TOURMALINE ANNOUNCES STRONG SECOND QUARTER RESULTS AND LIQUIDS MARKETING AGREEMENT
CALGARY, Alberta, July 29, 2026 /CNW/ -- Tourmaline Oil Corp. (TSX:TOU) ("Tourmaline" or the "Company") is pleased to release financial and operating results for the second quarter of 2026.
HIGHLIGHTS
- Q2 2026 cash flow(1)(2) ("CF") of $786.1 million ($2.02 per fully diluted share), generating $192.1 million of free cash flow(3) ("FCF") in the quarter.
- The Company entered into a long-term agreement to increase propane and butane exports through the AltaGas REEF terminal, increasing Tourmaline's exposure to premium LPG export markets by approximately 55% and resulting in higher realized margins for these products. Volumes under this agreement will be delivered from Tourmaline's planned new rail loading facility to be located adjacent to the Groundbirch-Monias deep cut plant under construction.
- Strong new well outperformance has continued with 1H 2026 performance now up 28% for the NEBC Montney complex and 14% for the Alberta Deep Basin over the prior five-year averages, based on IP90 rates.
- The NEBC infrastructure buildout is on schedule and on budget with five of six regional connector pipelines completed and the Aitken plant expansion start-up expected in Q4 2026.
- The Company is scheduling a one year pause between Phase 1 and Phase 2 of the NEBC infrastructure buildout, enhancing anticipated 2H 2027 and 2028 free cash flow and shareholder returns.
- Net debt(4) as of June 30, 2026, was $1.5 billion, below the Company's long-term debt target of $1.75 billion, approximately 0.4x net debt to 2026 forecasted cash flow.
PRODUCTION UPDATE
- Q2 2026 average production was 594,198 boepd, marginally below the 595,000 to 605,000 boepd guidance range, as the Company injected additional natural gas into storage and deferred activity in response to low Q2 natural gas prices, positioning volumes for stronger anticipated second-half 2026 pricing.
- Storage injections at Dimsdale Alberta, Dawn Ontario, and Wild Goose California averaged 8,867 boepd in the quarter, higher than initially planned given low natural gas prices during the quarter. These volumes are expected to be largely withdrawn from storage during the fourth quarter of 2026 and first quarter of 2027.
- A full year 2026 production range of 620,000 to 640,000 boepd is still anticipated, including a 2026 production exit target of 660,000 boepd, including natural gas storage withdrawals. The Company plans to shape the production growth curve with anticipated improving natural gas prices in 2H 2026.
- Given activity deferrals from Q2, the Company has 67 wells ready to frac and an additional 21 wells ready to turn in line. The Company will time these production increases to improving WCSB gas prices.
FINANCIAL RESULTS AND CAPITAL BUDGET
- Q2 2026 CF was $786.1 million ($2.02 per fully diluted share), generating $192.1 million of FCF in the quarter.
- Net debt as of June 30, 2026, was $1.5 billion, below the Company's long-term debt target of $1.75 billion, approximately 0.4x net debt to 2026 forecasted cash flow.
- Second quarter operating costs were $4.59/boe, down 10% from Q2 2025 and down 3% from Q1 2026. Costs are anticipated to continue to be reduced as NEBC infrastructure comes onstream and higher production through the winter quarters blends down fixed costs, which weighed on Q2 operating costs per boe given the limited activity and storage injections. Full year 2026 operating costs of $4.50 to $4.60/boe are expected, down 7% to 9% from full year 2025. Tourmaline maintains its aggregate operating and transportation cost reduction target of $1.50/boe by 2031 relative to 1H 2025 levels.
- The full year 2026 EP capital budget remains at $2.55 billion following the $350 million reduction announced on March 4, 2026. The Company will continue to monitor spending to optimize FCF.
- At current strip pricing, 2026 FCF is estimated to be $880 million. The FCF benefit from the Company's exposure to JKM and TTF pricing via LNG export-related contracts is expected to continue through the balance of 2026 and 2027. Given the volatility of commodity prices resulting from current geopolitical events, Tourmaline will announce potential allocations of this anticipated excess FCF, including potential increased shareholder returns, in the coming quarters following realization of the excess FCF.
- Tourmaline is now scheduling a one-year growth spending pause between the two phases of the NEBC Montney infrastructure buildout and development project. This pause will allow the Company and shareholders to realize the full operational benefits and FCF growth from Phase 1 in 2H 2027/2028 prior to embarking on Phase 2. The pause also allows the Company to assess global natural gas supply, demand, and price outlooks.
- 2027 EP spending is revised to $2.55 billion and 2028 EP spending is revised to $2.3 billion, from $2.7 billion and $2.69 billion respectively, yielding estimated FCF of over $1 billion(5) in both 2027 and 2028.
ACQUISITION AND DIVESTMENT ACTIVITY
- Tourmaline continues to pursue small tuck-in acquisitions and working interest consolidation opportunities adjacent to existing Company lands and operated infrastructure.
- During the second quarter, the Company acquired Aduro Resources Ltd. ("Aduro") in the South Montney complex for total consideration of approximately $100 million (including net debt), consisting of $50 million of cash and approximately 1.5 million common shares of Topaz Energy Corp. ("Topaz"). The acquisition included modest current production and infrastructure as well as 174 net Tier 1 Montney locations (including the consolidation of 20 net joint locations) adjacent to the Tourmaline Groundbirch-Monias deep cut plant currently under construction. This drilling inventory was acquired for an average cost of approximately $462,000 per location, net of PDP reserves, income tax pools and infrastructure.
