CALGARY, AB, Oct. 31, 2024 /PRNewswire/ - Veren Inc. ("Veren" or the "Company") (TSX:VRN) (NYSE:VRN) is pleased to announce its operating and financial results for the quarter ended September 30, 2024, revised 2024 guidance, 2025 budget and updated five-year outlook.

KEY HIGHLIGHTS

Generated third quarter excess cash flow of $114 million, with full year 2024 excess cash flow expected to total $625 million.
Returned $290 million to shareholders in dividends and share repurchases year-to-date, including $85 million in third quarter.
Entered into a strategic infrastructure transaction, directing $400 million of net cash proceeds to debt reduction.
Expect year-end net debt of $2.5 billion, or 1.1x debt to funds flow, reflecting $1.3 billion of total debt reduction in 2024.
Production results from Gold Creek West pad in the Alberta Montney rank in the top one percent of wells in North America.
Disciplined and returns-focused 2025 budget expected to generate excess cash flow of $575 million to $775 million.

"We continue to be excited about the quality of the resource and excess cash flow deliverability of our Kaybob Duvernay and Alberta Montney assets," said Craig Bryksa, President and CEO of Veren. "We have successfully enhanced our drilling efficiencies since entering each of these plays and are making adjustments to our completions design in the Alberta Montney to further enhance deliverability and returns. Under our disciplined and returns-focused budget for 2025 and five-year plan, we expect to generate significant excess cash flow and returns for shareholders."

FINANCIAL HIGHLIGHTS

Adjusted funds flow totaled $548.3 million during third quarter 2024, or $0.89 per share diluted, driven by a strong operating netback of $34.09 per boe.
For the quarter ended September 30, 2024, development capital expenditures, which included drilling and development, facilities and seismic costs, totaled $395.9 million.
Veren's net debt as at September 30, 2024 was $3.0 billion. During the quarter, the Company announced a strategic transaction related to the sale of certain infrastructure assets in the Alberta Montney to Pembina Gas Infrastructure ("PGI"), which included net cash proceeds of $400 million. Subsequent to the quarter, Veren successfully closed the transaction and directed all proceeds toward its balance sheet. The Company now expects its net debt to be $2.5 billion by year-end 2024.
Subsequent to the quarter, Veren successfully renewed and extended its unsecured, covenant-based credit facilities with a maturity date of November 2028. The Company also elected to cancel its $400 million unsecured syndicated credit facility, decreasing the size of its combined facilities to $2.4 billion. Veren currently has an unutilized credit capacity of $1.5 billion.
The Company continues to hedge a portion of its production as part of its ongoing commodity marketing and diversification program. Veren has hedged 50 percent of its oil and liquids production and 30 percent of its natural gas production for the remainder of 2024, net of royalty interest. In the first half of 2025, Veren has hedged 35 percent of its oil and liquids production and over 30 percent of its natural gas production, net of royalty interest. The Company has also diversified its pricing exposure for natural gas, resulting in the majority of its production through 2026 receiving a combination of fixed prices and pricing related to major U.S. markets.
Veren reported net income of $277.2 million, or $0.45 per share diluted, for the quarter ended September 30, 2024.

RETURN OF CAPITAL HIGHLIGHTS

During third quarter 2024, the Company returned $84.6 million to shareholders, including the base dividend, for a total of $290 million year-to-date. Veren remains committed to returning 60 percent of its annual excess cash flow to shareholders through a combination of dividends and share repurchases.
The Company repurchased 1.3 million shares for $13.7 million through its normal course issuer bid ("NCIB") during third quarter. Year-to-date, Veren has repurchased 6.9 million shares under its NCIB.
Subsequent to the quarter, the Company's Board of Directors declared a quarterly cash base dividend of $0.115 per share payable on January 2, 2025, to shareholders of record on December 15, 2024.

OPERATIONAL UPDATE

Average production in third quarter 2024 was 184,829 boe/d (65% oil and liquids). Veren's third quarter production reflects the full impact of the disposition of non-core assets in Saskatchewan, which closed in late second quarter, in addition to unplanned third-party facilities downtime and capacity constraints within some of the Company's Alberta Montney infrastructure. Veren plans to accelerate incremental capital spending during the remainder of the year to implement several recently identified facilities projects to improve infrastructure and reduce future downtime in the play. Excluding the impact of the disposition and downtime, Veren's production grew by approximately 6,000 boe/d between second and third quarter 2024.
Veren tested a plug-and-perforation ("P&P") completions design on wells in the Gold Creek area of its Alberta Montney in 2024 as part of its efforts to continuously seek additional efficiencies. The Company brought on stream two multi-well pads in this area with average peak 30-day rates of 600 to 900 boe/d per well (60% light oil, 10% NGLs) and recently brought on stream two additional multi-well pads that have been flowing for less than 30 days, using the P&P design. These wells are economic and were completed at a lower cost than wells completed using the single-point entry ("SPE") design in this area. However, production has underperformed the SPE completed wells which generated an average peak 30-day rate of 1,200 boe/d per well in 2023. While significantly enhancing the Company's knowledge of the play, Veren has determined that the results do not support moving away from using SPE design in this area. The Company's development plan going forward, as reflected in its revised 2024 guidance, 2025 guidance and the five-year plan, incorporates the use of SPE design in the Gold Creek area.
In the Karr area of the Alberta Montney, Veren has brought on stream two multi-well pads to date which were completed using the P&P design, generating average peak 30-day rates of 1,000 to 1,300 boe/d per well (70% light oil, 5% NGLs). The Company is testing SPE completions design in this area with three additional multi-well pads that are expected to be on stream between late 2024 and early 2025.
Wells within the Company's most recent Gold Creek West pad in the Alberta Montney ranked amongst the top one percent of all oil and liquids wells brought on stream in North America over the last three years based on an initial production rate of 180 days. This four well pad was originally brought on stream in first quarter 2024 and generated a peak 30-day rate of 2,000 boe/d per well (80% light oil, 5% NGLs). Strong performance from this pad has resulted in average cumulative production of 450,000 boe (70% light oil, 5% NGLs) per well over its first nine months, while currently producing at a rate of 1,800 boe/d per well. The Company expects to bring on stream an adjacent seven well pad in early 2025. Veren is also expanding capacity at its facility in the area in fourth quarter 2024 to accommodate increasing expected production from future pads. Veren has over 300 net internally identified drilling locations in this area.
In the Kaybob Duvernay, Veren brought three multi-well pads on stream in the Volatile Oil window during third quarter with average peak 30-day rates of 800 to 1,300 boe/d per well (70% condensate, 5% NGLs), further demonstrating the consistency of Veren's operational execution and results in the play. These pads included wells drilled on the eastern portion of the Company's land position, further delineating Veren's acreage in the area. The Company is currently completing additional delineation wells on the western portion of its land position which it expects to bring on stream in fourth quarter 2024.
Veren continues to target efficiency improvements through knowledge transfer across its assets to enhance overall returns. In the Alberta Montney and Kaybob Duvernay, the Company has reduced average drilling days per 1,000 meter lateral length by approximately 20 percent and 30 percent, respectively, since entering these plays.
In its Southeast Saskatchewan operations, the Company continues to progress its open-hole multi-lateral ("OHML") development. Veren recently brought on stream a step-out well on the eastern portion of its lands which generated a strong peak 30-day rate of 250 bbl/d (100% light oil) and plans to bring additional wells on stream through the remainder of the year.

