43,657 boe/d production in Q4/25 exceeded guidance by over 1,100 boe/d⁽²⁾ and was 6% higher than Q3/25
Repaid $110 million of debt to exit 2025 with $761.5 million of net debt⁽¹⁾
Adjusted funds flow⁽¹⁾ (“AFF”) of $464 million ($2.40/share) in 2025 increased 22% year-over-year
Record $223 million ($1.15/share) of annual free funds flow⁽¹⁾ drove 50% free funds flow yield⁽¹⁾ at year-end, with over $33 million returned to shareholders in 2025 via ongoing share buybacks
$5.47/share of PDP net asset value with 31% expansion in PDP reserves per debt-adjusted share^(1)(14)

Calgary, Alberta–(Newsfile Corp. – March 11, 2026) – Saturn Oil & Gas Inc. (TSX: SOIL) (OTCQX: OILSF) (“Saturn” or the “Company“), a light oil-weighted producer focused on unlocking value through the development of assets in Saskatchewan and Alberta, is pleased to report our operating and audited financial results for the three and twelve months ended December 31, 2025, highlighted by quarterly production above guidance, record free funds flow and free funds flow yield, continued debt repayment and return of capital to shareholders, along with a summary of the Company’s 2025 year-end independent reserves evaluation. Saturn’s financial statements (“Financial Statements“), Management’s Discussion and Analysis (“MD&A“) and Annual Information Form (“AIF“) will be available on our website and filed on SEDAR+ at sedarplus.ca. A conference call and webcast to discuss our results is scheduled for Thursday, March 12, 2026 at 8:00 am Mountain Time (10:00 am Eastern Time). Access details for the conference call and webcast are provided below.

“Through 2025, we continued to execute our blueprint and remained focused on optimizing and developing our low-decline, light oil-weighted asset base while improving our per share metrics year-over-year. As a result, we beat expectations, repaid $110 million on our Senior Notes, exceeded Q4 production guidance by 1,100 boe/d and generated record free funds flow⁽¹⁾ of $223 million. We bought back $33 million of our shares in 2025, and since we view every dollar of debt repayment as a dollar back to shareholders, Saturn returned over $143 million to our shareholders last year. If we include the share buybacks to date in 2026, that figure increases to $155 million, or about a quarter of our current market cap,” said John Jeffrey, Saturn’s Chief Executive Officer.

In commenting on Saturn’s year end reserves, Mr. Jeffrey continued, “We recorded the largest positive proved developed producing (“PDP“) technical revisions in our history, increased booked drilling locations⁽¹⁵⁾ by 8% over 2024, giving us a booked and unbooked identified inventory⁽¹⁵⁾ that management estimates could sustain 20 years of drilling at our current pace. Our reserves per debt adjusted share^(1)(13) grew by 31 to 32% across all categories, and we maintained our PDP net asset value per share at just under $5.50⁽¹⁾⁽³⁾, despite a 19% decline in the evaluators’ oil price forecasts. Our 2025 results and reserves further highlight the upside opportunity in Saturn given the disconnect between our current market value and underlying reserves value.”

Q4 & FULL YEAR 2025 HIGHLIGHTS

Production of 43,657 boe/d in Q4/25 was 6% higher than the prior quarter, as volumes continue to exceed both analysts’ expectations and Saturn’s guidance, while 2025 volumes averaged 41,728 boe/d, and contributed to 46% growth in production per debt-adjusted share⁽¹³⁾ versus 2024.
$110 million of Senior Notes repayment to exit 2025 with net debt⁽¹⁾ of $761.5 million, achieved during a period of substantially lower oil prices, and resulting in a net debt to adjusted EBITDA⁽¹⁾ ratio of 1.35x.
Record $464 million of AFF⁽¹⁾ ($2.40/share basic) generated in 2025 against a backdrop of 13% lower realized oil prices than the previous year, and $121 million ($0.64/share basic) of AFF⁽¹⁾ in Q4/25. Record AFF was supported by an average 23% outperformance of type curve⁽¹⁴⁾ across all of our assets, an ongoing focus on operating cost reductions and our robust hedging strategy.
Highest free funds flow⁽¹⁾ in Saturn’s history, totaling $223 million ($1.15/share basic) in 2025, was allocated to debt repayment, our ongoing return of capital framework and tuck-in acquisitions, with free funds flow⁽¹⁾ of $56 million ($0.30/share basic) generated in Q4/25.

Over $33 million returned to shareholders in 2025 by purchasing and cancelling 14.4 million common shares (“Shares“) through our normal course issuer bid (“NCIB“) and substantial issuer bid, including $12 million returned in Q4/25 via the purchase and cancellation of 4.8 million Shares.
Opex (net operating expenses⁽¹⁾) averaged $19.09/boe in 2025 and $19.24/boe in Q4/25, both coming in below Saturn’s guidance range of $19.50 – $20.00/boe, reflecting our disciplined approach to cost reduction and efficiency capture, with the lower opex also supporting positive year end reserves bookings.
Capital expenditures⁽¹⁾⁽⁴⁾ totaled $241 million in 2025, resulting in the drilling of 93 gross (71.4 net) wells, with Q4/25 capital of $65 million directed to drill 30 gross (22.1 net) wells, including 20 in southeast Saskatchewan; six in southwest Saskatchewan; and four in Central Alberta.
Core-up strategy continued with $94 million of tuck-in acquisitions during 2025, meaningfully expanding our open hole multi-lateral (“OHML“) development potential in southeast Saskatchewan. At year-end 2025, our drilling location inventory included over 380 gross (318.0 net)⁽¹⁵⁾ identified OHML Bakken, Spearfish, Midale and Torquay locations, having an internally estimated net present value approaching $450 million that was previously unrecognized and represents significant future value creation potential.
Net income of $168 million ($0.87/share basic) was generated in 2025, and $31 million ($0.17 per share basic) in Q4/25, primarily reflecting continued operational performance, along with an unrealized gain on derivatives and unrealized foreign exchange gain on our Senior Notes compared to unrealized losses in 2024.

