Gran Tierra, commented: “During the Quarter, we announced the sale of our Colombia and Ecuador businesses, received noteholder consent required to amend one of our indentures and subsequent to Quarter end, we received shareholder approval to proceed with the sale. Also subsequent to Quarter end, our Exploration, Development and Production Sharing Agreement (“EDPSA”) in Azerbaijan was ratified by Parliament (the Milli Majlis). With $141 million of cash at quarter-end, we are well positioned as we work through the remaining approvals and conditions to closing, including regulatory approvals in Colombia and Ecuador. On closing, we expect to be debt-free, with the flexibility to return capital to stockholders and build our businesses in Canada and Azerbaijan.
During the Quarter, operationally, production was down from the second quarter primarily as a result of lower production in Colombia, partly due to a contractual reduction in our working interest production at higher oil prices in the Suroriente Block, and the asset sale in Canada. Financially, compared to the second quarter, lower realized prices in South America reduced cash flow by approximately $17 million, net of lower royalties. Brent decreased by $5.39 per bbl and quality and transportation discounts increased by $5.52 per bbl, reflecting wider differentials and the cost of alternative transportation routes while the Ecuador and Colombia border remains closed. While pricing impacted cash flow, the assets across the portfolio continue to perform well.”
Key Highlights of the Quarter:
- Production: Gran Tierra’s total average WI production was 39,904 boepd, which was 4% lower than the second quarter of 2026 (the “Prior Quarter”) and 7% lower than the third quarter of 2025. The decrease from the Prior Quarter was primarily due to lower production from the Cohembi field in Colombia and the sale of the Lodgepole area in Canada in June 2026, partially offset by an increase in production from the Acordionero field in Colombia. The decrease in production when compared to the third quarter of 2025 was primarily due to lower production in Colombia and the sale of the Simonette and Lodgepole areas in Canada, partially offset by higher than anticipated production results from wells in
the Charapa and Chanangue Blocks and additional production from the Perico Block in Ecuador acquired in December 2025.
- Net Loss: Gran Tierra incurred a net loss of $42 million or $1.20 per share, basic and diluted, compared to net income of $25 million in the Prior Quarter and a net loss of $20 million or $0.57 per share, basic and diluted, in the third quarter of 2025. The net loss in the Quarter was primarily due to non-cash stock-based compensation expense of $30 million, driven by the increase in the Company’s share price during the Quarter, and derivative instrument losses of $29 million, partially offset by a deferred income tax recovery of $30 million.
- Gross Profit: The Company’s gross profit was approximately $41 million for the Quarter, which was down from approximately $75 million for the Prior Quarter and up from $15 million in the third quarter of 2025. On a per boe basis, gross profit for the Quarter was $10.77, down from $19.90 in the Prior Quarter and up from $3.67 in the third quarter of 2025.
- Operating Netback: The Company’s operating netback was $25.98 per boe, down 25% from the Prior Quarter primarily due to lower Brent oil prices, higher quality and transportation discounts and higher operating expenses per boe, and up 37% from the third quarter of 2025 primarily due to higher Brent oil prices, partially offset by higher quality and transportation discounts and royalties.
- South American Quality and Transportation Discounts: The Company’s average quality and transportation discounts per bbl in South America during the Quarter increased to $15.83 from $10.80 in the third quarter of 2025 and $10.31 in the Prior Quarter. The increase from the Prior Quarter was primarily due to an increase in differentials and higher transportation discounts.
- The Castilla oil differential per bbl was $13.73, up from $9.71 in the Prior Quarter and up from $4.88 in the third quarter of 2025 (Castilla is the benchmark for the Company’s Middle Magdalena Valley Basin oil production). The Vasconia differential per bbl was $6.68, up from $1.42 in the Prior Quarter and up from $1.88 in the third quarter of 2025. The Oriente differential per bbl (Oriente is the benchmark for the Company’s Ecuador oil production) was $10.32, up from $2.01 in the Prior Quarter and up from $7.20 in the third quarter of 2025.
- The Company’s sales price in Ecuador is the average Brent price less discounts for the month prior to lifting (“M-1”). The impact of the Company’s M-1 pricing in Ecuador of $85.43 per bbl decreased revenue before royalties by approximately $5 million when compared to the average Brent price for the Quarter of $91.29 per bbl. In the Prior Quarter, the M-1 pricing structure increased revenue before royalties by $4 million.
- Adjusted EBITDA: Adjusted EBITDA was $68 million compared to $85 million in the Prior Quarter and $69 million in the third quarter of 2025.
- Net Cash Provided by Operating Activities: Net cash provided by operating activities was $27 million ($0.75 per share), down 54% from the Prior Quarter and down 45% from the third quarter of 2025.
- Funds Flow from Operations: Funds flow from operations was $32 million ($0.89 per share), down 48% from the Prior Quarter and down 24% from the third quarter of 2025. The decrease from the Prior Quarter was primarily due to lower Brent prices, higher quality and transportation discounts, higher operating expenses, realized foreign exchange losses and transaction costs, partially offset by lower realized derivative losses.
- Cash and Debt: As of September 30, 2026, the Company had a cash balance of $141 million, total gross debt of $591 million and net debt of $450 million. During the nine months ended September 30, 2026, Gran Tierra repurchased $24.2 million in face value of the Company’s 9.75% Senior Secured Amortizing Notes due 2031 (the “2031 Notes”) at a discount of 11% to the face value of the repurchased 2031 Notes.