Adjusted funds flow, adjusted funds flow per share diluted, excess cash flow, operating netback, development capital expenditures, total return of capital, net debt, net debt to adjusted funds flow and base dividends are specified financial measures - refer to the Specified Financial Measures section in this press release for further information. All financial figures are approximate and in Canadian dollars unless otherwise noted. This press release contains forward-looking information and references to specified financial measures. Significant related assumptions and risk factors, and reconciliations are described under the Specified Financial Measures, Forward-Looking Statements and Reserves and Drilling Data sections of this press release, respectively. Further information breaking down the production information contained in this press release by product type can be found in the "Product Type Production Information" section of this press release.

UPDATED 2024 GUIDANCE

Veren now expects to generate annual average production of 191,000 boe/d (65% oil and liquids) in 2024. The Company also expects its 2024 annual development capital expenditures to be $1.45 billion to $1.50 billion, reflecting incremental capital spending on facilities projects and changes to further optimize its completions design in the Alberta Montney, partially offset by a reallocation of development capital from its Saskatchewan assets.
Based on US$75/bbl WTI and $1.50/Mcf AECO for the full year, the Company expects to generate excess cash flow of $625 million in 2024. Veren expects to exit the year with net debt of $2.5 billion, reflecting a total reduction of $1.3 billion in 2024.

2025 GUIDANCE

Based on the current commodity price outlook, Veren expects its development capital expenditures to total $1.48 billion to $1.58 billion in 2025, generating annual average production of 188,000 to 196,000 boe/d (65% oil and liquids). Adjusting for non-core asset dispositions in 2024, the mid-point of the 2025 production guidance range represents growth of 10,000 boe/d, or five percent, year-over-year.
Approximately 85 percent of the Company's 2025 budget is allocated to its Alberta Montney and Kaybob Duvernay plays, which provide top quartile returns, scalability and quick well payouts. In the Alberta Montney, the company has allocated incremental capital for recently identified facilities projects to increase capacity in the play. The remaining capital budget is allocated to Veren's long-cycle, low-decline Saskatchewan assets, which generate among the highest operating netbacks in the portfolio and significant excess cash flow. Consistent with its capital allocation framework, the Company's annual budget also includes a portion of capital allocated to long-term projects, such as decline mitigation, and various environmental initiatives.
Under its 2025 budget, the Company expects to generate excess cash flow of $575 million to $775 million at US$70/bbl to US$75/bbl WTI and $2.50/Mcf AECO, allowing for significant returns to shareholders and further strengthening of the balance sheet. Veren will continue to target the return of 60 percent of its excess cash flow to shareholders, with plans to increase the percentage of excess cash flow returned as the Company further reduces its debt. Veren maintains a strong balance sheet with ample liquidity, access to the investment-grade institutional debt market and an active hedging program to mitigate against commodity price volatility.
Veren will monitor the macroeconomic environment, including results from the upcoming OPEC meeting, and will retain flexibility to lower its overall capital budget and allocation in response to weakness in commodity prices. The Company will continue to prioritize operational execution, strengthening and optimizing its balance sheet and increasing its return of capital to shareholders.

UPDATED FIVE-YEAR PLAN

Veren's annual average production is forecast to grow to 250,000 boe/d in 2029 under its updated five-year plan, driven by its Alberta Montney and Kaybob Duvernay assets. The Company expects to generate $3.9 billion of cumulative after-tax excess cash flow at US$70/bbl WTI and $3.00/Mcf AECO. Under the updated five-year plan, the Company expects to generate excess cash flow per share growth of over 10 percent on a compounded annual basis, similar to its prior plan.

CONFERENCE CALL DETAILS

Veren's management will host a conference call on Thursday, October 31, 2024 at 10:00 a.m. MT (12:00 p.m. ET) to discuss the Company's results and outlook. A slide deck will accompany the conference call and can be found on Veren's website.

Participants can listen to this event online via webcast. To join the call without operator assistance, participants may register online by entering their phone number to receive an instant automated call back. Alternatively, the conference call can be accessed with operated assistance by dialing 1‑888‑510‑2154. Participants will be able to take part in a question and answer session through both the webcast dashboard and the conference line following management's opening remarks.

The webcast will be archived for replay and can be accessed online. The replay will be available shortly after the call's completion.

The Company's most recent investor presentation is available on Veren's website.