- Also during the second quarter, Tourmaline completed the sale of a gross overriding royalty on the Aduro lands, as well as on certain recently acquired Alberta Deep Basin lands, to Topaz for cash proceeds of $38.7 million.
MARKETING UPDATE
- Tourmaline's average realized natural gas price in Q2 2026 was CAD $3.12/mcf, significantly (CAD $1.46/mcf) above the AECO 5A benchmark price of CAD $1.66/mcf over the same period, as the Company continues to benefit from its diversified marketing portfolio and strategic hedging program.
- Tourmaline has an average of 1,014 mmcfpd of natural gas hedged for the remainder of 2026 at a weighted average fixed price of CAD $4.97/mcf. This includes 100 mmcfpd hedged at a weighted average price of CAD $16.25/mcf in international markets and 164 mmcfpd at a weighted average price of CAD $6.32/mcf in Western U.S. markets.
- Tourmaline has an average of 220,000 mmbtu/d exposed to international pricing (TTF/JKM) in 2026. This will grow to 253,000 mmbtu/d by exit 2027 and 333,000 mmbtu/d by exit 2028. For the balance of 2026, JKM and TTF are trading over USD $15/mmbtu(5), which represents a >60% price appreciation for the same strip as at the beginning of January 2026. The majority of Tourmaline's costs under LNG supply agreements are fixed, enabling the Company to capture this pricing upside.
- Tourmaline is amongst Canada's largest propane producers and, similar to its natural gas business, the Company has a long-standing propane marketing diversification strategy in place. Tourmaline is pleased to announce that it has entered into a long-term agreement with AltaGas to increase propane and butane exports through the Ridley Island Energy Export Facility (REEF). Combined with the Company's existing export capacity at the Ridley Island Propane Export Terminal (RIPET), the agreement is expected to increase Tourmaline's exposure to premium LPG export markets by approximately 55% once the Company's Groundbirch-Monias deep cut plant is in service. LPG volumes will be supplied to REEF from Tourmaline's planned unit train rail loading facility, which will be located adjacent to the Groundbirch-Monias deep cut plant currently under construction. The new rail terminal is expected to improve realized LPG margins by enabling direct rail shipments to the west coast, reducing third-party transportation to, and fractionation, storage, and loading fees in, Fort Saskatchewan.
- Tourmaline has natural gas storage capacity at Dawn Ontario, Wild Goose California, and most recently at Dimsdale Alberta. These facilities were utilized heavily during the periods of low gas prices in Q2 2026. The Company currently expects to withdraw these volumes over the 2026 / 2027 winter heating season, providing both a production and cash flow increase.
EP UPDATE
- Tourmaline drilled a total of 43 wells and completed 33 wells during the second quarter of 2026, as considerable EP activity was deferred from Q2 into 2H of 2026.
- Strong new well performance has continued in both gas complexes in the first half of 2026. NEBC Montney well performance is now up 28% in the first half of 2026, over the prior five-year average based on the 25 wells that have reached IP90.
- The Alberta Deep Basin is up 14% in the first half of 2026 over the prior five-year average based on the first 30 wells that have reached IP90.
INVENTORY BUILDING
- Tourmaline controls the largest future drilling inventory in the North American natural gas business, and the Company has continued to cost effectively add high quality inventory in 2026.
- Through the Aduro acquisition, Tourmaline has added 174 net locations of primarily Tier 1 inventory in NEBC at an average cost of $462,000 per location.
- Land sales (including the first disposition of previously restricted Alberta Caribou lands) and minor asset consolidations added 110 locations in the Alberta Deep Basin at an average cost of $173,000 per location.
NEBC INFRASTRUCTURE BUILDOUT
- Tourmaline's ongoing NEBC Montney infrastructure buildout is a major Canadian project and is fully funded by CF.
- The two-phase project, once completed, is expected to add 1.1 bcf/d and over 50,000 bpd of condensate and NGLs.
- As well as adding growth volumes, the NEBC Montney infrastructure buildout will reduce operating and transportation costs and will improve liquid margins. The buildout, once completed, is anticipated to generate over $400 million of structural incremental annual cash flow, compared to 1H 2025 cost structure, above the cash flow generated by growing natural gas and product sales.
- A substantial amount of the Phase 1 buildout is already complete, including the Highway condensate hub, five of the six major pipeline interconnects, the Birch facility, and the South Montney electrification project, yielding significant operating and transportation cost reductions in 2026.
- The first two major facilities in the buildout, Aitken and Groundbirch-Monias, remain on schedule for Q4 2026 and Q4 2027 start-ups, respectively.
- The Company will continue with Phase 2 planning and design efforts to be in a position to execute on the original schedule should natural gas prices materially improve on a sustained basis.
MANAGEMENT UPDATE
- Mr. Brian Robinson, the Company's Chief Financial Officer, has advised the Board of Directors of his intention to retire as CFO, effective November 1, 2026. Mr. Robinson has served as CFO since the Company's founding in 2008 and has played a central role in building Tourmaline into Canada's largest natural gas producer. Throughout his tenure, he has been instrumental in shaping the Company's strategic direction, financing its exponential growth, and maintaining the balance sheet discipline that has allowed Tourmaline to invest consistently through multiple commodity price cycles.