- Liquidity: In addition to the $141 million cash on hand as of September 30, 2026, the Company has approximately $53 million in undrawn availability under its Canadian revolving credit facility.
Secured Formal Ratification of the EDPSA with SOCAR in Azerbaijan
- On October 5, 2026, Azerbaijan’s Parliament (the Milli Majlis) ratified Gran Tierra’s EDPSA for the onshore Guba-Khazaryani region. Gran Tierra signed the EDPSA with the State Oil Company of the Republic of Azerbaijan (“SOCAR”) on February 18, 2026.
- Gran Tierra has also completed the flying of its airborne digital full tensor gradiometry (“dFTG”) survey, acquiring 102 lines (5,775 line-km) over 4,815 km². Once processed and integrated with existing seismic and exploratory well data, the dFTG data is expected to help define the geometry of sedimentary basins and fault-related structures that may trap oil and gas, guiding the selection of future seismic acquisition areas and drilling locations.
Previously Announced Sale of Colombian and Ecuadorian Businesses to Maurel & Prom
- On August 5, 2026, Gran Tierra entered into a definitive Share Sale and Purchase Agreement (the “Share Purchase Agreement”) to sell its Colombian and Ecuadorian businesses (the “Sale”) to Maurel & Prom for total consideration of approximately $1.33 billion, subject to adjustment, including the assumption of its 2031 Notes, its 9.50% Senior Secured Amortizing Notes due 2029 and the facility under its oil prepayment agreement. Expected net cash proceeds are approximately $315 million. Of the expected net cash proceeds, approximately $250 million is payable in cash, including the $50 million deposit received during the Quarter, which is included in the $141 million cash balance, and the remaining $65 million is payable under an unsecured note 364 days after closing.
- On September 22, 2026, following receipt of the requisite consents from holders of the 2031 Notes, the Company executed a supplemental indenture in connection with the Sale, which becomes operative on closing. On October 9, 2026, Gran Tierra’s stockholders approved the Sale. Closing remains subject to the remaining consents, regulatory approvals in Colombia and Ecuador and other closing conditions, and the Company continues to target closing before the end of the year.
- As previously announced, the Company expects to use a portion of the net cash proceeds from the Sale to return capital to stockholders through a share repurchase, the structure, size and terms of which will be determined by the Board of Directors and announced separately. Any share repurchase is conditional on completion of the Sale.
Additional Key Financial Metrics:
- Capital Expenditures: Capital expenditures of $31 million were lower than the $54 million in the Prior Quarter and lower than the $57 million in the third quarter of 2025, as the Company did not drill any wells during the Quarter. Spending was concentrated in Colombia, which accounted for $25 million, primarily on development activities.
- Oil, Natural Gas, and Natural Gas Liquids (“NGL”) Sales: Gran Tierra generated sales of $168 million, up 13% from the third quarter of 2025 due to a 34% increase in Brent price, partially offset by a 6% decrease in sales volumes and higher quality and transportation discounts in Colombia associated with the use of alternative transportation routes for Putumayo production, as the Colombia and Ecuador border remained closed. These discounts had an impact of approximately $3.7 million for the Quarter and $13.6 million year to date in 2026. Sales decreased 10% from the Prior Quarter primarily due to a 6% decrease in Brent price, higher quality and transportation discounts in Colombia and a shift from a premium to a discount in Ecuador, partially offset by a 21% decrease in royalties per boe as a result of lower benchmark oil prices during the Quarter.
- Free Cash Flow: During the Quarter, the Company generated free cash flow of approximately $1 million, compared to $6 million in the Prior Quarter and negative free cash flowof $16 million reported in the third quarter of 2025. The decrease from the Prior Quarter was primarily due to lower funds flow from operations, partially offset by lower capital expenditures.
- Operating Expenses: Total operating expenses increased by 24% to $64 million and on a per boe basis increased by 25% when compared to the Prior Quarter, primarily due to higher workover activities and lifting costs on inventory
accumulated at the end of the Prior Quarter and sold during the Quarter, including two liftings in Ecuador compared to one in the Prior Quarter, and the strengthening of the Colombian peso. When compared to the third quarter of 2025, total operating expenses decreased by 6%, primarily due to the sale of the Simonette and Lodgepole areas in Canada, lower workover activities, reduced field personnel costs and lower equipment maintenance, while on a per boe basis they increased by 1% as lower sales volumes more than offset the lower costs.
- Transportation Expenses: The Company’s transportation expenses increased by 42% to $5.5 million, compared to transportation expenses of $3.9 million in the Prior Quarter, and increased by 29% compared to transportation expenses of $4.3 million in the third quarter of 2025. The increases were primarily due to higher volumes transported via pipeline, which had higher costs per boe.
- General and Administrative (“G&A”) Expenses: G&A expenses before stock-based compensation were $11.8 million or $3.11 per boe, a decrease from $3.49 per boe in the Prior Quarter and $3.27 per boe in the third quarter of 2025, primarily due to lower consulting and legal expenses, lower salaries associated with personnel optimization and lower costs associated with project optimization during the current Quarter.
- Cash Netback: Cash netback per boe was $8.34 during the Quarter, a decrease from $15.90 in the Prior Quarter and a decrease from $10.28 in the third quarter of 2025. The decrease from the Prior Quarter was primarily due to a lower operating netback, realized foreign exchange losses and transaction costs, partially offset by lower realized derivative losses. The decrease from the third quarter of 2025 was primarily due to realized derivative losses compared to gains in the prior-year period, realized foreign exchange losses and transaction costs, partially offset by a higher operating netback.