2024 GUIDANCE

The Company's guidance for 2024 is as follows:

	Prior	Revised
Total Annual Average Production (boe/d) ⁽¹⁾	192,500 - 197,500	191,000
Development Capital Expenditures ($ millions) ⁽²⁾	$1,400 - $1,500	$1,450 - $1,500

Other Information for 2024 Guidance
Annual operating expenses ($/boe)	$12.50 - $13.50	$13.50
Royalties	10.00% - 11.00%	10.00% - 11.00%

Revised total annual average production (boe/d) is comprised of approximately 65% Oil, Condensate & NGLs and 35% Natural Gas

Specified financial measure that does not have any standardized meaning prescribed by IFRS and, therefore may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section for further information. Excludes capitalized administration of approximately $40 million, in addition to land expenditures and net property acquisitions and dispositions. Revised development capital expenditures spend is allocated on an approximate basis as follows: 90% drilling & development and 10% facilities & seismic

2025 GUIDANCE

The Company's guidance for 2025 is as follows:

Total Annual Average Production (boe/d) ⁽¹⁾	188,000 - 196,000
Development Capital Expenditures ($ millions) ⁽²⁾	$1,475 - $1,575

Other Information for 2025 Guidance
Annual operating expenses ($/boe)	$12.75 - $13.75
Royalties	10.75% - 11.75%

Total annual average production (boe/d) is comprised of approximately 65% Oil, Condensate & NGLs and 35% Natural Gas

Specified financial measure that does not have any standardized meaning prescribed by IFRS and, therefore may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section for further information Excludes capitalized administration of approximately $40 million, in addition to land expenditures and net property acquisitions and dispositions. Development capital expenditures spend is allocated on an approximate basis as follows: 85% drilling & development and 15% facilities & seismic

RETURN OF CAPITAL OUTLOOK

Base Dividend
Current quarterly base dividend per share	$0.115
Total Return of Capital
% of excess cash flow ⁽¹⁾	60 %

1)	Total return of capital is based on a framework that targets to return to shareholders 60% of excess cash flow on an annual basis

The Company's unaudited consolidated financial statements and management's discussion and analysis for the quarter ended September 30, 2024, will be available on the System for Electronic Document Analysis and Retrieval ("SEDAR+") at www.sedarplus.ca, on EDGAR at www.sec.gov and on Veren's website at www.vrn.com.

CONSOLIDATED FINANCIAL AND OPERATING HIGHLIGHTS

	Three months ended September 30		Nine months ended September 30
(Cdn$ millions except per share and per boe amounts)	2024	2023	2024	2023
Financial
Cash flow from operating activities	561.7	648.9	1,598.7	1,584.4
Adjusted funds flow from operations ⁽¹⁾	548.3	687.1	1,728.2	1,764.6
Per share^{(1) (2)}	0.89	1.28	2.79	3.24
Net income (loss)	277.2	(809.9)	126.5	(380.9)
Per share ⁽²⁾	0.45	(1.52)	0.20	(0.70)
Adjusted net earnings from operations ⁽¹⁾	177.0	315.5	601.8	739.8
Per share ^{(1) (2)}	0.29	0.59	0.97	1.36
Dividends declared	70.9	71.7	213.9	143.6
Per share ⁽²⁾	0.115	0.135	0.345	0.267
Net debt ⁽¹⁾	2,959.4	2,876.2	2,959.4	2,876.2
Net debt to adjusted funds flow from operations ^{(1) (3)}	1.3	1.3	1.3	1.3
Weighted average shares outstanding
Basic	616.6	534.3	618.4	542.0
Diluted	617.5	536.9	620.0	544.8
Operating
Average daily production
Crude oil and condensate (bbls/d)	102,373	114,997	108,769	103,094
NGLs (bbls/d)	16,859	21,635	17,656	19,519
Natural gas (mcf/d)	393,582	263,694	393,347	215,012
Total (boe/d)	184,829	180,581	191,983	158,448
Average selling prices ⁽⁴⁾
Crude oil and condensate ($/bbl)	95.05	105.24	95.65	97.72
NGLs ($/bbl)	34.64	27.45	35.99	30.40
Natural gas ($/mcf)	1.21	2.81	1.97	3.19
Total ($/boe)	58.39	74.42	61.54	71.65
Netback ($/boe)
Oil and gas sales	58.39	74.42	61.54	71.65
Royalties	(6.36)	(9.67)	(6.43)	(9.46)
Operating expenses	(13.48)	(14.58)	(13.68)	(14.75)
Transportation expenses	(4.46)	(3.03)	(4.51)	(2.99)
Operating netback⁽¹⁾	34.09	47.14	36.92	44.45
Realized gain (loss) on commodity derivatives	1.98	(0.57)	0.66	0.20
Other ⁽⁵⁾	(3.83)	(5.21)	(4.73)	(3.86)
Adjusted funds flow from operations netback ⁽¹⁾	32.24	41.36	32.85	40.79
Capital Expenditures
Capital acquisitions ⁽⁶⁾	26.4	1.1	26.4	2,075.8
Capital dispositions ⁽⁶⁾	(1.4)	(0.2)	(648.3)	(11.2)
Development capital expenditures ⁽¹⁾
Drilling and development	354.7	285.1	1,023.4	777.8
Facilities and seismic	41.2	30.4	121.7	82.0
Total	395.9	315.5	1,145.1	859.8
Land expenditures	1.1	23.0	36.2	31.4

(1)	Specified financial measure that does not have any standardized meaning prescribed by IFRS and, therefore, may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section for further information.
(2)	The per share amounts (with the exception of dividends per share) are the per share – diluted amounts.
(3)	Net debt to adjusted funds flow from operations is calculated as the period end net debt divided by the sum of adjusted funds flow from operations for the trailing four quarters.
(4)	The average selling prices reported are before realized derivatives and transportation.
(5)	Other includes net purchased products, general and administrative expenses, interest on long-term debt, foreign exchange, cash-settled share-based compensation and certain cash items and excludes transaction costs, foreign exchange on US dollar long-term debt and certain non-cash items.
(6)	Capital acquisitions and dispositions, net represent total consideration for the transactions, including long-term debt and working capital assumed, and exclude transaction costs.