- Prior to Tourmaline's inception, Mr. Robinson served as CFO of companies founded and led by Mike Rose and members of Tourmaline's senior management team for over twenty-five years, including Duvernay Oil Corp. until its sale to Shell Canada in 2008 and as CFO of Berkley Petroleum from 2000 until its sale to Anadarko in 2001.
- Mr. Robinson will remain on the Board of Directors of Tourmaline following his retirement as CFO.
- The Board has appointed Mr. Jamie Heard, currently the Company's Vice President, Capital Markets, to succeed Mr. Robinson as Chief Financial Officer, effective November 1, 2026. Mr. Heard joined Tourmaline in 2019 and has held progressively senior roles in capital markets and finance with the Company. Prior to joining Tourmaline, Mr. Heard worked in investment and finance roles with multiple buy side funds and banks.
DIVIDEND
- Tourmaline's Board of Directors intends to declare a quarterly base dividend of $0.50 per share in early September, which will be payable on September 29, 2026, to shareholders of record at the close of business on September 15, 2026. The quarterly base dividend will be designated as an eligible dividend for Canadian income tax purposes.
_____________________________________________________ |
|
(1) |
This news release contains certain specified financial measures consisting of non-GAAP financial measures, non-GAAP financial ratios, capital management measures and supplementary financial measures. See "Non-GAAP and Other Financial Measures" in this news release for information regarding the following specified financial measures: "cash flow", "capital expenditures", "EP expenditures", "free cash flow", "operating netback", "operating netback per boe", "cash flow per diluted share", "free cash flow per diluted share", "adjusted working capital" and "net debt". Since these specified financial measures do not have standardized meanings under International Financial Reporting Standards ("GAAP"), securities regulations require that, among other things, they be identified, defined, qualified and, where required, reconciled with their nearest GAAP measure and compared to the prior period. See "Non-GAAP and Other Financial Measures" in this news release and in the Company's most recently filed Management's Discussion and Analysis (the "Q2 2026 MD&A"), which information is incorporated by reference into this news release, for further information on the composition of and, where required, reconciliation of these measures. |
(2) |
"Cash flow" is a non-GAAP financial measure defined as cash flow from operating activities adjusted for the change in non-cash working capital (deficit) and current taxes. See "Non-GAAP and Other Financial Measures" in this news release and in the Q2 2026 MD&A. |
(3) |
"Free cash flow" is a non-GAAP financial measure defined as cash flow less capital expenditures, excluding acquisitions and dispositions. Free cash flow is prior to dividend payments. See "Non-GAAP and Other Financial Measures" in this news release. |
(4) |
"Net debt" is a capital management measure. See "Non-GAAP and Other Financial Measures" in this news release and in the Q2 2026 MD&A. |
(5) |
As per strip pricing as of July 21, 2026. |
CORPORATE SUMMARY – SECOND QUARTER 2026
Three Months Ended June 30, |
Six Months Ended June 30, |
||||||
2026 |
2025 |
Change |
2026 |
2025 |
Change |
||
OPERATIONS |
|||||||
Production |
|||||||
Natural gas (mcf/d) |
2,886,412 |
2,877,712 |
– % |
3,009,789 |
2,909,964 |
3 % |
|
Crude oil, condensate and NGL (bbl/d) |
113,129 |
141,138 |
(20) % |
128,313 |
144,271 |
(11) % |
|
Oil equivalent (boe/d) |
594,198 |
620,757 |
(4) % |
629,945 |
629,265 |
– % |
|
Product prices(1) |
|||||||
Natural gas ($/mcf) |
$ 3.12 |
$ 3.34 |
(7) % |
$ 3.36 |
$ 3.82 |
(12) % |
|
Crude oil, condensate and NGL ($/bbl) |
$ 65.55 |
$ 49.25 |
33 % |
$ 58.34 |
$ 53.06 |
10 % |
|
Operating expenses ($/boe) |
$ 4.59 |
$ 5.12 |
(10) % |
$ 4.68 |
$ 5.14 |
(9) % |
|
Transportation costs ($/boe) |
$ 5.21 |
$ 5.01 |
4 % |
$ 5.29 |
$ 5.27 |
– % |
|
Operating netback ($/boe)(2) |
$ 15.14 |
$ 14.93 |
1 % |
$ 15.23 |
$ 17.05 |
(11) % |
|
Cash general and |
$ 0.87 |
$ 0.82 |
6 % |
$ 0.86 |
$ 0.82 |
5 % |
|
FINANCIAL |
|||||||
Commodity sales from production |
1,348,528 |
1,134,466 |
19 % |
2,795,577 |
2,592,033 |
8 % |
|
Total revenue from commodity sales and realized gains |
1,493,037 |
1,506,049 |
(1) % |
3,186,927 |
3,397,642 |
(6) % |
|
Royalties |
144,560 |
90,328 |
60 % |
313,396 |
269,487 |
16 % |
|
Cash flow |
786,089 |
822,831 |
(4) % |
1,648,244 |
1,785,877 |
(8) % |
|
Cash flow per share (diluted) |
$ 2.02 |
$ 2.16 |
(6) % |
$ 4.23 |
$ 4.72 |
(10) % |
|
Net earnings |
184,426 |
514,591 |
(64) % |
841,986 |
727,269 |
16 % |
|
Net earnings per share (diluted) |
$ 0.47 |
$ 1.35 |
(65) % |
$ 2.16 |
$ 1.92 |
13 % |
|
Capital expenditures (net of dispositions)(2) |
554,808 |
505,239 |
10 % |
463,524 |
1,330,257 |
(65) % |
|
Weighted average shares outstanding (diluted) |
389,669,745 |
378,683,661 |
3 % |
||||
Net debt |
(1,508,252) |
(1,867,053) |
(19) % |
||||
Notes: |
|
(1) |
Product prices include realized gains and losses on risk management activities and financial instrument contracts. |
(2) |
See "Non-GAAP and Other Financial Measures" in this news release and in the Q2 2026 MD&A. |
(3) |
Excluding interest and financing charges. |
Conference Call Tomorrow at 9:00 a.m. MT (11:00 a.m. ET)
Tourmaline will host a conference call tomorrow, July 30, 2026 starting at 9:00 a.m. MT (11:00 a.m. ET).