Hedging Entered into Subsequent to the Quarter:
- Gran Tierra has secured price protection on 5,000 bbl per day of first quarter 2027 oil sales, through its physical sales arrangements with Trafigura. The structure provides a floor of $95.00 per barrel and a ceiling of $111.00 per barrel, based on monthly average Brent prices. In any month where Brent averages below $80.00 per barrel, Gran Tierra receives the market price plus $15.00 per barrel. The structure was put in place at no upfront cost.
Financial and Operational Highlights (all amounts in $000s, except per share and boe amounts)
| Consolidated Information | Three Months Ended September 30, | Three Months Ended June 30, | Nine Months Ended September 30, |
| 2026 | 2025 | 2026 | 2026 | 2025 |
| Net (Loss) Income | $(42,415) | $(19,950) | $24,861 | $(136,726) | $(51,971) |
| Per Share - Basic | $(1.20) | $(0.57) | $0.70 | $(3.87) | $(1.47) |
| Per Share - Diluted | $(1.20) | $(0.57) | $0.70 | $(3.87) | $(1.47) |
| Gross Profit | $40,872 | $14,879 | $75,460 | $153,029 | $66,293 |
| Depletion and Accretion | $57,706 | $61,908 | $56,253 | $177,867 | $196,286 |
| Operating Netback | $98,578 | $76,787 | $131,713 | $330,896 | $262,579 |
| Oil, Natural Gas and NGL Sales | $168,306 | $149,254 | $187,181 | $527,544 | $466,784 |
| Operating Expenses | (64,186) | (68,170) | (51,561) | (181,896) | (190,863) |
| Transportation Expenses | (5,542) | (4,297) | (3,907) | (14,752) | (13,342) |
| Operating Netback | $98,578 | $76,787 | $131,713 | $330,896 | $262,579 |
| G&A Expenses Before Stock-Based Compensation | $11,814 | $13,246 | $13,219 | $40,182 | $39,306 |
| G&A Stock-Based Compensation Expense (Recovery) | 30,465 | 143 | (3,757) | 46,384 | 172 |
| G&A Expenses, Including Stock-Based Compensation | $42,279 | $13,389 | $9,462 | $86,566 | $39,478 |
| EBITDA | $20,279 | $59,202 | $132,156 | $126,420 | $223,820 |
| Adjusted EBITDA | $68,096 | $69,034 | $85,071 | $227,102 | $231,183 |
| Net Cash Provided by Operating Activities | $26,558 | $48,149 | $57,414 | $256,706 | $156,056 |
| Funds Flow from Operations | $31,640 | $41,685 | $60,289 | $134,752 | $150,935 |
| Capital Expenditures (Before Changes in Working Capital) | $30,660 | $64,184 | $54,309 | $130,328 | $218,155 |
| Free Cash Flow | $980 | $(15,655) | $5,980 | $4,424 | $(52,302) |
| Average Daily Production (boe/d) | | | | | |
| WI Production Before Royalties | 39,904 | 42,685 | 41,501 | 42,280 | 45,495 |
| Royalties | (8,514) | (6,723) | (9,511) | (8,596) | (7,396) |
| Production NAR | 31,390 | 35,962 | 31,990 | 33,684 | 38,099 |
| Decrease in Inventory | 1,334 | 1,391 | 176 | 1,341 | 132 |
| Sales | 32,724 | 37,353 | 32,166 | 35,025 | 38,231 |
| Royalties, % of WI Production Before Royalties | 21% | 16% | 23% | 20% | 16% |
| Cash Netback ($/boe) | | | | | |
| Gross Profit | $10.77 | $3.67 | $19.90 | $12.85 | $5.32 |
| Depletion and Accretion | $15.21 | $15.27 | $14.83 | $14.94 | $15.76 |
| Operating Netback | $25.98 | $18.94 | $34.73 | $27.79 | $21.08 |
| Average Realized Price before Royalties | 55.90 | 43.43 | 63.94 | 55.17 | 44.72 |
| Royalties | (11.54) | (6.62) | (14.59) | (10.87) | (7.25) |
| Average Realized Price | 44.36 | 36.81 | 49.35 | 44.30 | 37.47 |
| Transportation Expenses | (1.46) | (1.06) | (1.03) | (1.24) | (1.07) |
| Average Realized Price Net of Transportation Expenses | 42.90 | 35.75 | 48.32 | 43.06 | 36.40 |
| Operating Expenses | (16.92) | (16.81) | (13.59) | (15.27) | (15.32) |
| Operating Netback | 25.98 | 18.94 | 34.73 | 27.79 | 21.08 |
| Cash G&A Expenses | (3.11) | (3.27) | (3.49) | (3.37) | (3.16) |
| Other Taxes | (0.27) | (0.75) | (0.37) | (0.29) | (0.33) |
| Severance Expenses | - | - | (0.03) | (0.22) | - |
| Transaction Costs | (1.29) | - | - | (0.41) | - |
| Realized Foreign Exchange (Loss) Gain | (2.81) | (0.53) | 0.07 | (1.01) | (0.39) |
| Cash Settlement on Derivative Instruments | (4.80) | 1.84 | (8.97) | (5.32) | 0.77 |
| Interest Expense, Excluding Amortization of Debt Issuance Costs, Non-Cash Interest, and Senior Notes Exchange Fees | (4.32) | (5.22) | (4.17) | (4.49) | (4.89) |