FINANCIAL AND OPERATING HIGHLIGHTS FROM CONTINUING OPERATIONS

	Three months ended September 30		Nine months ended September 30
(Cdn$ millions except per share and per boe amounts)	2024	2023	2024	2023
Financial
Cash flow from operating activities from continuing operations	561.7	537.1	1,598.7	1,272.8
Adjusted funds flow from continuing operations ⁽¹⁾	548.3	548.6	1,728.2	1,440.6
Per share^{(1) (2)}	0.89	1.02	2.79	2.64
Net income from continuing operations	277.2	133.6	139.2	496.8
Per share ⁽²⁾	0.45	0.25	0.22	0.92
Adjusted net earnings from continuing operations ⁽¹⁾	177.0	226.6	601.8	585.8
Per share ^{(1) (2)}	0.29	0.42	0.97	1.08
Weighted average shares outstanding
Basic	616.6	534.3	618.4	542.0
Diluted	617.5	536.9	620.0	544.8
Operating
Average daily production from continuing operations
Crude oil and condensate (bbls/d)	102,373	92,824	108,769	85,372
NGLs (bbls/d)	16,859	16,119	17,656	14,690
Natural gas (mcf/d)	393,582	244,777	393,347	198,796
Production from continuing operations (boe/d)	184,829	149,739	191,983	133,195
Average selling prices from continuing operations ⁽³⁾
Crude oil and condensate ($/bbl)	95.05	104.15	95.65	96.34
NGLs ($/bbl)	34.64	30.81	35.99	33.72
Natural gas ($/mcf)	1.21	2.83	1.97	3.16
Total ($/boe)	58.39	72.50	61.54	70.19
Netback from Continuing Operations ($/boe)
Oil and gas sales	58.39	72.50	61.54	70.19
Royalties	(6.36)	(7.23)	(6.43)	(7.41)
Operating expenses	(13.48)	(15.55)	(13.68)	(15.57)
Transportation expenses	(4.46)	(3.32)	(4.51)	(3.25)
Operating netback ⁽¹⁾	34.09	46.40	36.92	43.96
Realized gain (loss) on commodity derivatives	1.98	(0.36)	0.66	0.36
Other ⁽⁴⁾	(3.83)	(6.22)	(4.73)	(4.70)
Adjusted funds flow from continuing operations netback ⁽¹⁾	32.24	39.82	32.85	39.62
Capital Expenditures
Development capital expenditures from continuing operations ⁽¹⁾	395.9	260.4	1,145.1	568.9

(1)	Specified financial measure that does not have any standardized meaning prescribed by IFRS and, therefore, may not be comparable with the calculation of similar measures presented by other entities. Refer to the Specified Financial Measures section for further information.
(2)	The per share amounts (with the exception of dividends per share) are the per share – diluted amounts.
(3)	The average selling prices reported are before realized derivatives and transportation.
(4)	Other includes net purchased products, general and administrative expenses, interest on long-term debt, foreign exchange, cash-settled share-based compensation and certain cash items and excludes transaction costs, foreign exchange on US dollar long-term debt and certain non-cash items.

Specified Financial Measures

Throughout this press release, the Company uses the terms "total operating netback", "total operating netback from continuing operations", "total netback", "total netback from continuing operations", "operating netback", "netback", "adjusted funds flow from operations" (or "adjusted FFO"), "adjusted funds flow from operations per share - diluted", "adjusted funds flow from continuing operations", "adjusted funds flow from continuing operations per share - diluted", "adjusted funds flow from discontinued operations", "adjusted funds flow from operations netback", "adjusted funds flow from continuing operations netback", "excess cash flow", "base dividends", "total return of capital", "adjusted working capital deficiency", "net debt", "net debt to adjusted funds flow from operations", "adjusted net earnings from operations", "adjusted net earnings from operations per share - diluted", "adjusted net earnings from continuing operations", "adjusted net earnings from continuing operations per share – diluted", "adjusted net earnings from discontinued operations", "development capital expenditures", "development capital expenditures from continuing operations", and "development capital expenditures from discontinued operations". These terms do not have any standardized meaning as prescribed by IFRS and, therefore, may not be comparable with the calculation of similar measures presented by other issuers. For information on the composition of these measures and how the Company uses these measures, refer to the Specified Financial Measures section of the Company's MD&A for the quarter ended September 30, 2024, which section is incorporated herein by reference, and available on SEDAR+ at www.sedarplus.ca and on EDGAR at www.sec.gov/edgar.

Adjusted funds flow from operations netback is a non-GAAP financial ratio and is calculated as adjusted funds flow from operations divided by total production. Adjusted funds flow from operations netback is a common metric used in the oil and gas industry and is used to measure operating results on a per boe basis.

The following table reconciles oil and gas sales to total operating netback from continuing operations, total netback from continuing operations and total adjusted funds flow from continuing operations netback:

	Three months ended September 30			Nine months ended September 30
($ millions)	2024	2023	% Change	2024	2023	% Change
Oil and gas sales	992.9	998.7	(1)	3,237.2	2,552.3	27
Royalties	(108.2)	(99.6)	9	(338.0)	(269.4)	25
Operating expenses	(229.3)	(214.2)	7	(719.8)	(566.0)	27
Transportation expenses	(75.9)	(45.8)	66	(237.4)	(118.3)	101
Total operating netback from continuing operations	579.5	639.1	(9)	1,942.0	1,598.6	21
Realized gain (loss) on commodity derivatives	33.6	(4.9)	(786)	34.7	13.0	167
Total netback from continuing operations	613.1	634.2	(3)	1,976.7	1,611.6	23
Other⁽¹⁾	(64.8)	(85.6)	(24)	(248.5)	(171.0)	45
Total adjusted funds flow from continuing operations netback	548.3	548.6	—	1,728.2	1,440.6	20

(1)	Other includes net purchased products, general and administrative expenses, interest on long-term debt, foreign exchange, cash-settled share-based compensation and certain cash items and excludes transaction costs, foreign exchange on US dollar long-term debt and certain non-cash items.