To participate without operator assistance, you may register and enter your phone number at https://emportal.ink/4f9XyUo to receive an instant automated call back.
To participate using an operator, please dial 1-888-510-2154 (toll-free in North America), or 1-437-900-0527 (international dial-in), a few minutes prior to the conference call.
REPLAY DETAILS
If you are unable to dial into the live conference call on July 30, a replay will be available by dialing 1-888-660-6345 (international 1-289-819-1450), referencing Replay Code 82060. The recording will expire on August 13, 2026.
Reader Advisories
CURRENCY
All amounts in this news release are stated in Canadian dollars unless otherwise specified.
FORWARD-LOOKING INFORMATION
This news release contains forward-looking information and statements (collectively, "forward-looking information") within the meaning of applicable securities laws. The use of any of the words "forecast", "expect", "anticipate", "continue", "estimate", "objective", "ongoing", "on track", "may", "will", "project", "should", "believe", "plans", "intends" and similar expressions are intended to identify forward-looking information. More particularly and without limitation, this news release contains forward-looking information concerning Tourmaline's plans and other aspects of its anticipated future operations, management focus, objectives, strategies, financial, operating and production results and business opportunities, including the following: anticipated petroleum and natural gas production and production growth for various periods including estimated average production levels for full-year 2026 and exit 2026; the anticipated increase in the Company's exposure to premium LPG export markets and higher realized margins associated with long term agreements entered into with AltaGas; the expectation that volumes delivered to the REEF terminal will originate from the Company's planned new rail loading facility to be located adjacent to the Groundbirch-Monias plant under construction; the anticipated start-up date of various facilities including the Aitken plant expansion and the Groundbirch-Monias plant; the scheduled one year pause in growth capital spending between Phase 1 and Phase 2 of the NEBC Montney infrastructure buildout; the Company's long-term net debt target; the anticipated 2026 full year EP capital program; anticipated commodity price improvement; anticipated 2026, 2027 and 2028 FCF; anticipated international LNG pricing; anticipated injections and withdrawals of natural gas using the Company's storage capacity and the timing and volume thereof; production levels, CF, FCF and other information included in the Company's EP Plan; average production volumes exposed to international pricing in 2026 and by exit 2028 (JKM/TTF); the timing of the FCF benefit that the Company expects to realize from exposure to JKM and TTF pricing; expected total operating and transportation cost reductions that the Company expects to realize by 2031; anticipated 2027 and 2028 EP spending and estimated FCF; the expectation that the Company and shareholders will realize the full operational benefits and FCF growth from Phase 1 of the NEBC Montney infrastructure buildout in 2H 2027/2028; expected natural gas volumes and condensate and NGL growth volumes resulting from the NEBC Montney infrastructure and development project; the expectation that the Company is unlikely to make further reductions to the EP capital budget in 2026; the expectation that costs will continue to be reduced as NEBC infrastructure comes on stream and higher production through the winter quarters blends down fixed costs; anticipated structural incremental annual cash flow resulting from the NEBC Montney infrastructure buildout; the Company's ability to execute the NEBC Montney infrastructure buildout on the original schedule should natural gas prices materially improve; potential future drilling and completion-related capital deferrals; the expectation that the Board of Directors will declare a quarterly base dividend in early September; the timing of announcements relating to potential allocations for anticipated excess FCF, including potential increased shareholder returns and the timing thereof; the timing and scale of future growth and developments projects, including the NEBC infrastructure build out; projected operating and drilling costs and drilling times; anticipated future commodity prices; anticipated increasing worldwide natural gas demand across key markets;; as well as Tourmaline's future drilling locations, prospects and plans, business strategy, future development and growth opportunities, prospects and asset base. The forward-looking information is based on certain key expectations and assumptions made by Tourmaline, including expectations and assumptions concerning the following: prevailing and future commodity prices and currency exchange and interest rates; applicable royalty rates and tax laws; future well production rates and reserve volumes; operating costs, the timing of receipt of regulatory approvals; the performance of existing and future wells; the success obtained in drilling new wells; anticipated timing and results of capital expenditures; the sufficiency of budgeted capital expenditures in carrying out planned activities; the timing, location and extent of future drilling operations; the successful completion of acquisitions and dispositions and the benefits to be derived therefrom; the state of the economy and the exploration and production business; the availability and cost of financing, labour and services; ability to maintain its investment grade credit rating; and ability to market crude oil, natural gas and NGL successfully. Without limitation of the foregoing, future dividend payments, if any, and the level thereof is uncertain, as the Company's dividend policy and the funds available for the payment of dividends from time to time is dependent upon, among other things, FCF, financial requirements for the Company's operations and the execution of its growth strategy, fluctuations in working capital and the timing and amount of capital expenditures, debt service requirements and other factors beyond the Company's control. Further, the ability of Tourmaline to pay dividends is subject to applicable laws (including the satisfaction of the solvency test contained in applicable corporate legislation) and contractual restrictions contained in the instruments governing its indebtedness, including its credit facility.