| Interest Income | 0.14 | 0.05 | 0.13 | 0.12 | 0.07 |
| Other Cash Gain | 0.04 | 0.31 | 0.43 | 0.18 | 0.13 |
| Net Lease Payments | (0.03) | (0.10) | (0.03) | (0.04) | - |
| Current Income Tax Expense | (1.19) | (0.99) | (2.40) | (1.64) | (1.16) |
| Cash Netback | $8.34 | $10.28 | $15.90 | $11.30 | $12.12 |
| Share Information (000s) | | | | | |
| Common Stock Outstanding, End of Period | 35,382 | 35,296 | 35,380 | 35,382 | 35,296 |
| Weighted Average Number of Shares of Common Stock Outstanding - Basic and Diluted | 35,380 | 35,291 | 35,369 | 35,350 | 35,466 |
| Colombia Information | Three Months Ended September 30, | Three Months Ended June 30, | Nine Months Ended September 30, |
| 2026 | 2025 | 2026 | 2026 | 2025 |
| Operating Netback | | | | | |
| Gross Profit | $19,711 | $10,446 | $44,585 | $88,673 | $57,275 |
| Depletion and Accretion | $38,356 | $44,041 | $38,072 | $117,061 | $136,936 |
| Operating Netback | $58,067 | $54,487 | $82,657 | $205,734 | $194,211 |
| Oil Sales | $103,358 | $101,999 | $118,136 | $323,818 | $329,339 |
| Operating Expenses | (42,370) | (44,610) | (33,152) | (110,564) | (125,280) |
| Transportation Expenses | (2,921) | (2,902) | (2,327) | (7,520) | (9,848) |
| Operating Netback | $58,067 | $54,487 | $82,657 | $205,734 | $194,211 |
| Capital Expenditures (Before Changes in Working Capital) | $24,784 | $50,323 | $44,274 | $103,733 | $110,741 |
| Average Daily Production (boe/d) | | | | | |
| WI Production Before Royalties | 19,305 | 22,701 | 19,994 | 20,199 | 24,476 |
| Royalties | (3,576) | (3,481) | (3,968) | (3,592) | (3,912) |
| Production NAR | 15,729 | 19,220 | 16,026 | 16,607 | 20,564 |
| Decrease (Increase) in Inventory | 100 | 337 | (57) | 278 | 26 |
| Sales | 15,829 | 19,557 | 15,969 | 16,885 | 20,590 |
| Royalties, % of WI Production Before Royalties | 19% | 15% | 20% | 18% | 16% |
| Operating Netback ($/boe) | | | | | |
| Gross Profit | $11.04 | $4.93 | $24.57 | $15.86 | $8.56 |
| Depletion and Accretion | $21.48 | $20.78 | $20.98 | $20.94 | $20.47 |
| Operating Netback | $32.52 | $25.71 | $45.56 | $36.80 | $29.03 |
| Castilla Differential | $13.73 | $4.88 | $9.71 | $11.07 | $4.98 |
| Vasconia Differential | $6.68 | $1.88 | $1.42 | $4.69 | $1.95 |
| Brent | $91.29 | $68.17 | $96.68 | $88.86 | $69.91 |
| Quality and Transportation Discount | (20.32) | (11.48) | (15.39) | (18.61) | (11.32) |
| Royalties | (13.08) | (8.57) | (16.18) | (12.32) | (9.35) |
| Average Realized Price | 57.89 | 48.12 | 65.11 | 57.93 | 49.24 |
| Transportation Expenses | (1.64) | (1.37) | (1.28) | (1.35) | (1.48) |
| Average Realized Price Net of Transportation Expenses | 56.25 | 46.75 | 63.83 | 56.58 | 47.76 |
| Operating Expenses | (23.73) | (21.04) | (18.27) | (19.78) | (18.73) |
| Operating Netback | $32.52 | $25.71 | $45.56 | $36.80 | $29.03 |
| Ecuador Information | Three Months Ended September 30, | Three Months Ended June 30, | Nine Months Ended September 30, |
| 2026 | 2025 | 2026 | 2026 | 2025 |
| Operating Netback | | | | | |
| Gross Profit | $13,710 | $859 | $24,811 | $44,899 | $1,801 |
| Depletion and Accretion | $14,104 | $9,519 | $9,775 | $39,740 | $24,366 |
| Operating Netback | $27,814 | $10,378 | $34,586 | $84,639 | $26,167 |
| Oil Sales | $42,134 | $20,605 | $41,964 | $124,843 | $50,123 |
| Operating Expenses | (11,985) | (9,157) | (6,196) | (34,133) | (21,352) |
| Transportation Expenses | (2,335) | (1,070) | (1,182) | (6,071) | (2,604) |
| Operating Netback | $27,814 | $10,378 | $34,586 | $84,639 | $26,167 |
| Capital Expenditures (Before Changes in Working Capital) | $4,754 | $10,546 | $5,888 | $15,892 | $56,133 |
| Average Daily Production (boe/d) | | | | | |
| WI Production Before Royalties | 7,747 | 3,872 | 7,993 | 8,162 | 4,166 |
| Royalties | (3,206) | (1,273) | (3,788) | (3,195) | (1,353) |
| Production NAR | 4,541 | 2,599 | 4,205 | 4,967 | 2,813 |
| Decrease in Inventory | 1,234 | 1,054 | 233 | 1,063 | 106 |