EVENTS SUBSEQUENT TO YEAR END

Returned an additional $10.0 million to shareholders through the acquisition of 3.2 million Shares on the open market via our NCIB subsequent to the end of the quarter. This brings Saturn’s total return to shareholders since the initial NCIB launch in August 2024 to $53.6 million, with the purchase and cancellation of over 22 million Shares.
Added further price protection with incremental oil hedges through 2026 and into 2027, using wide Canadian dollar collars as well as differential swaps through 2026. Saturn layered on new foreign exchange rate contracts to lock in the principal and interest payments on our US denominated debt through mid-2027, replacing the previous contracts that were monetized for a gain of approximately $9 million in Q4/25. The Company remains active and will continue to opportunistically enhance our hedge book when market conditions are optimal.

FINANCIAL AND OPERATING HIGHLIGHTS

	Three months ended			Year ended
($000s, except per share amounts)	December 31, 2025	September 30, 2025	December 31, 2024	December 31, 2025	December 31, 2024

FINANCIAL HIGHLIGHTS

Petroleum and natural gas sales	233,554	235,344	268,845	983,691	908,296
Cash flow from operating activities	76,065	126,097	91,157	457,399	311,937
Operating netback, net of derivatives⁽¹⁾	136,600	128,565	152,616	554,565	472,236
Adjusted EBITDA⁽¹⁾	140,854	123,571	152,823	549,322	482,997
Adjusted funds flow⁽¹⁾	120,697	103,282	129,205	463,954	380,091
per share – Basic⁽¹⁾	0.64	0.54	0.64	2.40	2.10
per share – Diluted⁽¹⁾	0.61	0.51	0.63	2.28	2.05
Free funds flow⁽¹⁾	55,933	15,943	23,785	222,714	133,775
per share – Basic⁽¹⁾	0.30	0.08	0.12	1.15	0.74
per share – Diluted⁽¹⁾	0.28	0.08	0.12	1.09	0.72
Net income (loss)	31,230	3,466	(26,318)	167,569	54,106
per share – Basic	0.17	0.02	(0.13)	0.87	0.30
– Diluted	0.16	0.02	(0.13)	0.82	0.29
Acquisitions, net of cash acquired	23,469	65,212	26,011	93,813	564,407
Proceeds from dispositions	–	–	576	–	(25,132)
Capital expenditures⁽¹⁾⁽⁴⁾	64,764	87,339	105,420	241,240	246,316
Total assets	2,190,825	2,214,611	2,161,578	2,190,825	2,161,578
Net debt⁽¹⁾, end of period	761,476	782,514	860,155	761,476	860,155
Shareholders’ equity	946,591	924,514	803,972	946,591	803,972
Common shares outstanding, end of period	184,084	190,020	199,555	184,084	199,555
Weighted average, basic	187,135	192,520	201,484	193,402	180,864
Weighted average, diluted	197,604	202,785	206,205	203,842	185,607

OPERATING HIGHLIGHTS

Average production volumes
Crude oil (bbls/d)	31,287	29,152	30,449	30,430	24,885
NGLs (bbls/d)	4,052	4,180	3,381	3,718	2,954
Natural gas (mcf/d)	49,906	46,860	43,328	45,478	38,093
Total boe/d	43,657	41,142	41,051	41,728	34,188
% Oil and NGLs	81%	81%	82%	82%	81%
Average realized prices
Crude oil ($/bbl)	72.52	81.71	89.13	81.05	92.63
NGLs ($/bbl)	38.72	37.49	46.74	41.84	44.89
Natural gas ($/mcf)	2.44	0.67	1.41	1.84	1.43
Processing expenses ($/boe)	(0.21)	(0.30)	(0.27)	(0.25)	(0.31)
Petroleum and natural gas sales ($/boe)	58.15	62.18	71.18	64.59	72.59
Operating netback ($/boe)
Petroleum and natural gas sales	58.15	62.18	71.18	64.59	72.59
Royalties	(6.65)	(7.70)	(8.71)	(7.75)	(9.12)
Net operating expenses⁽¹⁾	(19.24)	(19.24)	(18.35)	(19.09)	(19.01)
Transportation expenses	(1.57)	(1.49)	(1.07)	(1.57)	(1.39)
Operating netback⁽¹⁾	30.69	33.75	43.05	36.18	43.07
Realized gain (loss) on derivatives	3.32	0.22	(2.64)	0.23	(5.33)
Operating netback, net of derivatives⁽¹⁾	34.01	33.97	40.41	36.41	37.74

2025 RESERVES HIGHLIGHTS

The 2025 year end reserves evaluation of Saturn’s crude oil and natural gas assets in Saskatchewan and Alberta was effective December 31, 2025, dated February 20, 2026, and prepared by independent reserves evaluators Ryder Scott Company-Canada (“Ryder Scott“) in accordance with the Canadian Oil and Gas Evaluation Handbook and in compliance with National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101“) (the “2025 Reserve Report“).

Our 2025 Reserve Report reflects our drilling and development success realized during the year, Saturn’s extensive inventory of highly economic drilling locations, and the impact of tuck-in acquisitions. Our fulsome reserves disclosure is included in the Company’s AIF for the year ended December 31, 2025, which is available on SEDAR+ at www.sedarplus.com and on our website.

Reserves growth across all categories which more than offset the approximately 19% decline in Ryder Scott’s 2026 oil price forecasts year-over-year:

Category	Reserves (million boe⁽³⁾)	Year / Year Increase	Reserve Life Index (RLI)
Proved Developed Producing (“PDP“)	94.4 MMboe	+9%	6 years
Total Proved (“1P“)	144.1 MMboe	+9%	9 years
Total Proved + Probable (“2P“)	219.6 MMboe	+10%	14 years

Reserves per debt-adjusted share⁽¹³⁾ expanded versus 2024, including growth of 31% on PDP, 31% on 1P and 32% on 2P, reflecting robust reserves additions and Saturn’s focus on continuous improvement in per share metrics.
Net asset value (“NAV“) per share⁽¹⁾⁽³⁾ remained relatively constant at $5.47 for PDP, $7.75 for 1P, and $12.98 for 2P, showcasing the opportunity presented by a disconnect between the Company’s underlying value and current market value.
Largest PDP positive technical revisions in Saturn’s history, totaling 11.4MMboe, driven by base well outperformance, year-over-year opex reductions, waterflood impact and PDP conversions, with new reserves added in each category from the combination of extensions, improved recovery, infill drilling, technical revisions and discoveries:
- PDP additions of 22.9 MMboe = 44% of 2024 PDP reserves;
- 1P additions of 26.8 MMboe = 32% of 2024 1P reserves; and
- 2P additions of 34.8 MMboe = 25% of 2024 2P reserves.
Expanded inventory of future drilling opportunities, with over 1,200 booked drilling locations^(3)(15), 8% higher than in 2024. An additional approximately 1,400 locations^(3)(15) have been internally identified, positioning Saturn with an inventory that could potentially maintain flat production for an estimated 20 years of drilling.
Replaced production⁽³⁾ by 150% on a PDP basis, 176% on 1P and 229% on 2P.
Robust capital efficiencies on finding, development and acquisition costs (“FD&A“)^{(3)(9)(10)(12)} and recycle ratios^(3)(11), including changes in future development capital (“FDC“)⁽³⁾:
- 1P FD&A was $16.26/boe with a 2.2x recycle ratio^(3)(11) and 2P FD&A was $16.79/boe with a 2.2x recycle ratio^(3)(11)