The following table reconciles cash flow from operating activities to adjusted funds flow from operations and excess cash flow:

	Three months ended September 30			Nine months ended September 30
($ millions)	2024	2023⁽¹⁾	% Change	2024	2023⁽¹⁾	% Change
Cash flow from operating activities	561.7	648.9	(13)	1,598.7	1,584.4	1
Changes in non-cash working capital	(29.3)	27.1	(208)	84.8	136.9	(38)
Transaction costs	1.8	0.3	500	16.0	16.7	(4)
Decommissioning expenditures ⁽²⁾	14.1	10.8	31	28.7	26.6	8
Adjusted funds flow from operations	548.3	687.1	(20)	1,728.2	1,764.6	(2)
Development capital and other expenditures	(404.7)	(351.9)	15	(1,210.3)	(928.4)	30
Payments on principal portion of lease liability	(9.2)	(5.6)	64	(26.6)	(16.2)	64
Decommissioning expenditures	(14.1)	(10.8)	31	(28.7)	(26.6)	8
Unrealized gain (loss) on equity derivative contracts	(6.2)	6.4	(197)	(6.8)	(23.6)	(71)
Transaction costs	(1.8)	(0.3)	500	(16.0)	(16.7)	(4)
Other items ⁽³⁾	1.3	(3.3)	(139)	(2.0)	(0.3)	567
Excess cash flow	113.6	321.6	(65)	437.8	752.8	(42)

(1)	Comparative period revised to reflect current period presentation.
(2)	Excludes amounts received from government grant programs.
(3)	Other items exclude net acquisitions and dispositions.

The following table reconciles cash flow from operating activities from discontinued operations to adjusted funds flow from discontinued operations:

	Three months ended September 30			Nine months ended September 30
($ millions)	2024	2023	% Change	2024	2023	% Change
Cash flow from operating activities from discontinued operations	—	111.8	(100)	—	311.6	(100)
Changes in non-cash working capital	—	26.7	(100)	—	12.4	(100)
Adjusted funds flow from discontinued operations	—	138.5	(100)	—	324.0	(100)

The following tables reconcile cash flow from operating activities and adjusted funds flow from operations from continuing and discontinued operations:

	Three months ended September 30			Nine months ended September 30
($ millions)	2024	2023	% Change	2024	2023	% Change
Cash flow from operating activities from continuing operations	561.7	537.1	5	1,598.7	1,272.8	26
Cash flow from operating activities from discontinued operations	—	111.8	(100)	—	311.6	(100)
Cash flow from operating activities	561.7	648.9	(13)	1,598.7	1,584.4	1

	Three months ended September 30			Nine months ended September 30
($ millions)	2024	2023	% Change	2024	2023	% Change
Adjusted funds flow from continuing operations	548.3	548.6	—	1,728.2	1,440.6	20
Adjusted funds flow from discontinued operations	—	138.5	(100)	—	324.0	(100)
Adjusted funds flow from operations	548.3	687.1	(20)	1,728.2	1,764.6	(2)

Adjusted funds flow from operations per share - diluted is a supplementary financial measure and is calculated as adjusted funds flow from operations divided by the number of weighted average diluted shares outstanding.

The following table reconciles adjusted working capital deficiency:

($ millions)	September 30, 2024	December 31, 2023	% Change
Accounts payable and accrued liabilities	566.0	634.9	(11)
Dividends payable	70.9	56.8	25
Long-term compensation liability ⁽¹⁾	48.1	66.8	(28)
Cash	(8.2)	(17.3)	(53)
Accounts receivable	(323.7)	(377.9)	(14)
Prepaids and deposits	(102.4)	(87.8)	17
Deferred consideration receivable⁽²⁾	(60.3)	(79.2)	(24)
Adjusted working capital deficiency	190.4	196.3	(3)

(1)	Includes current portion of long-term compensation liability and is net of equity derivative contracts.
(2)	Deferred consideration receivable is comprised of $49.5 million included in other current assets and $10.8 million included in other long-term assets (December 31, 2023 - $79.2 million in other current assets and nil in other long-term assets).

The following table reconciles long-term debt to net debt:

($ millions)	September 30, 2024	December 31, 2023	% Change
Long-term debt ⁽¹⁾	2,776.7	3,566.3	(22)
Adjusted working capital deficiency	190.4	196.3	(3)
Unrealized foreign exchange on translation of hedged US dollar long-term debt	(7.7)	(24.5)	(69)
Net debt	2,959.4	3,738.1	(21)

(1)	Includes current portion of long-term debt.

The following table reconciles net income (loss) to adjusted net earnings from operations:

	Three months ended September 30			Nine months ended September 30
($ millions)	2024	2023	% Change	2024	2023	% Change
Net income (loss)	277.2	(809.9)	(134)	126.5	(380.9)	(133)
Amortization of E&E undeveloped land	31.2	11.0	184	90.6	18.9	379
Impairment	—	773.8	(100)	512.3	773.8	(34)
Unrealized derivative (gains) losses	(146.6)	35.4	(514)	11.1	155.5	(93)
Unrealized foreign exchange (gain) loss on translation of hedged US dollar long-term debt	(16.2)	55.9	(129)	(14.6)	(73.2)	(80)
Net (gain) loss on capital dispositions	(0.3)	(0.1)	200	10.4	(4.2)	(348)
Deferred tax adjustments	31.7	249.4	(87)	(134.5)	249.9	(154)
Adjusted net earnings from operations	177.0	315.5	(44)	601.8	739.8	(19)

The following table reconciles net income (loss) from discontinued operations to adjusted net earnings from discontinued operations:

	Three months ended September 30			Nine months ended September 30
($ millions)	2024	2023	% Change	2024	2023	% Change
Net income (loss) from discontinued operations	—	(943.5)	(100)	(12.7)	(877.7)	(99)
Amortization of E&E undeveloped land	—	0.1	(100)	—	0.1	(100)
Impairment	—	728.4	(100)	—	728.4	(100)
Unrealized derivative loss	—	24.0	(100)	—	24.0	(100)
Net loss on capital dispositions	—	—	—	12.7	—	100
Deferred tax adjustments	—	279.9	(100)	—	279.2	(100)
Adjusted net earnings from discontinued operations	—	88.9	(100)	—	154.0	(100)

The following table reconciles adjusted net earnings from continuing and discontinued operations:

	Three months ended September 30			Nine months ended September 30
($ millions)	2024	2023	% Change	2024	2023	% Change
Adjusted net earnings from continuing operations	177.0	226.6	(22)	601.8	585.8	3
Adjusted net earnings from discontinued operations	—	88.9	(100)	—	154.0	(100)
Adjusted net earnings from operations	177.0	315.5	(44)	601.8	739.8	(19)

The following table reconciles development capital and other expenditures to development capital expenditures:

	Three months ended September 30			Nine months ended September 30
($ millions)	2024	2023	% Change	2024	2023	% Change
Development capital and other expenditures	404.7	351.9	15	1,210.3	928.4	30
Payments on drilling rig lease liabilities	3.3	—	100	9.6	—	100
Land expenditures	(1.1)	(23.0)	(95)	(36.2)	(31.4)	15
Capitalized administration ⁽¹⁾	(9.9)	(11.9)	(17)	(34.9)	(33.4)	4
Corporate assets	(1.1)	(1.5)	(27)	(3.7)	(3.8)	(3)
Development capital expenditures	395.9	315.5	25	1,145.1	859.8	33

(1)	Capitalized administration excludes capitalized equity-settled SBC.

The following table reconciles development capital expenditures from continuing and discontinued operations:

	Three months ended September 30			Nine months ended September 30
($ millions)	2024	2023	% Change	2024	2023	% Change
Development capital expenditures from continuing operations	395.9	260.4	52	1,145.1	568.9	101
Development capital expenditures from discontinued operations	—	55.1	(100)	—	290.9	(100)
Development capital expenditures	395.9	315.5	25	1,145.1	859.8	33

Total return of capital is a supplementary financial measure and is comprised of base dividends, special dividends and share repurchases, adjusted for the timing of special dividend payments.

Excess cash flow for 2024 is a forward-looking non-GAAP measures and is calculated consistently with the measures disclosed in the Company's MD&A. Refer to the Specified Financial Measures section of the Company's MD&A for the three and nine months ended September 30, 2024.

Management believes the presentation of the specified financial measures above provide useful information to investors and shareholders as the measures provide increased transparency and the ability to better analyze performance against prior periods on a comparable basis.

Notice to US Readers

All amounts in the news release are stated in Canadian dollars unless otherwise specified.

Forward-Looking Statements

Any "financial outlook" or "future oriented financial information" in this press release, as defined by applicable securities legislation has been approved by management of Veren. Such financial outlook or future oriented financial information is provided for the purpose of providing information about management's current expectations and plans relating to the future. Readers are cautioned that reliance on such information may not be appropriate for other purposes.

Certain statements contained in this press release constitute "forward-looking statements" within the meaning of section 27A of the Securities Act of 1933 and section 21E of the Securities Exchange Act of 1934 and "forward-looking information" for the purposes of Canadian securities regulation (collectively, "forward-looking statements"). The Company has tried to identify such forward-looking statements by use of such words as "could", "should", "can", "anticipate", "expect", "believe", "will", "may", "intend", "projected", "sustain", "continues", "strategy", "potential", "projects", "grow", "take advantage", "estimate", "well-positioned" and other similar expressions, but these words are not the exclusive means of identifying such statements.

In particular, this press release contains forward-looking statements pertaining, among other things, to the following: expected 2024 excess cash flow, year-end 2024 net debt and net debt to funds flow at the commodity prices specified; disciplined and returns-focused budget for 2025 expected to generate excess cash flow as specified herein; 2024 debt reduction; quality of resources and excess cash flow deliverability of the Kaybob Duvernay and Alberta Montney; further productivity in the Kaybob Duvernay and Alberta Montney; 2025 budget and five-year plan expected to generate significant excess cash flow and returns for shareholders; extent and benefits of hedging; diversification of pricing exposure; return of capital commitments; return of capital outlook, percentage of annual excess cash flow to be returned to shareholders and methods thereof; incremental capital to implement several previously identified facilities projects to improve infrastructure and reduce future downtime in the Alberta Montney; expectations of the P&P and SPE completions designs; timing to bring on stream three multi-well pads in the Karr area using SPE design; using the SPE completions design moving forward; bringing on Alberta Montney seven well pad in early 2025; expanded capacity in its facility in the Alberta Montney in fourth quarter 2024 and benefits and capabilities thereof; drilling locations in Gold Creek West; timing to bring on stream additional delineation wells in the Kaybob Duvernay; timing for additional OHML wells to come on stream and benefits thereof; Veren's priorities; Veren's 2025 guidance; Veren's 2024 and 2025 production (including oil and liquids percentages) and development capital expenditures guidance (and components thereof); and other information for Veren's 2024 and 2025 guidance, including capitalized administration, annual operating expenses and royalties; 2025 budget allocation by area and and area attributes, expectations and focuses; capital allocated to long-term projects; five-year plan production forecast by 2029 (and drivers thereof) and expected cumulative after-tax excess cash flow at the commodity prices specified; expected excess cash flow per share growth under the five-year plan; 2024 and 2025 outlook; 2025 budget excess cash generation at the commodity prices specified; 2025 budget allowing for significant returns to shareholders and further strengthening the balance sheet; return of capital outlook, including base dividend, and the additional return of capital targeted as a percentage of excess cash flow; plans to increase the percentage of excess cash flow returned to shareholders as it further reduces debt; portion of excess cash flow directed to debt repayment; strong balance sheet, ample liquidity, access to investment-grade institutional debt market and active hedging program; 2025 budget characteristics and responsiveness; flexibility in overall capital budget and allocation in response to commodity prices; and that the Company will continue to prioritize operational execution, strengthening and optimizing its balance sheet and increasing its return of capital to shareholders.