| Sales | 5,775 | 3,653 | 4,438 | 6,030 | 2,919 |
| Royalties, % of WI Production Before Royalties | 41% | 33% | 47% | 39% | 32% |
| Operating Netback ($/boe) | | | | | |
| Gross Profit | $16.59 | $1.90 | $33.15 | $17.83 | $1.54 |
| Depletion and Accretion | $17.07 | $21.00 | $13.06 | $15.78 | $20.90 |
| Operating Netback | $33.66 | $22.90 | $46.20 | $33.61 | $22.44 |
| Oriente Differential | $10.32 | $7.20 | $2.01 | $6.86 | $7.37 |
| Brent (M-1 Pricing) | $85.43 | $68.89 | $101.89 | $84.26 | $70.53 |
| Quality and Transportation (Discount) Premium | (6.13) | (7.60) | 2.01 | (8.43) | (7.61) |
| Royalties | (28.31) | (15.83) | (47.84) | (26.26) | (19.93) |
| Average Realized Price | 50.99 | 45.46 | 56.06 | 49.57 | 42.99 |
| Transportation Expenses | (2.83) | (2.36) | (1.58) | (2.41) | (2.24) |
| Average Realized Price Net of Transportation Expenses | 48.16 | 43.10 | 54.48 | 47.16 | 40.75 |
| Operating Expenses | (14.50) | (20.20) | (8.28) | (13.55) | (18.31) |
| Operating Netback | $33.66 | $22.90 | $46.20 | $33.61 | $22.44 |
| Canadian Information | Three Months Ended September 30, | Three Months Ended June 30, | Nine Months Ended September 30, |
| 2026 | 2025 | 2026 | 2026 | 2025 |
| Operating Netback | | | | | |
| Gross Profit | $7,451 | $3,574 | $6,064 | $19,457 | $7,217 |
| Depletion and Accretion | $5,246 | $8,348 | $8,406 | $21,066 | $34,984 |
| Operating Netback | $12,697 | $11,922 | $14,470 | $40,523 | $42,201 |
| Oil Sales | $19,066 | $21,884 | $24,196 | $64,248 | $64,984 |
| Natural Gas Sales | 3,403 | 3,702 | 3,673 | 13,151 | 16,463 |
| NGL Sales | 4,304 | 4,314 | 5,079 | 14,422 | 16,249 |
| Royalties | (3,959) | (3,250) | (5,866) | (12,938) | (10,374) |
| Oil, Natural Gas and NGL Sales After Royalties | $22,814 | $26,650 | $27,081 | $78,883 | $87,322 |
| Operating Expenses | (9,831) | (14,403) | (12,213) | (37,199) | (44,231) |
| Transportation Expenses | (286) | (325) | (398) | (1,161) | (890) |
| Operating Netback | $12,697 | $11,922 | $14,470 | $40,523 | $42,201 |
| Capital Expenditures (Before Changes in Working Capital) | $692 | $3,250 | $4,147 | $10,273 | $50,786 |
| Average Daily Production | | | | | |
| Crude Oil (bbl/d) | 2,581 | 4,013 | 2,928 | 3,057 | 3,992 |
| Natural Gas (Mcf/d) | 37,134 | 49,260 | 39,366 | 39,942 | 49,746 |
| NGLs (bbl/d) | 4,081 | 3,889 | 4,026 | 4,205 | 4,571 |
| WI Production Before Royalties (boe/d) | 12,852 | 16,112 | 13,514 | 13,919 | 16,853 |
| Royalties (boe/d) | (1,732) | (1,969) | (1,755) | (1,809) | (2,131) |
| Production NAR (boe/d) | 11,120 | 14,143 | 11,759 | 12,110 | 14,722 |
| Sales (boe/d) | 11,120 | 14,143 | 11,759 | 12,110 | 14,722 |
| Royalties, % of WI Production Before Royalties | 13% | 12% | 13% | 13% | 13% |
| Benchmark Prices | | | | | |
| West Texas Intermediate ($/bbl) | 85.68 | 65.07 | 92.70 | 83.76 | 66.74 |
| AECO Natural Gas Price (C$/GJ) | 1.48 | 0.60 | 1.55 | 1.65 | 1.42 |
| Average Realized Price | | | | | |
| Crude Oil ($/bbl) | 80.28 | 59.28 | 90.81 | 76.98 | 59.63 |
| Natural Gas ($/Mcf) | 1.00 | 0.82 | 1.03 | 1.21 | 1.21 |
| NGLs ($/bbl) | 11.46 | 12.06 | 13.86 | 12.56 | 13.02 |
| Operating Netback ($/boe) | | | | | |
| Gross Profit | $6.30 | $2.41 | $4.93 | $5.12 | $1.57 |
| Depletion and Accretion | $4.44 | $5.63 | $6.84 | $5.54 | $7.61 |
| Operating Netback | $10.74 | $8.04 | $11.77 | $10.66 | $9.18 |
| Average Realized Price before Royalties | $22.64 | $20.17 | $26.79 | $24.16 | $21.23 |
| Royalties | (3.35) | (2.19) | (4.77) | (3.40) | (2.25) |
| Transportation Expenses | (0.24) | (0.22) | (0.32) | (0.31) | (0.19) |
| Operating Expenses | (8.31) | (9.72) | (9.93) | (9.79) | (9.61) |
| Operating Netback | $10.74 | $8.04 | $11.77 | $10.66 | $9.18 |
Per share amounts are based on weighted average shares outstanding (basic and diluted) of 35,380,459, 35,368,716, and 35,291,099 for the three months ended September 30, 2026, June 30, 2026, and September 30, 2025, respectively, and 35,349,968 and 35,465,938 for the nine months ended September 30, 2026 and 2025, respectively.