Statements relating to "reserves" are also deemed to be forward looking information, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future.
Although Tourmaline believes that the expectations and assumptions on which such forward-looking information is based are reasonable, undue reliance should not be placed on the forward-looking information because Tourmaline can give no assurances that it will prove to be correct. Since forward-looking information addresses future events and conditions, by its very nature it involves inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to: the risks associated with the oil and gas industry in general such as operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures; supply chain disruptions; the uncertainty of estimates and projections relating to reserves, production, revenues, costs and expenses; health, safety and environmental risks; commodity price and exchange rate fluctuations; interest rate fluctuations; changes in rates of inflation; marketing and transportation; loss of markets; environmental risks; competition; incorrect assessment of the value of acquisitions; failure to complete or realize the anticipated benefits of acquisitions or dispositions; hazards such as fire, explosion, blowouts, cratering, and spills, any of which could result in substantial damage to wells, production facilities, other property and the environment or in personal injury; stock market volatility; ability to access sufficient capital from internal and external sources; uncertainties associated with counterparty credit risk; failure to obtain required regulatory and other approvals including drilling permits and the impact of not receiving such approvals on the Company's long-term planning; climate change risks; severe weather (including wildfires, floods and drought); risks of wars or other hostilities or geopolitical events, civil insurrection and pandemics; risks relating to Indigenous land claims and duty to consult; data breaches and cyber attacks; risks relating to the use of artificial intelligence; changes in legislation, including but not limited to tax laws, royalties and environmental regulations (including greenhouse gas emission reduction requirements and other decarbonization or social policies and including uncertainty with respect to the interpretation and impact of omnibus Bill C-59 and the related amendments to the Competition Act (Canada)); trade policy, barriers, disputes or wars (including new tariffs or changes to existing international trade arrangements); and general economic and business conditions and markets. Readers are cautioned that the foregoing list of factors is not exhaustive.
Additional information on these and other factors that could affect Tourmaline, or its operations or financial results, are included in the Company's most recently filed Management's Discussion and Analysis (See "Forward-Looking Statements" therein), Annual Information Form (See "Risk Factors" and "Forward-Looking Statements" therein) and other reports on file with applicable securities regulatory authorities and may be accessed through the SEDAR+ website (www.sedarplus.ca) or Tourmaline's website (www.tourmalineoil.com).
The forward-looking information contained in this news release is made as of the date hereof and Tourmaline undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, unless expressly required by applicable securities laws.
BOE EQUIVALENCY
In this news release, production and reserves information may be presented on a "barrel of oil equivalent" or "BOE" basis. BOEs 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, as the value ratio between natural gas and crude oil based on the current prices of natural gas and crude oil is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.
FINANCIAL OUTLOOKS
Also included in this news release are estimates of Tourmaline's 2026, 2027 and 2028 FCF, which are based on, among other things, the various assumptions as to production levels, receipt of drilling permits, capital expenditures and other assumptions disclosed in this news release and, with respect to 2026 to 2028 FCF, Tourmaline's estimated average production of 620,000 – 640,000 boepd for 2026, 665,000 boepd for 2027 and 680,000 boepd for 2028, commodity price assumptions for natural gas (2026 - $3.54/mmbtu NYMEX U.S., $1.90/mcf AECO, $2.50/mmbtu PG&E Citygate U.S., $17.37/mcf JKM U.S.; 2027 - $3.33/mmbtu NYMEX U.S., $2.41/mcf AECO, $3.36/mmbtu PG&E Citygate U.S., $14.14mcf JKM U.S.; 2028 - $3.62/mmbtu NYMEX U.S., $2.61/mcf AECO, $3.79/mmbtu PG&E Citygate U.S., $10.31/mcf JKM U.S), crude oil (2026 - $81.06/bbl WTI U.S.; 2027 - $72.18/bbl WTI U.S; 2028 - $68.63/bbl WTI U.S ) and an exchange rate assumption (USD$/CAD$) of $0.72 for 2026 and 2027 and $0.73 for 2028. In addition, such estimates are provided for illustration only and are based on budgets and forecasts as of the date hereof that are subject to change and a variety of contingencies including prior years' results. To the extent such estimates constitute a financial outlook, they are included to provide readers with an understanding of Tourmaline's anticipated FCF based on the capital expenditure, production, pricing, exchange rate and other assumptions described herein and readers are cautioned that the information may not be appropriate for other purposes.