Statements relating to "reserves" are also deemed to be forward-looking statements, 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. Actual reserve values may be greater than or less than the estimates provided herein.

Unless otherwise noted, reserves referenced herein are given as at December 31, 2023. Also, estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates and future net revenue for all properties due to the effect of aggregation. All required reserve information for the Company is contained in its Annual Information Form for the year ended December 31, 2023, which is accessible at www.sedarplus.ca.

With respect to disclosure contained herein regarding resources other than reserves, there is uncertainty that it will be commercially viable to produce any portion of the resources and there is significant uncertainty regarding the ultimate recoverability of such resources.

All forward-looking statements are based on Veren's beliefs and assumptions based on information available at the time the assumption was made. Veren believes that the expectations reflected in these forward-looking statements are reasonable but no assurance can be given that these expectations will prove to be correct and such forward-looking statements included in this report should not be unduly relied upon. By their nature, such forward-looking statements are subject to a number of risks, uncertainties and assumptions, which could cause actual results or other expectations to differ materially from those anticipated, expressed or implied by such statements, including those material risks discussed in the Company's Annual Information Form for the year ended December 31, 2023 under "Risk Factors" and our Management's Discussion and Analysis for the year ended December 31, 2023, under the headings "Risk Factors" and "Forward-Looking Information" and for the three and nine months ended September 30, 2024, under the headings "Risk Factors" and "Forward-Looking Information". The material assumptions are disclosed in the Management's Discussion and Analysis for the year ended December 31, 2023, under the headings "Capital Expenditures", "Liquidity and Capital Resources", "Critical Accounting Estimates", "Risk Factors" and "Changes in Accounting Policies" and in the Management's Discussion and Analysis for the three and nine months ended September 30, 2024, under the headings "Overview", "Commodity Derivatives", "Liquidity and Capital Resources", "Guidance", "Royalties" and "Operating Expenses". In addition, risk factors include: financial risk of marketing reserves at an acceptable price given market conditions; volatility in market prices for oil and natural gas, decisions or actions of OPEC and non-OPEC countries in respect of supplies of oil and gas; delays in business operations or delivery of services due to pipeline restrictions, rail blockades, outbreaks, pandemics, and blowouts; the risk of carrying out operations with minimal environmental impact; industry conditions including changes in laws and regulations including the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced; uncertainties associated with estimating oil and natural gas reserves; risks and uncertainties related to oil and gas interests and operations on Indigenous lands; economic risk of finding and producing reserves at a reasonable cost; uncertainties associated with partner plans and approvals; operational matters related to non-operated properties; increased competition for, among other things, capital, acquisitions of reserves and undeveloped lands; competition for and availability of qualified personnel or management; incorrect assessments of the value and likelihood of acquisitions and dispositions, and exploration and development programs; unexpected geological, technical, drilling, construction, processing and transportation problems; the impacts of drought, wildfires and severe weather events; availability of insurance; fluctuations in foreign exchange and interest rates; stock market volatility; general economic, market and business conditions, including uncertainty in the demand for oil and gas and economic activity in general; changes in interest rates and inflation; uncertainties associated with regulatory approvals; geopolitical conflicts, including the Russian invasion of Ukraine and conflict in the Middle East; uncertainty of government policy changes; the impact of the implementation of the Canada-United States-Mexico Agreement; uncertainty regarding the benefits and costs of dispositions; failure to complete acquisitions and dispositions; uncertainties associated with credit facilities and counterparty credit risk; and changes in income tax laws, tax laws, crown royalty rates and incentive programs relating to the oil and gas industry; and other factors, many of which are outside the control of the Company. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these are interdependent and Veren's future course of action depends on management's assessment of all information available at the relevant time.

Included in this press release are Veren's 2024 and 2025 guidance in respect of capital expenditures and average annual production which is based on various assumptions as to production levels, commodity prices and other assumptions and are subject to a variety of contingencies. The Company's return of capital framework is based on certain facts, expectations and assumptions that may change and, therefore, this framework may be amended as circumstances necessitate or require. To the extent such estimates constitute a "financial outlook" or "future oriented financial information" in this press release, as defined by applicable securities legislation, such information has been approved by management of Veren. Such financial outlook or future oriented financial information is provided for the purpose of providing information about management's current expectations and plans relating to the future. Readers are cautioned that reliance on such information may not be appropriate for other purposes.

Additional information on these and other factors that could affect Veren's operations or financial results are included in Veren's reports on file with Canadian and U.S. securities regulatory authorities. Readers are cautioned not to place undue reliance on this forward-looking information, which is given as of the date it is expressed herein. Veren undertakes no obligation to update publicly or revise any forward-looking statements, whether as a result of new information, future events or otherwise, unless required to do so pursuant to applicable law. All subsequent forward-looking statements, whether written or oral, attributable to Veren or persons acting on the Company's behalf are expressly qualified in their entirety by these cautionary statements.