Gross profit is calculated as oil, gas and NGL sales, less operating and transportation expenses, and depletion and accretion related to producing assets.
Operating netback, earnings before interest, taxes and depletion, depreciation and accretion (“DD&A”) (“EBITDA”), Adjusted EBITDA, funds flow from operations, net debt, free cash flow, and cash netback, are non-GAAP measures and do not have a standardized meaning under U.S. generally accepted accounting principles (“GAAP”). Cash flow refers to the GAAP line item “net cash provided by operating activities”. Refer to “Non-GAAP Measures” in this press release for descriptions of these non-GAAP measures and reconciliations to the most directly comparable measures calculated and presented in accordance with GAAP. Operating netback per boe, cash netback per boe and funds flow from operations per share are non-GAAP ratios, each calculated using a non-GAAP financial measure as a component.
Net debt is based on $591 million outstanding of Senior Notes less $141 million of cash and cash equivalents as at September 30, 2026.
Depletion and Accretion is calculated as DD&A expenses less depreciation of administrative assets.
Per boe amounts are based on WI sales before royalties. For per boe amounts based on NAR production, see Gran Tierra’s Quarterly Report on Form 10-Q filed on November 5, 2026.
Ecuador oil sales are priced on an “M-1” basis, a pricing convention whereby the realized price for volumes lifted in a given month is determined by reference to the average Brent crude oil price of the immediately preceding calendar month, rather than the month in which lifting occurs.
Conference Call Information:
Gran Tierra will host its third quarter 2026 results conference call on Friday, November 6, 2026, at 9:00 a.m. Alberta Time, 10:00 a.m. Eastern Standard Time, and 3:00 p.m. Greenwich Mean Time. Interested parties may access the conference call by registering at the following link: https://register-conf.media-server.com/register/BI4b98dba552ba498d9f67edc852f15f71. Please note that there is no longer a general dial-in number to participate and each individual party must register through the provided link. Once parties have registered, they will be provided a unique PIN and call-in details. There is also a feature that allows parties to elect to be called back through the “Call Me” function on the platform. Interested parties can also continue to access the live webcast from their mobile or desktop devices at the following link: https://edge.media-server.com/mmc/p/hkogo43v, which is also available on Gran Tierra’s website at https://www.grantierra.com/investor-relations/presentations-events/.
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 the operator of, and holds a 65% working interest in, an onshore exploration, development and production sharing agreement in Azerbaijan. Upon completion of the Sale, the Company’s operations will be focused on Canada and Azerbaijan, and the Company 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 filings with the U.S. Securities and Exchange Commission (the “SEC”) are available on the SEC website at http://www.sec.gov. Gran Tierra’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 http://data.fca.org.uk/#/nsm/nationalstoragemechanism.
Contact Information
For investor and media inquiries please contact:
Gary Guidry, President and Chief Executive Officer
Ryan Ellson, Executive Vice President and Chief Financial Officer
Tel: (403) 265-3221
For more information on Gran Tierra please go to: www.grantierra.com.
Forward-Looking Statements and Advisories:
Forward-looking statements notice
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”), which can be identified by such terms as “expect”, “plan”, “anticipate”, “target”, “outlook”, “can,” “will,” “should,” “guidance,” “forecast,” “signal,” “measures taken to” and “believes”, derivations thereof and similar terms. Such forward-looking statements include, but are not limited to, statements regarding the Sale, including the satisfaction of the remaining conditions to closing, the timing of completion, the expected net cash proceeds and the timing of their receipt, the intended use of those proceeds, including any return of capital to stockholders, and the Company’s financial position, strategy and plans following completion of the Sale; the interpretation and use of the dFTG survey data and the timing and scope of the exploration program in Azerbaijan; the Company’s capital budget amount and uses; the Company’s strategies related to exploration, drilling and operation activities; expectations regarding reservoir prospects and production amounts; future well results (including initial oil and natural gas production rates and productive capacity based on past performance); expected future net cash provided by operating activities (described in this press release as “cash flow”), free cash flow, operating netback, EBITDA and certain associated metrics; anticipated capital expenditures, including the location and impact of capital expenditures; operating and general and administrative costs; and the Company’s expectations as to debt repayment, hedging and its positioning for 2026 and beyond. 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, the accuracy of testing and production results and seismic data, pricing and cost estimates (including with respect to commodity pricing and exchange rates), that the remaining approvals and consents for the Sale will be obtained and the other conditions to closing satisfied on the anticipated timeline, that the Share Purchase Agreement will not be terminated, and the general continuance of current or, where applicable, assumed operational, regulatory and industry conditions in Canada, Colombia, Ecuador and Azerbaijan and areas of potential expansion, and the ability of Gran Tierra to execute its business and operational plans (including any debt repayment plan) in the manner currently planned. Gran Tierra believes the material factors, expectations and assumptions reflected in the forward-looking statements are reasonable at this time, but no assurance can be given that these factors, expectations and assumptions will prove to be correct.