NON-GAAP AND OTHER FINANCIAL MEASURES
This news release contains the terms "cash flow", "capital expenditures", "EP expenditures", "free cash flow", and "operating netback", which are considered "non-GAAP financial measures" and the terms "cash flow per diluted share", "free cash flow per diluted share", "operating netback per boe", and "cash flow per-boe", which are considered "non-GAAP financial ratios". These terms do not have a standardized meaning prescribed by GAAP. In addition, this news release contains the terms "adjusted working capital" and "net debt", which are considered "capital management measures" and do not have standardized meanings prescribed by GAAP. Accordingly, the Company's use of these terms may not be comparable to similarly defined measures presented by other companies. Investors are cautioned that these measures should not be construed as an alternative to or more meaningful than the most directly comparable GAAP measures in evaluating the Company's performance. See "Non-GAAP and Other Financial Measures" in the most recent Management's Discussion and Analysis for more information on the definition and description of these terms
Non-GAAP Financial Measures
Cash Flow
Management uses the term "cash flow" for its own performance measure and to provide shareholders and potential investors with a measurement of the Company's efficiency and its ability to generate the cash (net of current taxes) necessary to fund its future growth expenditures, to repay debt or to pay dividends. The most directly comparable GAAP measure for cash flow is cash flow from operating activities. A summary of the reconciliation of cash flow from operating activities to cash flow, is set forth below:
Three Months Ended |
Six Months Ended |
|||
(000s) |
2026 |
2025 |
2026 |
2025 |
Cash flow from operating activities (per GAAP) |
$ 643,793 |
$ 745,049 |
$ 1,586,420 |
$ 1,833,360 |
Current tax recovery |
14,580 |
42,933 |
19,768 |
5,051 |
Current taxes paid |
14,978 |
18,932 |
19,778 |
18,932 |
Change in non-cash working capital |
112,738 |
15,917 |
22,278 |
(71,466) |
Cash flow |
$ 786,089 |
$ 822,831 |
$ 1,648,244 |
$ 1,785,877 |
Free Cash Flow
Management uses the term "free cash flow" for its own performance measure and to provide shareholders and potential investors with a measurement of the Company's ability to manage debt levels and return value to shareholders. Free cash flow is defined as cash flow less capital expenditures, excluding acquisitions and dispositions. The most directly comparable GAAP measure for cash flow is cash flow from operating activities. A summary of the reconciliation of cash flow from operating activities to free cash flow is set forth below:
Three Months Ended |
Six Months Ended |
|||
(000s) |
2026 |
2025 |
2026 |
2025 |
Cash flow from operating activities (per GAAP) |
$ 643,793 |
$ 745,049 |
$ 1,586,420 |
$ 1,833,360 |
Current tax recovery |
14,580 |
42,933 |
19,768 |
5,051 |
Cash taxes paid |
14,978 |
18,932 |
19,778 |
18,932 |
Change in non-cash working capital |
112,738 |
15,917 |
22,278 |
(71,466) |
Cash flow |
$ 786,089 |
$ 822,831 |
$ 1,648,244 |
$ 1,785,877 |
Capital expenditures |
(554,808) |
(505,239) |
(463,524) |
(1,330,257) |
Property acquisitions |
- |
- |
1,829 |
12,143 |
Proceeds from divestitures |
(39,164) |
(724) |
(792,439) |
(1,747) |
Free Cash flow |
$ 192,117 |
$ 316,868 |
$ 394,110 |
$ 466,016 |
Capital Expenditures
Management uses the term "capital expenditures" as a measure of capital investment in exploration and production activity, as well as property acquisitions and divestitures. The most directly comparable GAAP measure for capital expenditures is cash flow used in investing activities. A summary of the reconciliation of cash flow used in investing activities to capital expenditures is set forth below:
Three Months Ended |
Six Months Ended |
|||
(000s) |
2026 |
2025 |
2026 |
2025 |
Cash flow used in investing activities (per GAAP) |
$ 635,150 |
$ 803,220 |
$ 669,407 |
$ 1,517,299 |
Corporate acquisition |
(13,636) |
- |
(13,636) |
- |
Proceeds from sale of investment |
9,092 |
- |
9,092 |
- |
Change in non-cash working capital |
(75,798) |
(297,981) |
(201,339) |
(187,042) |
Capital expenditures |
$ 554,808 |
$ 505,239 |
$ 463,524 |
$ 1,330,257 |
EP Expenditures
Management uses the term "EP expenditures" or exploration and production expenditures as a measure of capital investment in exploration and production activity, and such spending is compared to the Company's annual budgeted exploration and production expenditures. The most directly comparable GAAP measure for exploration and production spending is cash flow used in investing activities. A summary of the reconciliation of cash flow used in investing activities to exploration and production expenditures is set forth below:
Three Months Ended |
Six Months Ended |
|||
(000s) |
2026 |
2025 |
2026 |
2025 |
Cash flow used in investing activities (per GAAP) |
$ 635,150 |
$ 803,220 |
$ 669,407 |
$ 1,517,299 |
Change is non-cash working capital |
(75,798) |
(297,981) |
(201,339) |
(187,042) |
Corporate Acquisition |
(13,636) |
– |
(13,636) |
– |
Proceeds from sale of investment |
9,092 |
– |
9,092 |
– |
Property acquisitions |
– |
– |
(1,829) |
(12,143) |
Proceeds from divestitures |
39,164 |
724 |
792,439 |
1,747 |
Other |
(18,102) |
(16,190) |
(34,812) |
(32,356) |
EP Expenditures |
$ 575,870 |
$ 489,773 |
$ 1,219,322 |
$ 1,287,505 |
Operating Netback