OPERATIONS UPDATE

Saturn’s fourth quarter production averaged 43,657 boe/d, again exceeding analyst consensus estimates and our previous guidance by over 1,000 boe/d, driving full year 2025 average production of 41,728 boe/d. These strong 2025 volumes reflect our continued type curve outperformance across each of our core operating areas. In southeast Saskatchewan, we outperformed type curve⁽¹⁴⁾ by an average of 32% due to our continued Bakken, Spearfish and Frobisher development, while we exceeded type curves by 16%⁽¹⁴⁾ in Central Alberta and 13%⁽¹⁴⁾ in West Central Saskatchewan on the year. As a result of this outperformance, we produced higher volumes than originally anticipated without needing to spend more capital, which improves our efficiency and long-term sustainability. In Q4/25, we invested $64.8 million, with 81% directed to production-adding activities, including the drilling of 30 gross (22.1 net) wells, of which 20 were drilled in Southeast Saskatchewan, six in Southwest Saskatchewan, and four in Central Alberta.

Our Q4 and full year 2025 results demonstrate the capabilities of our team and the strength of our Saturn blueprint. The Company continued to enhance performance across our low decline, mid-life cycle assets, while ongoing cost reductions extended the economic life of our assets, enabling higher sustained production and incremental reserves bookings. Net operating expenses⁽¹⁾ in the fourth quarter averaged $19.24/boe, remaining below the revised guidance range of $19.50 – $20.00/boe, with full-year operating costs averaging $19.09/boe.

Momentum continues to build in our OHML program which provides a clear example of Saturn’s ability to create value. The assets now being developed using OHML had zero value ascribed when acquired, with no locations nor reserves booked on those lands. Today, those same assets have more than 380 gross (318.0 net) OHML locations⁽¹⁵⁾ identified, with only 100 gross / 85.0 net booked⁽¹⁵⁾ at year-end 2025. Based on a US$60 WTI price deck (consistent with our 2026 guidance), Saturn has modeled over $190 million of value⁽¹⁾⁽³⁾ yet to be unlocked from the OHML Bakken locations alone, with an estimated $240 million of potential value⁽¹⁾⁽³⁾ on all of the other OHML locations in our inventory. This represents potential for over $430 million of previously unrecognized value⁽¹⁾⁽³⁾ from Saturn’s OHML program alone.

We are currently drilling our fourth Spearfish OHML well on a recently acquired, undeveloped land package in southeast Saskatchewan. The well is a six-leg design located near our recent 16-05 Spearfish well, which came on production at more than three times type curve expectations⁽¹⁴⁾. We anticipate providing production performance updates on this new well with the release of our Q1/26 results in May.

Saturn also drilled two OHML Midale re-entry wells late in Q4/25, and as we continue to drill in Q1/26, the team is focused on improving drilling efficiencies and increasing metres drilled per day. Through these re-entries, we can increase the length of the original leg and drill new additional legs, enabling the Company to benefit from certain royalty incentives on Crown land that boost economics and accelerate payouts.

Our team is excited about new development at Roncott within our Flat Lake field; an area that has remained undrilled since 2021. We drilled three new wells at Roncott in late 2025, including a multi-lateral re-entry and two open-hole single lateral new drills. All three of these wells are performing above type curve expectations⁽¹⁴⁾, increasing the potential for follow-up drilling in close proximity to this initial development and opening up an additional 10 to 15 locations. We also initiated a waterflood at Roncott, as the reservoir appears highly receptive, and implementing a waterflood eliminates the costs associated with transporting and handling produced water off-site, capturing operational synergies and driving down operating costs. Roncott is just one example of Saturn’s application of OHML learnings across our portfolio to improve recoveries, reduce costs and find innovative ways to enhance asset profitability.

Safety continues to be at the heart of Saturn’s operations. In 2025, we proudly achieved a second consecutive year with zero lost time injuries, a notable achievement given the 18% increase in person-hours worked in 2025 over 2024, following the 38% increase in 2024 versus 2023. This success is showcased by a 196% increase in hazard identifications from 2023 to 2025, and is a direct result of our team’s proactive risk identification and mitigation approach to preventing incidents before they occur. Saturn’s embedded safety culture is dedicated to protecting our people first and foremost, while also minimizing potential liabilities and supporting our financial performance.

OUTLOOK

The recent strike on Iran has increased volatility across global oil markets due to supply disruption concerns and the security of key shipping routes. Saturn remains well positioned to navigate this volatility given our disciplined risk management strategy, strong leverage to oil prices, and flexible capital allocation framework. In addition, we continue to seek opportunities to enhance and optimize Saturn’s hedge book, and can quickly layer in further hedges as prices escalate. Our strong torque to oil prices is a key differentiator relative to peers, as each US$5 per barrel movement in WTI from our guidance pricing assumption of US$60 per barrel is expected to drive an estimated $45 to 50 million impact to our AFF⁽¹⁾, further supporting robust free funds flow⁽¹⁾ generation and financial sustainability.

In Q1/26, we forecast capital expenditures⁽¹⁾⁽⁴⁾to range between $40 and $50 million, with average production anticipated between 41,000 and 42,000 boe/d⁽²⁾. Approximately 70% of our 2026 capital program is expected to be deployed in the second half of the year, affording the Company time and the flexibility to adjust capital spending should pricing and market conditions remain supportive through the back half of 2026. Saturn continues to prioritize free funds flow⁽¹⁾ generation, further net debt⁽¹⁾ reduction and a disciplined capital allocation framework that includes ongoing share buybacks, tuck-in acquisitions and other measures to support shareholder value creation and long-term resilience.