Forward-looking statements notice
Among the important factors that could cause actual results to differ materially from those indicated by the forward-looking statements in this press release are: the possibility that the remaining approvals or consents for the Sale are not obtained or other conditions to completion are not satisfied; delays in completing, or the failure to complete, the Sale; the risk that the Share Purchase Agreement is terminated in circumstances requiring Gran Tierra to repay the $50 million deposit with interest; adjustments to the consideration and the risk that the net cash proceeds are lower than, or received later than, expected, including the $65 million payable 364 days after closing; the effect of the pendency of the Sale on Gran Tierra’s business; certain of Gran Tierra’s operations are located in South America and the Company is pursuing activities in other international jurisdictions, including Azerbaijan, and unexpected problems can arise due to guerrilla activity, strikes, local blockades or protests; technical difficulties and operational difficulties may arise which impact the production, transport or sale of Gran Tierra’s products; other disruptions to local operations; 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 ongoing conflicts in Ukraine, the Middle East and Venezuela, 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 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 and natural gas prices and oil and natural gas consumption more than Gran Tierra currently predicts, which could cause Gran Tierra to further modify its 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 Gran Tierra’s products; the ability of Gran Tierra to execute its 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 Gran Tierra’s 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 Gran Tierra’s common stock or bonds; the risk that Gran Tierra does not receive the anticipated benefits of government programs, including government tax refunds; Gran Tierra’s ability to comply with financial covenants in its credit agreement and indentures and make borrowings under its credit agreement; and the risk factors detailed from time to time in Gran Tierra’s periodic reports filed with the SEC, including, without limitation, under the caption “Risk Factors” in Gran Tierra’s Annual Report on Form 10-K for the year ended December 31, 2025 filed on March 4, 2026 and Quarterly Report on Form 10-Q for the quarter ended September 30, 2026 filed on November 5, 2026, its definitive proxy statement relating to the Sale filed on September 15, 2026, and its other filings with the SEC. These filings are available on the SEC’s website at http://www.sec.gov and on SEDAR+ at 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 notice
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 risks 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 financial outlook contained in this press release is 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. Gran Tierra’s forward-looking statements are expressly qualified in their entirety by this cautionary statement.
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, net cash provided by 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.
Net debt, as presented as at September 30, 2026, is comprised of $545 million (gross) of long-term senior notes outstanding and $46 million (gross) of current senior notes outstanding less cash and cash equivalents of $141 million. Total debt of $589 million (the most directly comparable GAAP measure), plus unamortized senior notes discount of $20 million and unamortized debt issuance costs of $9 million, less long-term lease obligations of $26 million, equals senior notes principal outstanding of $591 million. Management believes that net debt is a useful supplemental measure for management and investors in order to evaluate the financial sustainability of the Company’s business and leverage. The most directly comparable GAAP measure is total debt.
Operating netback, as presented, is defined as gross profit adjusted for depletion and accretion related to producing assets. Operating netback per boe, as presented, is defined as operating netback over WI sales volume. See the table entitled Financial and Operational Highlights above for the components of consolidated operating netback and corresponding reconciliation.
Cash netback, as presented, is most directly comparable to gross profit and is calculated as gross profit adjusted for depletion and accretion related to producing assets, cash G&A expenses, transaction costs, other taxes, severance expenses, realized foreign exchange gains or losses, cash settlement on derivative instruments, interest expense (excluding amortization of debt issuance costs, non-cash interest, and senior notes exchange fees), interest income, other cash gains or losses, net lease payments, and current income tax expense or recovery. Cash netback per boe, as presented, is defined as cash netback over WI sales volumes. 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. See the table entitled Financial and Operational Highlights above for the components of operating netback and operating netback per boe. A reconciliation from gross profit to cash netback is as follows:
| Three Months Ended September 30, | Three Months Ended June 30, | Nine Months Ended September 30, |
|---|
| Operating and Cash Netback - Non-GAAP Measure ($000s) | | 2026 | | 2025 | | 2026 | | 2026 | | 2025 |
| Gross Profit | $40,872 | | $14,879 | | $75,460 | | $153,029 | | $66,293 | |
| Adjustments to reconcile gross profit to operating netback | | | | | |
| Depletion and accretion | 57,706 | 61,908 | 56,253 | 177,867 | 196,286 |
| Operating Netback (non-GAAP) | 98,578 | 76,787 | 131,713 | 330,896 | 262,579 |