Management uses the term "operating netback" as a key performance indicator and one that is commonly presented by other oil and natural gas producers. Operating netback is defined as the sum of commodity sales from production, premium on risk management activities and realized gains on financial instruments less the sum of royalties, transportation costs and operating expenses. A summary of the reconciliation of operating netback from commodity sales from production, which is a GAAP measure, is set forth below:
Three Months Ended |
Six Months Ended |
|||
(000s) |
2026 |
2025 |
2026 |
2025 |
Commodity sales from production |
$ 1,348,528 |
$ 1,134,466 |
$ 2,795,577 |
$ 2,592,033 |
Premium on risk management activities |
114,862 |
262,646 |
372,759 |
600,255 |
Realized gain on financial instruments |
29,647 |
108,937 |
18,591 |
205,354 |
Royalties |
(144,560) |
(90,328) |
(313,396) |
(269,487) |
Operating expenses |
(248,199) |
(289,467) |
(533,214) |
(585,128) |
Transportation costs |
(281,703) |
(282,803) |
(603,387) |
(600,000) |
Operating netback |
$ 818,575 |
$ 843,451 |
$ 1,736,930 |
$ 1,943,027 |
Non-GAAP Financial Ratios
Operating Netback per-boe
Management calculates "operating netback per-boe" as operating netback divided by total production for the period. Operating netback per-boe is a key performance indicator and measure of operational efficiency and one that is commonly presented by other oil and natural gas producers. A summary of the calculation of operating netback per boe, is set forth below:
Three Months Ended |
Six Months Ended |
|||
($/boe) |
2026 |
2025 |
2026 |
2025 |
Revenue, excluding processing income |
$ 27.61 |
$ 26.66 |
$ 27.95 |
$ 29.83 |
Royalties |
(2.67) |
(1.60) |
(2.75) |
(2.37) |
Operating expenses |
(4.59) |
(5.12) |
(4.68) |
(5.14) |
Transportation costs |
(5.21) |
(5.01) |
(5.29) |
(5.27) |
Operating netback |
$ 15.14 |
$ 14.93 |
$ 15.23 |
$ 17.05 |
Capital Management Measures
Adjusted Working Capital
Management uses the term "adjusted working capital" for its own performance measures and to provide shareholders and potential investors with a measurement of the Company's liquidity. A summary of the reconciliation of working capital (deficit) to adjusted working capital (deficit), is set forth below:
(000s) |
As at |
As at |
Working capital (deficit) |
$ (553,507) |
$ (419,306) |
Fair value of financial instruments – short-term (asset) |
(327,574) |
(135,676) |
Lease liabilities – short-term |
7,515 |
8,034 |
Decommissioning obligations – short-term |
64,000 |
75,000 |
Unrealized foreign exchange in working capital – liability (asset) |
(1,565) |
991 |
Adjusted working capital (deficit) |
$ (811,131) |
$ (470,957) |
Net Debt
Management uses the term "net debt", as a key measure for evaluating its capital structure and to provide shareholders and potential investors with a measurement of the Company's total indebtedness. A summary of the composition of net debt, is set forth below:
(000s) |
As at |
As at |
Long-term debt |
$ (697,121) |
$(1,052,914) |
Adjusted working capital (deficit) |
(811,131) |
(470,957) |
Net debt |
$ (1,508,252) |
$(1,523,871) |
Supplementary Financial Measures
The following measures are supplementary financial measures: cash flow per diluted share, operating expenses ($/boe), cash general and administrative expenses ($/boe) and transportation costs ($/boe). These measures are calculated by dividing the numerator by a diluted share count or by total production for the period, depending on the financial measure discussed.
OIL AND GAS METRICS
This news release contains certain oil and gas metrics 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. Such metrics have been included in this document to provide readers with additional measures to evaluate the Company's performance; however, such measures are not reliable indicators of the Company's future performance and future performance may not compare to the Company's performance in previous periods and therefore such metrics should not be unduly relied upon.
ESTIMATED DRILLING INVENTORY
This news release discloses an estimate of the percentages of the Company's total drilling locations that are booked and derived from the Company's Independent Reserve Evaluations. Drilling locations are categorized as follows: (i) proved undeveloped locations; (ii) probable undeveloped locations; (iii) unbooked locations; and (iv) an aggregate total of (i), (ii) and (iii). Proved producing wells, proved undeveloped locations, including drilled-uncompleted locations, and probable undeveloped locations are booked and derived from the Company's Independent Reserve Evaluations, and account for drilling locations that have associated proved and/or probable reserves, as applicable. Unbooked locations are internal estimates based on the Company's prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources (including contingent and prospective). Unbooked locations have been identified by management as an estimation of the Company's multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that the Company will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which the Company will actually drill wells, including the number and timing thereof is ultimately dependent upon the availability of funding, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While a certain number of the unbooked drilling locations have been derisked by drilling existing wells in relative close proximity to such unbooked drilling locations, the majority of other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production.