2025 RESERVES DETAIL

Summary of Crude Oil, Natural Gas and Natural Gas Liquids Reserves and Before Tax Net Present Values⁽³⁾⁽⁵⁾

The following tables are a summary of the Ryder Scott estimated Company reserves (Company share gross volumes) and NPVs of future net revenue, before tax, based on forecast price and costs as contained in the Reserve Report. The Reserve Report encompasses 100% of the Company’s oil and gas properties as of December 31, 2025.

Reserves Category	Light and Medium Crude Oil (Mbbl)		Heavy Crude Oil (Mbbl)		Conventional Natural Gas (MMscf)		Natural Gas Liquids (Mbbl)		Total MBOE (Mboe)
	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Proved
Developed Producing	58,263	53,786	10,312	8,785	104,631	95,276	8,387	7,630	94,400	86,081
Developed Non-Producing	366	350	9	9	149	144	32	31	431	414
Undeveloped	34,185	31,541	1,100	1,058	61,631	55,206	3,665	3,307	49,221	45,107
Total Proved	92,813	85,676	11,421	9,853	166,411	150,626	12,084	10,968	144,053	131,602
Probable	49,394	45,439	4,951	4,219	91,491	81,792	5,985	5,290	75,579	68,580
Total Proved Plus Probable	142,207	131,115	16,372	14,071	257,902	232,418	18,068	16,259	219,631	200,182

NPVs Before Tax^(3)(5)(6)(7)

Reserves Category⁽³⁾	Before Income Tax (MM$)⁽²⁾
	0%	5%	10%	15%	20%
Proved:
Developed Producing	2,179.5	2,074.8	1,768.0	1,517.4	1,327.5
Developed Non-Producing	15.5	11.0	8.1	6.1	4.7
Undeveloped	1,097.7	663.9	411.9	256.3	155.1
Total Proved	3,292.7	2,749.7	2,187.9	1,779.8	1,487.4
Probable	2,579.0	1,487.3	962.3	673.4	498.7
Total Proved plus Probable	5,871.7	4,237.0	3,150.3	2,453.2	1,986.1

Net Asset Value^(1)(3)(6)(7)

The following table sets out a calculation of NAV based on the before-tax estimated net present value of future net revenue discounted at 10% (“NPV₁₀ BT“) associated with the PDP, 1P and 2P reserves, as evaluated in the 2025 Reserve Report, including deductions for future development costs, abandonment and reclamation obligations:

	Proved Developed Producing	Total Proved	Total Proved + Probable
NPV₁₀ BT (MM$)	1,768.0	2,187.9	3,150.3
Net debt⁽¹⁾ December 31, 2025 (MM$)	(761.5)	(761.5)	(761.5)
Net Asset Value (MM$)	1,006.5	1,426.4	2,388.8
Basic shares outstanding (MM)	184.1	184.1	184.1
Estimated NAV per basic share ($)	$5.47	$7.75	$12.98

Reserves Reconciliation^(3)(5)(8)

The following table provides a summary of the reconciliation of the changes in the Company’s gross reserves as of December 31, 2025 against reserves at December 31, 2024, based on forecast prices and costs assumptions in effect at the applicable reserve evaluation date:

RESERVES RECONCILIATION

	Light and Medium Oil			Heavy Oil			Associated and Non-Associated Gas
	Proved (Mbbl)	Probable (Mbbl)	Proved + Probable (Mbbl)	Proved (Mbbl)	Probable (Mbbl)	Proved + Probable (Mbbl)	Proved (Mbbl)	Probable (Mbbl)	Proved + Probable (Mbbl)
31-Dec-24	88,066	45,678	133,744	12,147	4,072	16,219	129,913	71,400	201,313
Extensions	901	193	1,094	–	–	–	649	259	909
Improved Recovery	220	(92)	128	–	–	–	92	(50)	42
Infill Drilling	2,976	2,776	5,753	5	2	7	6,390	6,267	12,657
Technical Revisions	5,218	(4,667)	551	927	1,057	1,984	18,979	(1,929)	17,050
Discoveries	1,346	2,033	3,379	–	–	–	2,006	2,282	4,287
Acquisitions	7,139	3,735	10,874	–	–	–	26,063	12,528	38,592
Dispositions	(53)	(12)	(65)	–	–	–	(24)	(5)	(29)
Economic Factors⁽⁹⁾	(3,129)	(250)	(3,378)	(425)	(179)	(604)	(1,056)	738	(318)
Production	(9,873)	–	(9,873)	(1,234)	–	(1,234)	(16,600)	–	(16,600)
31-Dec-25	92,813	49,394	142,207	11,421	4,951	16,372	166,411	91,492	257,903

	NGL/Condensate			Mboe
	Proved (Mbbl)	Probable (Mbbl)	Proved + Probable (Mbbl)	Proved (Mbbl)	Probable (Mbbl)	Proved + Probable (Mbbl)
31-Dec-24	10,649	5,891	16,540	132,515	67,541	200,056
Extensions	60	25	85	1,070	261	1,331
Improved Recovery	30	(22)	8	265	(122)	143
Infill Drilling	332	184	516	4,379	4,007	8,385
Technical Revisions	635	(1,237)	(601)	9,944	(5,169)	4,775
Discoveries	20	6	26	1,701	2,419	4,120
Acquisitions	1,950	1,076	3,027	13,433	6,900	20,333
Dispositions	(2)	(0)	(3)	(59)	(13)	(72)
Economic Factors⁽⁹⁾	(235)	62	(173)	(3,964)	(244)	(4,208)
Production	(1,357)	–	(1,357)	(15,231)	–	(15,231)
31-Dec-25	12,084	5,985	18,068	144,053	75,579	219,631

Future Development Costs⁽³⁾⁽⁶⁾

The following table provides a summary of the estimated FDC required to bring Saturn’s 1P and 2P undeveloped reserves to production, as reflected in the Reserve Report, which costs have been deducted in Ryder Scott’s estimation of future net revenue associated with such reserves:

Future Development Costs (MM$)	Total Proved	Total Proved + Probable
2026	225.6	254.1
2027	243.7	303.3
2028	259.2	310.6
2029	280.9	357.8
2030	203.6	376.9
Remaining	6.2	461.5
Total (undiscounted)	1,219.2	2,064.2