| Cash G&A expenses | (11,814) | (13,246) | (13,219) | (40,182) | (39,306) |
| Transaction costs | (4,887) | - | - | (4,887) | - |
| Other taxes | (1,031) | (3,046) | (1,389) | (3,461) | (4,105) |
| Severance expenses | - | - | (95) | (2,563) | - |
| Realized foreign exchange (loss) gain | (10,679) | (2,149) | 260 | (12,044) | (4,902) |
| Cash settlement on derivative instruments | (18,205) | 7,461 | (34,032) | (63,319) | 9,535 |
| Interest expense, excluding amortization of debt issuance costs, non-cash interest, and senior notes exchange fees | (16,379) | (21,178) | (15,832) | (53,380) | (60,864) |
| Interest income | 538 | 197 | 503 | 1,442 | 873 |
| Other cash gain | 143 | 1,268 | 1,625 | 2,188 | 1,645 |
| Net lease payments | (113) | (387) | (130) | (462) | (38) |
| Current income tax expense | (4,511) | (4,022) | (9,115) | (19,476) | (14,482) |
| Cash Netback (non-GAAP) | $31,640 | $41,685 | $60,289 | $134,752 | $150,935 |
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 asset impairment, severance expenses, transaction costs, non-cash lease expense, lease payments, foreign exchange gains or losses, stock-based compensation expense or recovery, unrealized derivative instruments gains or losses, and other non-cash gains or losses. 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 Ended September 30, | Three Months Ended June 30, | Nine Months Ended September 30, | Twelve Month Trailing September 30, |
|---|
| EBITDA - Non-GAAP Measure ($000s) | | 2026 | | 2025 | | 2026 | | 2026 | | 2025 | | 2026 |
| Net (Loss) Income | $(42,415) | | $(19,950) | | $24,861 | | $(136,726) | | $(51,971) | | $(277,874) | |
| Adjustments to reconcile net (loss) income to EBITDA and Adjusted EBITDA | | | | | | |
| DD&A expenses | 64,391 | | 64,981 | | 62,334 | | 196,599 | | 205,818 | | 269,134 | |
| Interest expense | 23,878 | | 25,447 | | 24,473 | | 98,229 | | 73,048 | | 126,490 | |
| Income tax (recovery) expense | (25,575) | | (11,276) | | 20,488 | | (31,682) | | (3,075) | | (68,360) | |
| EBITDA (non-GAAP) | $20,279 | | $59,202 | | $132,156 | | $126,420 | | $223,820 | | $49,390 | |
| Asset Impairment | - | | - | | - | | - | | - | | 136,261 | |
| Severance expenses | - | | - | | 95 | | 2,563 | | - | | 2,563 | |
| Transaction costs | 4,887 | | - | | - | | 4,887 | | - | | 4,887 | |
| Non-cash lease expense | 1,452 | | 1,187 | | 1,503 | | 4,423 | | 4,648 | | 5,596 | |
| Lease payments | (1,565) | | (1,574) | | (1,633) | | (4,885) | | (4,686) | | (6,172) | |
| Foreign exchange loss | 2,252 | | 284 | | 2,603 | | 6,280 | | 7,838 | | 7,176 | |
| Stock-based compensation expense (recovery) | 30,465 | | 143 | | (3,757) | | 46,384 | | 172 | | 49,426 | |
| Unrealized derivative instruments loss (gain) | 11,023 | | 9,527 | | (45,896) | | 42,455 | | (964) | | 34,786 | |
| Other non-cash (gain) loss | (697) | 265 | - | (1,425) | 355 | (4,338) |
| Adjusted EBITDA (non-GAAP) | $68,096 | $69,034 | $85,071 | $227,102 | $231,183 | $279,575 |
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 or recovery, amortization of debt issuance costs, Senior Notes exchange fees, non-cash interest, non-cash lease expense, lease payments, unrealized foreign exchange gains or losses, other non-cash gains or losses and unrealized derivative instruments gains or losses. 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 funds flow from operations and free cash flow is as follows:
| Three Months Ended September 30, | Three Months Ended June 30, | Nine Months Ended September 30, |
|---|
| Funds flow from operations - Non-GAAP Measure ($000s) | | 2026 | | 2025 | | 2026 | | 2026 | | 2025 |
| Net (Loss) Income | $(42,415) | | $(19,950) | | $24,861 | | $(136,726) | | $(51,971) | |
| Adjustments to reconcile net (loss) income to funds flow from operations | | | | | |
| DD&A expenses | 64,391 | | 64,981 | | 62,334 | | 196,599 | | 205,818 | |
| Deferred tax (recovery) expense | (30,086) | | (15,298) | | 11,373 | | (51,158) | | (17,557) | |
| Stock-based compensation expense (recovery) | 30,465 | | 143 | | (3,757) | | 46,384 | | 172 | |
| Amortization of debt issuance costs | 1,734 | | 4,269 | | 1,722 | | 14,749 | | 12,184 | |
| Senior Notes exchange fees | (179) | | - | | 785 | | 13,509 | | - | |
| Non-cash interest | 5,944 | | - | | 6,134 | | 16,591 | | - | |
| Non-cash lease expense | 1,452 | | 1,187 | | 1,503 | | 4,423 | | 4,648 | |
| Lease payments | (1,565) | | (1,574) | | (1,633) | | (4,885) | | (4,686) | |
| Unrealized foreign exchange (gain) loss | (8,427) | | (1,865) | | 2,863 | | (5,764) | | 2,936 | |
| Other non-cash (gain) loss | (697) | | 265 | | - | | (1,425) | | 355 | |
| Unrealized derivative instruments loss (gain) | 11,023 | | 9,527 | | (45,896) | | 42,455 | | (964) | |
| Funds flow from operations (non-GAAP) | $31,640 | | $41,685 | | $60,289 | | $134,752 | | $150,935 | |
| Capital expenditures | $30,660 | | $57,340 | | $54,309 | | $130,328 | | $203,237 | |
| Free cash flow (non-GAAP) | $980 | | $(15,655) | | $5,980 | | $4,424 | | $(52,302) | |
Presentation of Oil and Gas Information
Boes have been converted on the basis of six thousand cubic feet (“Mcf”) natural gas to 1 boe of oil. Boes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf: 1 boe 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 boe would be misleading as an indication of value.
References to a formation where evidence of hydrocarbons has been encountered are 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 crude oil, conventional natural gas, shale gas and natural gas liquids for which there is no precise breakdown since the Company’s sales volumes typically represent blends of more than one product type. 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.
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.