SUPPLEMENTAL INFORMATION REGARDING PRODUCT TYPES
This news release includes references to Q2 2026 average daily production and 2026 forecast average daily production. The following table is intended to provide supplemental information about the product type composition for each of the production figures that are provided in this news release:
Light and Medium |
Conventional |
Shale |
Natural Gas |
Oil Equivalent |
|||||
Company Gross |
Company Gross |
Company Gross |
Company Gross |
Company Gross |
|||||
Q2 2026 Average Daily Production |
41,458 |
1,426,302 |
1,460,110 |
71,671 |
594,198 |
||||
2026 Forecast Average Daily Production |
44,525 |
1,517,810 |
1,508,800 |
81,040 |
630,000 |
Notes: |
|
(1) |
For the purposes of this disclosure, condensate has been combined with Light and Medium Crude Oil as the associated revenues and certain costs of condensate are similar to Light and Medium Crude Oil. Accordingly, NGLs in this disclosure exclude condensate. |
CREDIT RATINGS
Credit ratings are intended to provide investors with an independent measure of credit quality of an issue of securities. Credit ratings are not recommendations to purchase, hold or sell securities and do not address the market price or suitability of a specific security for a particular investor. There is no assurance that any rating will remain in effect for any given period of time or that any rating will not be revised or withdrawn entirely by a rating agency in the future if, in its judgment, circumstances so warrant.
INITIAL PRODUCTION RATES
Any references in this news release to initial production rates are useful in confirming the presence of hydrocarbons; however, such rates are not determinative of the rates at which such wells will continue production and decline thereafter and are not necessarily indicative of long-term performance or ultimate recovery. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for the company. Such rates are based on field estimates and may be based on limited data available at this time.
GENERAL
See also "Forward-Looking Statements" and "Non-GAAP and Other Financial Measures" in the most recently filed Management's Discussion and Analysis.
1H |
first half |
2H |
second half |
AECO |
Alberta Energy Company and is the Canadian benchmark price for natural gas |
bbl |
barrel |
bbls/day |
barrels per day |
bbl/mmcf |
barrels per million cubic feet |
bcf |
billion cubic feet |
bcfe |
billion cubic feet equivalent |
bpd or bbl/d |
barrels per day |
boe |
barrel of oil equivalent |
boepd or boe/d |
barrel of oil equivalent per day |
bopd or bbl/d |
barrel of oil, condensate or liquids per day |
C2+ |
a hydrocarbon mixture consisting of ethane and heavier hydrocarbons |
DUC |
drilled but uncompleted wells |
Dutch TTF or TTF |
a natural gas pricing location within the Netherlands |
EP |
exploration and production |
gj |
gigajoule |
JKM |
Japan Korea Marker |
LPG |
Liquefied Petroleum Gas |
mbbls |
thousand barrels |
mmbbls |
million barrels |
mboe |
thousand barrels of oil equivalent |
mboepd |
thousand barrels of oil equivalent per day |
mcf |
thousand cubic feet |
mcfpd or mcf/d |
thousand cubic feet per day |
mcfe |
thousand cubic feet equivalent |
mmboe |
million barrels of oil equivalent |
mmbtu |
million British thermal units |
mmbtu/d |
million British thermal units per day |
mmcf |
million cubic feet |
mmcfpd or mmcf/d |
million cubic feet per day |
natural gas |
conventional natural gas and shale gas |
NEBC |
Northeast British Columbia |
NGL or NGLs |
natural gas liquids |
PGE |
Pacific Gas & Electric |
Tcf |
trillion cubic feet |
Tier 1 |
Tier 1 in reference to locations or inventory refers to the most productive and high-quality drilling locations or inventory in the Company's estimation, characterized by superior geological properties and anticipated higher initial production rates. These drilling locations or inventory are considered by the Company the best for drilling due to their potential for higher productivity and profitability |
To view Tourmaline's Management's Discussion and Analysis and Consolidated Financial Statements for the periods ended June 30, 2026 and 2025, please refer to SEDAR+ (www.sedarplus.ca) or Tourmaline's website at www.tourmalineoil.com.
ABOUT TOURMALINE OIL CORP.
Tourmaline is Canada's largest and most active natural gas producer dedicated to producing the lowest-development-cost natural gas in North America. We are an investment grade exploration and production company providing strong and predictable operating and financial performance through the development of our two core areas in the Western Canadian Sedimentary Basin. With our existing large reserve base, decades-long drilling inventory, relentless focus on execution, cost management, safety and environmental performance improvement, we are excited to provide shareholders an excellent return on capital and an attractive source of income through our base dividend and surplus free cash flow distribution strategies.
SOURCE Tourmaline Oil Corp.
FOR FURTHER INFORMATION, PLEASE CONTACT: Tourmaline Oil Corp., Michael Rose, Chairman, President and Chief Executive Officer, (403) 266-5992 OR Tourmaline Oil Corp., Brian Robinson, Chief Financial Officer, (403) 767-3587; [email protected] OR Tourmaline Oil Corp., Scott Kirker, Chief Legal Officer and External Affairs, (403) 767-3593; [email protected] OR Tourmaline Oil Corp., Jamie Heard, Vice President, Capital Markets, (403) 767-5942; [email protected] OR Tourmaline Oil Corp., Suite 2900, 250 - 6th Avenue S.W., Calgary, Alberta T2P 3H7, Phone: (403) 266-5992; Facsimile: (403) 266-5952, E-mail: [email protected], Website: www.tourmalineoil.com
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