Performance Measures^{(3)(9)(10)(11)(12)}

The following tables highlight our 2P and 1P FD&A costs⁽¹⁾⁽³⁾ (including changes in FDC) and associated recycle ratios based on the evaluation of reserves prepared by Ryder Scott:

2P FD&A costs^{(1)(3)(9)(10)(11)(12)}	2025	2024	2023	Three Year
F&D capital expenditures ($MM)	$ 232.7	$ 233.4	$ 120.8	$ 587.0
Net acquisition expenditures ($MM)	$ 93.8	$ 539.3	$ 466.7	$ 1,099.8
Total expenditures ($MM)	$ 326.5	$ 772.7	$ 587.5	$ 1,686.7
Change in FDC ($MM)	$ 257.8	$ 560.4	$ 759.5	$ 1,577.7
Total expenditures including FDC ($MM)	$ 584.3	$ 1,333.1	$ 1,347.0	$ 3,264.4
Reserve additions (Mboe)	34.8	67.3	91.3	193.3
FD&A cost ($ per BOE)	$ 16.79	$ 19.82	$ 14.76	$ 16.89
Average Operating Netback ($ per BOE)	$ 36.18	$ 43.07	$ 47.64	$ 42.30
Recycle Ratio (x)	2.2x	2.2x	3.2x	2.5x

1P FD&A costs^{(1)(3)(9)(10)(11)(12)}	2025	2024	2023	Three Year
Total expenditures ($MM)	$ 326.5	$ 772.7	$ 587.5	$ 1,686.7
Change in 1P FDC ($MM)	$ 109.3	$ 332.5	$ 489.6	$ 931.4
Total expenditures including FDC ($MM)	$ 435.8	$ 1,105.2	$ 1,077.1	$ 2,618.1
Reserve additions (Mboe)	26.8	47.4	63.6	137.8
FD&A cost ($ per BOE)	$ 16.26	$ 23.32	$ 16.94	$ 19.00
Recycle Ratio (x)	2.2x	1.8x	2.8x	2.2x

Total Location Summary^(3)(15)

The following table summarizes the gross drilling locations identified for future development in the Reserve Report:

Field (Business Unit)	Locations Year End 2025	Previous Locations Year End 2024
Southeast Saskatchewan	741	658
West Central Saskatchewan	243	246
Central Alberta	221	211
Total Locations	1,205	1,115

CONFERENCE CALL AND WEBCAST

The Company plans to host a conference call on Thursday, March 12, 2026, at 8:00 am Mountain Time (10:00 am Eastern Time), which will include a discussion with Saturn’s leadership team, who will provide an overview of our Q4 and year end 2025 results and reserves, followed by a question-and-answer session with attendees.

Date: Thursday, March 12, 2026
Time: 8:00 am MT (10:00 am ET)
Live Webcast Link: https://www.gowebcasting.com/14545
North America (Toll Free) Dial In: 1-833-752-3741
International Dial In: 1-647-846-8678

An audio replay of the webcast will be available one hour after the end of the call at the link above and will remain accessible for 12 months. The replay link will also be posted on Saturn’s website.

NOTES
⁽¹⁾ See reader advisory: Non-GAAP and Other Financial Measures.
⁽²⁾ See reader advisory: Supplemental Information Regarding Product Types.
⁽³⁾ See reader advisory: Oil and Gas Metrics & Reserve Definitions.
⁽⁴⁾ Includes capitalized G&A.
⁽⁵⁾ Total values may not add due to rounding.
⁽⁶⁾ The estimated NPV does not represent fair market value of the reserves.
⁽⁷⁾ Price forecasts and foreign exchange rate assumptions of three consultant’s (GLJ Ltd., McDaniel & Associates Consultants Ltd. and Sproule Associates Ltd.) average forecast as of January 1, 2025 as applied in the Reserve Report.
⁽⁸⁾ Economic Factors include changes due to commodity pricing, price differentials and operating cost.
⁽⁹⁾ FD&A costs are calculated by dividing the identified capital expenditures, including expenditures associated with assets acquired or disposed of during the year, by the applicable reserves. These include changes in future development capital costs.
⁽¹⁰⁾ While Nl 51-101 requires that the effects of acquisitions and dispositions be excluded from the calculation of finding and development costs, FD&A costs have been presented because acquisitions and dispositions can have a significant impact on the Company’s ongoing reserve replacement costs and excluding these amounts could result in an inaccurate portrayal of the Company’s cost structure. Finding and development costs including acquisitions and dispositions have been presented above.
⁽¹¹⁾ Recycle ratio is calculated as operating netback before derivatives divided by FD&A costs. Based on a 2025 operating netback of $36.18 per boe.
⁽¹²⁾ The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.
⁽¹³⁾ Calculated by converting year end net debt to Shares (net debt divided by the closing price of the Company’s Shares on the TSX on December 31, 2025, of $2.43 per Share), adding that to the basic Shares outstanding at year end of 184.1 million and dividing the total reserves at year end by the debt adjusted Shares.
⁽¹⁴⁾ See reader advisory: Type Curves and Initial Production.
⁽¹⁵⁾ See reader advisory: Drilling Locations

ABOUT SATURN

Saturn is a returns-driven Canadian energy company focused on the efficient, responsible and innovative development of high-quality, light oil weighted assets, supported by an acquisition strategy targeting accretive and complementary opportunities. The Company’s portfolio of free-cash flowing, low-decline operated assets in Saskatchewan and Alberta provide a deep inventory of long-term economic drilling opportunities across multiple zones. With an unwavering commitment to building an entrepreneurial focused culture, Saturn’s goal is to increase per Share reserves, production and cash flow at an attractive return on invested capital. The Company’s Shares are listed for trading on the TSX under ticker ‘SOIL’ and on the OTCQX under the ticker ‘OILSF’. Further information and our corporate presentation are available on Saturn’s website at www.saturnoil.com.

INVESTOR & MEDIA CONTACTS

John Jeffrey, MBA – Chief Executive Officer
Tel: +1 (587) 392-7900
www.saturnoil.com

Cindy Gray, MBA – VP Investor Relations
Tel: +1 (587) 392-7900
[email protected]

READER ADVISORIES

Non-GAAP and Other Financial Measures

Throughout this press release and in other materials disclosed by the Company, Saturn employs certain measures to analyze financial performance, financial position, and cash flow. These non-GAAP and other financial measures do not have any standardized meaning prescribed under IFRS and therefore may not be comparable to similar measures presented by other entities. The non-GAAP and other financial measures should not be considered to be more meaningful than GAAP measures which are determined in accordance with IFRS, such as net income (loss), cash flow from operating activities, and cash flow used in investing activities, as indicators of Saturn’s performance.

The disclosure under the section “Non-GAAP and Other Financial Measures” in our MD&A, including non-GAAP financial measures and ratios, capital management measures and supplementary financial measures in the Company’s Financial Statements and MD&A are incorporated by reference into this news release.

This news release may use the terms “Adjusted EBITDA”, “Adjusted Funds Flow”, “Net Debt”, “Free Funds Flow”, “Net Debt to Annualized Adjusted EBITDA” and “Net Debt to Annualized AFF” which are capital management financial measures. See the disclosure under “Capital Management” in our Audited Consolidated Financial Statements and MD&A for the three months and year ended December 31, 2025, for an explanation and composition of these measures and how these measures provide useful information to an investor, and the additional purposes, if any, for which management uses these measures, and, where applicable, a reconciliation of the Company’s historical non-GAAP financial measures to the most directly comparable measure calculated in accordance with IFRS for the applicable period then ended.

Capital Expenditures

Saturn uses capital expenditures to monitor its capital investments relative to those budgeted by the Company on an annual basis. Saturn’s capital budget excludes acquisition and disposition activities as well as the accounting impact of any accrual changes or payments under certain lease arrangements. The most directly comparable GAAP measure for capital expenditures is cash flow used in investing activities. The following table reconciles capital expenditures and capital expenditures, net A&D to the nearest GAAP measure, cash flow used in investing activities.

	Three months ended			Year ended
($000s)	December 31, 2025	September 30, 2025	December 31, 2024	December 31, 2025	December 31, 2024
Cash flow used in investing activities	104,906	102,027	114,533	374,387	749,533
Change in non-cash working capital	(16,673)	50,524	17,474	(39,334)	36,058
Capital expenditures, net A&D⁽¹⁾⁽³⁾	88,233	152,551	132,007	335,053	785,591
Acquisitions, net of cash acquired	(23,469)	(65,212)	(26,011)	(93,813)	(564,407)
Proceeds from disposition	–	–	(576)	–	25,132
Capital expenditures⁽¹⁾⁽³⁾	64,764	87,339	105,420	241,240	246,316

FD&A Expenditures

Saturn uses finding, development, and acquisition (“FD&A“) expenditures as a basis to monitor its capital efficiency. The Company’s FD&A expenditures are calculated by adding A&D to capital expenditures less certain capitalized overhead costs. This measure calculates the capital cost outlay associated with the Company’s exploration and development activities for the purposes of finding, developing and, when desired, acquiring its reserves.

Adjusted Funds Flow per Share

Adjusted funds flow per share is a non-GAAP ratio by management to better analyze the Company’s performance against prior periods on a more comparable basis. Adjusted funds flow per share is calculated as adjusted funds flow from operations divided by weighted average shares outstanding during the applicable period on a basic or diluted basis.

Free Funds Flow, Free Funds Flow per Share and Free Funds Flow Yield

Saturn uses free funds flow as an indicator of the efficiency and liquidity of its business, measuring its funds after capital investment available to manage debt levels, pursue acquisitions and gauge optionality to pay dividends and/or and return capital to shareholders through activities such as share repurchases. Saturn calculates free funds flow as adjusted funds flow in the period less capital expenditures. By removing the impact of current period capital expenditures from adjusted funds flow, management monitors its free funds flow to inform its capital allocation decisions. Free funds flow is also presented on a per share basis as a non-GAAP financial ratio. Free funds flow yield is calculated by dividing free funds flow by Saturn’s market capitalization as at year end 2025 ($447.4 million), expressed as a percentage, which is used as a valuation and capital allocation metric. The following table reconciles adjusted funds flow to free funds flow.

	Three months ended			Year ended
($000s)	December 31, 2025	September 30, 2025	December 31, 2024	December 31, 2025	December 31, 2024
Adjusted funds flow	120,697	103,282	129,205	463,954	380,091
Capital expenditures⁽¹⁾⁽³⁾	(64,764)	(87,339)	(105,420)	(241,240)	(246,316)
Free funds flow	55,933	15,943	23,785	222,714	133,775

Gross Petroleum and Natural Gas Sales

Gross petroleum and natural gas sales is calculated by adding crude oil, natural gas and NGLs revenue, before deducting certain gas processing expenses in arriving at petroleum and natural gas revenue as required under IFRS 15. These processing expenses associated with the processing of natural gas and NGLs revenue are a result of the Company transferring custody of the product at the terminal inlet, and therefore receiving net prices. This metric is used by management to quantify and analyze the realized price received before required processing deductions, against benchmark prices. The calculation of the Company’s gross petroleum and natural gas sales is shown within the petroleum and natural gas sales section within the MD&A for the year ended December 31, 2025.

Royalties as a Percentage of Gross Petroleum and Natural Gas Sales

Royalties as a percentage of gross petroleum and natural gas sales is calculated as royalties divided by gross petroleum and natural gas sales. This metric is used by management to quantify the Company’s royalty costs as they relate to revenue before deducting certain processing expenses and to better analyze how royalty rates change over time and compare to prior periods.

Net Operating Expenses and Net Operating Expenses per BOE

Net operating expense is calculated by deducting processing income primarily generated by processing third party production at processing facilities where the Company has an ownership interest, from operating expenses presented on the Statement of income (loss). Where the Company has excess capacity at one of its facilities, it will process third-party volumes to reduce the cost of ownership in the facility. The Company’s primary business activities are not that of a midstream entity whose activities are focused on earning processing and other infrastructure-based revenues, and as such third-party processing revenue is netted against operating expenses in this MD&A. This metric is used by management to evaluate the Company’s net operating expenses on a unit of production basis. Net operating expense per boe is a non-GAAP financial ratio and is calculated as net operating expense divided by total barrels of oil equivalent produced over a specific period of time. The calculation of the Company’s net operating expenses is shown within the net operating expenses section within the MD&A for the year ended December 31, 2025.

Operating Netback and Operating Netback, Net of Derivatives

The Company’s operating netback is determined by deducting royalties, net operating expenses and transportation expenses from petroleum and natural gas sales. The Company’s operating netback, net of derivatives is calculated by adding or deducting realized financial derivative commodity contract gains or losses from the operating netback. Derivative contract termination payments are included in realized derivative commodity contract gains or losses for the purposes of calculating the operating netback. The Company’s operating netback and operating netback, net of derivatives are used in operational and capital allocation decisions. Presenting operating netback and operating netback, net of derivatives on a per boe basis is a non-GAAP financial ratio and allows management to better analyze performance against prior periods on a per unit of production basis. The calculation of the Company’s operating netbacks and operating netback, net of derivatives are summarized as follows.

	Three months ended			Year ended
($000s)	December 31, 2025	September 30, 2025	December 31, 2024	December 31, 2025	December 31, 2024
Petroleum and natural gas sales	233,554	235,344	268,845	983,691	908,296
Royalties	(26,710)	(29,134)	(32,881)	(117,976)	(114,080)
Net operating expenses	(77,272)	(72,831)	(69,307)	(290,770)	(237,895)
Transportation expenses	(6,317)	(5,639)	(4,056)	(23,878)	(17,370)
Operating netback	123,255	127,740	162,601	551,067	538,951
Realized gain (loss) on derivatives	13,345	825	(9,985)	3,498	(66,715)
Operating netback, net of derivatives	136,600	128,565	152,616	554,565	472,236

($ per boe amounts)
Petroleum and natural gas sales	58.15	62.18	71.18	64.59	72.59
Royalties	(6.65)	(7.70)	(8.71)	(7.75)	(9.12)
Net operating expenses	(19.24)	(19.24)	(18.35)	(19.09)	(19.01)
Transportation expenses	(1.57)	(1.49)	(1.07)	(1.57)	(1.39)
Operating netback	30.69	33.75	43.05	36.18	43.07
Realized gain (loss) on derivatives	3.32	0.22	(2.64)	0.23	(5.33)
Operating netback, net of derivatives	34.01	33.97	40.41	36.41	37.74

Enterprise Value

The Company’s enterprise value is calculated as total market capitalization plus net debt. Enterprise value is used to assess the valuation of the Company. Refer to the Liquidity and Capital Resources section in the MD&A for the year ended December 31, 2025 for further information.

Capital Management Measures

National Instrument 52-112 Non-GAAP and Other Financial Measures Disclosure (“NI 52-112“) defines a capital management measure as a financial measure that: (i) is intended to enable an individual to evaluate an entity’s objectives, policies and processes for managing the entity’s capital; (ii) is not a component of a line item disclosed in the primary financial statements of the entity; (iii) is disclosed in the notes to the financial statements of the entity; and (iv) is not disclosed in the primary financial statements of the entity. Please refer to note 16 “Capital Management” in Saturn’s financial statements as at and for the year ended December 31, 2025, for additional disclosure on: adjusted working capital deficit (surplus), net debt, adjusted EBITDA, adjusted funds flow, free funds flow, annualized quarterly adjusted funds flow, and net debt to annualized quarterly adjusted funds flow, each of which are capital management measures used by the Company in the MD&A for the year ended December 31, 2025.

Supplementary Financial Measures

NI 52‐112 defines a supplementary financial measure as a financial measure that: (i) is, or is intended to be, disclosed on a periodic basis to depict the historical or expected future financial performance, financial position or cash flow of an entity; (ii) is not disclosed in the financial statements of the entity; (iii) is not a non‐GAAP financial measure; and (iv) is not a non‐GAAP ratio. The supplementary financial measures used in this MD&A are either a per unit disclosure of a corresponding GAAP measure, or a component of a corresponding GAAP measure, presented in the financial statements. Supplementary financial measures that are disclosed on a per unit basis are calculated by dividing the aggregate GAAP measure (or component thereof) by the applicable unit for the period. Supplementary financial measures that are disclosed on a component basis of a corresponding GAAP measure are a granular representation of a financial statement line item and are determined in accordance with GAAP.

Drilling Locations

Drilling locations have been identified by Saturn’s management as an estimation of Saturn’s multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that Saturn will drill all locations and if drilled there is no certainty that such locations will result in additional oil and natural gas reserves, resources or production. The drilling locations on which Saturn 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.

Supplemental Information Regarding Product Types

The Company’s aggregate average production for the past eight quarters and the references to “crude oil”, “NGLs”, and “natural gas” reported in this press release consist of the following product types, as defined in NI 51-101 and using a conversion ratio of 1 Bbl : 6 Mcf where applicable:

	2025				2024
	Q4	Q3	Q2	Q1	Q4	Q3	Q2	Q1
Average daily production
Light & medium crude oil (bbls/d)	27,962	25,825	26,712	27,697	27,330	24,992	18,346	18,981
Heavy crude oil (bbls/d)	3,325	3,327	3,438	3,445	3,119	4,002	2,664	–
NGLs (bbls/d)	4,052	4,180	3,310	3,318	3,381	3,407	2,673	2,344
Conventional natural gas (mcf/d)	49,906	46,860	41,740	43,319	43,328	39,885	38,664	30,416
Total (boe/d)	43,657	41,142	40,417	41,680	41,051	39,049	30,127	26,394

Q1 2026 average production, at the midpoint of the guidance range, is anticipated to be comprised of approximately 64% light and medium crude oil, 8% heavy crude oil, 9% NGLs and 19% natural gas.

Type Curve and Initial Production

Certain type curve disclosure presented herein represents estimates of the production decline and ultimate volumes expected to be recovered over time. “Results Projected” are based on a forward estimate of ultimate volumes to be recovered over time based on the initial 30 days average production data. References in this press release to IP rates, other short-term production rates or initial performance measures relating to new wells are useful in confirming the presence of hydrocarbons; however, such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long-term performance or of ultimate recovery. While encouraging, readers are cautioned not to place reliance on such rates in calculating Saturn’s aggregate production. Accordingly, Saturn cautions that the test results should be considered to be preliminary.

Boe Presentation

Boe means barrel of oil equivalent. All boe conversions in this press release are derived by converting gas to oil at the ratio of six thousand cubic feet (“Mcf“) of natural gas to one barrel (“Bbl“) of oil. Boe may be misleading, particularly if used in isolation. A boe conversion rate of 1 Bbl : 6 Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio of oil compared to natural gas based on currently prevailing prices is significantly different than the energy equivalency ratio of 1 Bbl : 6 Mcf, utilizing a conversion ratio of 1 Bbl : 6 Mcf may be misleading as an indication of value.

Oil and Gas Metrics & Reserve Definitions

This press release contains metrics commonly used in the oil and gas industry which have been prepared by management, such as “FD&A costs”, “Net Asset Value”, “Recycle Ratio” and “Reserve Life Index”. These terms do not have a standardized meaning and may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons.

“FD&A Cost” represents finding, developing and acquisition cost as calculated as the sum of 2025 capital expenditures not including capitalized general and administration expenses ($232.7 million) plus net acquisition costs ($93.8 million), divided by the change in reserves within the applicable reserves category.

“Net Asset Value” has been calculated based on the estimated net present value of all future revenue from the Company’s reserves, before income taxes as estimated by Ryder Scott effective December 31, 2025, including expenditures for abandonment, decommissioning and reclamation costs for all producing and non-producing wells and facilities, less net debt.

“Recycle Ratio” is calculated by dividing operating netback per boe by FD&A costs for a year.

“Reserve life index” or “RLI” is calculated by dividing the applicable reserves category volumes by 2025 fourth quarter production of 43,657 boe/d for 365 days as an estimation of how many years at a steady production level would the reserve volumes support.

“Production Replacement” is calculated by dividing reserves added by annual production, expressed as a percentage and shown by reserve category.

“Proved” reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

“Probable” reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

“Developed” reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g. when compared to the cost of drilling a well) to put the reserves on production.

“Developed Producing” reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.

“Developed Non-Producing” reserves are those reserves that either have not been on production, or have previously been on production, but are shut in, and the date of resumption of production is unknown.

“Undeveloped” reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable, possible) to which they are assigned.

Forward-Looking Information and Statements

Certain information included in this press release constitutes forward-looking information under applicable securities legislation. Forward-looking information typically contains statements with words such as “anticipate”, “believe”, “expect”, “plan”, “intend”, “estimate”, “propose”, “project”, “scheduled”, “will” or similar words suggesting future outcomes or statements regarding an outlook. Forward-looking information in this press release may include, but is not limited to, the Company’s capital allocation strategy, the benefits of robust adjusted funds flow, expectations with respect to the oil and natural gas environment, estimated sensitivity to commodity price changes, the benefits of acquisition activity, the success of our development program, expectations with respect to our assets, including anticipated funding of certain programs, net present value and anticipated volumes and production associated therewith, the Company’s outlook for Q1 2026, the expected composition of production, the Company’s drilling, completion and development plans, capital allocation strategy, the strength and sustainability of the Company’s asset base and expertise of its personnel, expectations concerning the quantum and timing of the Q1 capital program, expected returns from OHML drilling programs, the liquidity of the Company and available credit, expectations regarding netbacks, cost savings, hedging strategy, operating costs, return of capital, share buyback and debt reduction strategies, the Company’s intent to make purchases under the NCIB and the expected benefits to shareholders, the effect the Company’s capital strategy on per share metrics and equity accretion, the business plan, cost model and strategy of the Company, per boe operating costs, anticipated production levels and related product types, and expectations regarding anticipated pricing trends, the impact and length of the conflict in Iran, growth opportunities and market conditions.

The forward-looking statements contained in this press release are based on certain key expectations and assumptions made by Saturn. Although Saturn believes that the expectations reflected in its forward-looking information are reasonable, undue reliance should not be placed on forward-looking information because Saturn can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified in this press release, assumptions have been made regarding and are implicit in, among other things, expectations and assumptions concerning: the timing of and success of future drilling; commodity prices; the ability to successfully replicate certain strategies across the Company’s other areas; development and completion activities; the performance of existing wells; the performance of new wells; the availability and performance of facilities and pipelines, the ability to allocate capital to pay down debt and grow or maintain production; debt repayment plans; capital return strategies and future growth plans; the impact of our hedging strategy; the geological characteristics of Saturn’s properties; drilling inventory and booked locations; production and revenue guidance, the application of regulatory and licensing requirements, the availability of capital, labour and services, the creditworthiness of industry partners and the ability to integrate acquisitions.

Although Saturn believes that the expectations and assumptions on which the forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because Saturn can give no assurance that they will prove to be correct. Since forward-looking statements address future events and conditions, by their very nature they involve 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, risks associated with the oil and gas industry in general (e.g., operational risks in development, exploration and production; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to production, costs and expenses, and health, safety and environmental risks), constraints in the availability of services, commodity price and exchange rate fluctuations, actions of OPEC and OPEC+ members, impact of conflict in the Middle East, changes in legislation impacting the oil and gas industry, adverse weather or break-up conditions and uncertainties resulting from potential delays or changes in plans with respect to exploration or development projects or capital expenditures. These and other risks are set out in more detail in Saturn’s Management Discussion and Analysis for the three and twelve months ended December 31, 2025 and Annual Information Form for the year ended December 31, 2025, available on SEDAR+ at sedarplus.ca.

The forward-looking information in this news release reflects the Company’s current expectations, assumptions and/or beliefs based on information currently available to the Company. The forward-looking information contained in this press release is made as of the date hereof and Saturn undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws. The forward-looking information contained in this press release is expressly qualified by this cautionary statement.

This news release contains future-oriented financial information and financial outlook information (collectively, “FOFI“) about Saturn’s prospective results of operations including, without limitation, the Company’s capital expenditures, production, price movement sensitivity, asset retirement obligations, lease payments and administrative costs, all of which are subject to the same assumptions, risk factors, limitations, and qualifications as set forth above. Readers are cautioned that the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on FOFI. Saturn’s actual results, performance or achievement could differ materially from those expressed in, or implied by, these FOFI, or if any of them do so, what benefits Saturn will derive therefrom. Saturn has included the FOFI in order to provide readers with a more complete perspective on Saturn’s future operations and such information may not be appropriate for other purposes. Saturn disclaims any intention or obligation to update or revise any FOFI statements, whether as a result of new information, future events or otherwise, except as required by law.

All dollar figures included herein are presented in Canadian dollars, unless otherwise noted.

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To view the source version of this press release, please visit https://www.newsfilecorp.com/release/288118

Matribhumi Samachar English

Saturn Oil & Gas Inc. Announces 2025 Results and Reserves, With $110 Million of Debt Repayment, Record Q4 Production Ahead of Guidance and 50% Free Funds Flow Yield

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