Product Type Production Information

The Company's annual aggregate production for the three and nine months ended September 30, 2024 and September 30, 2023 and the references to "natural gas", "crude oil" and "condensate" reported in this Press Release consist of the following product types, as defined in NI 51-101 and using a conversion ratio of 6 mcf : 1 bbl where applicable:

	Three months ended September 30		Nine months ended September 30
	2024	2023	2024	2023
Light & Medium Crude Oil (bbl/d)	7,062	12,405	9,374	12,823
Heavy Crude Oil (bbl/d)	—	3,617	2,154	3,826
Tight Oil (bbl/d)	67,262	54,605	70,873	47,461
Total Crude Oil (bbl/d)	74,324	70,627	82,401	64,110

NGLs (bbl/d)	44,908	38,316	44,024	35,952

Shale Gas (mcf/d)	390,322	232,235	388,887	188,243
Conventional Natural Gas (mcf/d)	3,260	12,542	4,460	10,553
Total Natural Gas (mcf/d)	393,582	244,777	393,347	198,796

Total production from continuing operations (boe/d)	184,829	149,739	191,983	133,195

	Three months ended September 30		Nine months ended September 30
	2024	2023	2024	2023
Light & Medium Crude Oil (bbl/d)	7,062	12,405	9,374	12,823
Heavy Crude Oil (bbl/d)	—	3,617	2,154	3,826
Tight Oil (bbl/d)	67,262	75,882	70,873	64,376
Total Crude Oil (bbl/d)	74,324	91,904	82,401	81,025

NGLs (bbl/d)	44,908	44,728	44,024	41,588

Shale Gas (mcf/d)	390,322	251,152	388,887	204,459
Conventional Natural Gas (mcf/d)	3,260	12,542	4,460	10,553
Total Natural Gas (mcf/d)	393,582	263,694	393,347	215,012

Total average daily production (boe/d)	184,829	180,581	191,983	158,448

NI 51-101 includes condensate within the natural gas liquids (NGLs) product type. The Company has disclosed condensate as combined with crude oil and/or separately from other natural gas liquids in this press release since the price of condensate as compared to other natural gas liquids is currently significantly higher and the Company believes that this crude oil and condensate presentation provides a more accurate description of its operations and results therefore.

Two multi-well pads recently bought on stream in the Gold Creek area of the Alberta Montney, with average peak 30-day rates between 600 to 900 boe/d per well, consisted of 60% light crude oil, 10% NGLs and 30% shale gas.

The Company's prior wells in the eastern portion of its Gold Creek area, which were brought on stream in 2023 and completed using the SPE design, produced average peak 30-day rates 1,200 boe/d per well with product types of 50% light crude oil, 10% NGLs and 40% shale gas.

In the Karr area of the Alberta Montney, the Company has brought on stream two multi-well pads to-date which have generated average peak 30-day rates between 1,000 to 1,300 boe/d per well with product types of 60% to 75% light crude oil, 5% NGLs and 20% to 35% shale gas.

Wells within the Company's most recent Gold Creek West pad originally brought on stream in first quarter 2024 had the following peak 30-day rate product types: 79% light crude oil, 3% NGLs and 18% shale gas, with average cumulative production of 450,000 boe per well over the first nine months having product types consisting of 70% light crude oil, 5% NGLs and 25% shale gas.

In the Kaybob Duvernay, Veren brought three pads on stream in the Volatile Oil window during third quarter with average product types of 70% condensate, 5% NGLs and 25% shale gas.

Reserves and Drilling Data

The reserves information contained in this press release has been prepared in accordance with NI 51-101.

Where applicable, a barrels of oil equivalent ("boe") conversion rate of six thousand cubic feet of natural gas to one barrel of oil equivalent (6mcf:1bbl) has been used based on an energy equivalent conversion method primarily applicable at the burner tip. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different than the energy equivalency of the 6:1 conversion ratio, utilizing the 6:1 conversion ratio may be misleading as an indication of value.

This press release contains metrics commonly used in the oil and natural gas industry, including "netbacks". 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. Readers are cautioned as to the reliability of oil and gas metrics used in this press release.

Netback is calculated on a per boe basis as oil and gas sales, less royalties, operating and transportation expenses and realized derivative gains and losses. Netback is used by management to measure operating results on a per boe basis to better analyze performance against prior periods on a comparable basis.

There are numerous uncertainties inherent in estimating quantities of crude oil, natural gas and NGLs reserves and the future cash flows attributed to such reserves. The reserve and associated cash flow information set forth above are estimates only. In general, estimates of economically recoverable crude oil, natural gas and NGLs reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially. For these reasons, estimates of the economically recoverable crude oil, NGLs and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues associated with reserves prepared by different engineers, or by the same engineers at different times, may vary. The Company's actual production, revenues, taxes and development and operating expenditures with respect to its reserves will vary from estimates thereof and such variations could be material.

Initial production is for a limited time frame only (30 or 180 days) and may not be indicative of future performance. Peak IP30 refers the 30 consecutive days with the highest production rates since a pad has come on production and may not be indicative of future performance. Individual properties may not reflect the same confidence level as estimates of reserves for all properties due to the effects of aggregation. This press release contains estimates of the net present value of the Company's future net revenue from our reserves. Such amounts do not represent the fair market value of our reserves. The recovery and reserve estimates of the Company's reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered.

This press release discloses in the Gold Creek West region, 310 potential internally identified net drilling locations, of which 37 are proved plus probable locations as assigned in the company's year end 2023 independent reserves evaluation in accordance with NI 51-101 and the COGE Handbook, and an incremental 273 are unbooked locations. The Company's ability to drill and develop new locations and the drilling locations on which the Company actually drills wells depends on a number of uncertainties and factors, including, but not limited to, the availability of capital, equipment and personnel, oil and natural gas prices, costs, inclement weather, seasonal restrictions, drilling results, additional geological, geophysical and reservoir information that is obtained, production rate recovery, gathering system and transportation constraints, the net price received for commodities produced, regulatory approvals and regulatory changes. As a result of these uncertainties, there can be no assurance that the potential future drilling locations that the Company has identified will ever be drilled and, if drilled, that such locations will result in additional crude oil, natural gas or NGLs produced. As such, the Company's actual drilling activities may differ materially from those presently identified, which could adversely affect the company's business.

The reserve data provided in this news release presents only a portion of the disclosure required under National Instrument 51-101. All of the required information is contained in the Company's Annual Information Form for the year ended December 31, 2023, on SEDAR+ (accessible at www.sedarplus.ca and EDGAR (accessible at www.sec.gov/edgar.shtml) and further supplemented by Material Change Reports as applicable.

FOR MORE INFORMATION ON VEREN, PLEASE CONTACT:

Sarfraz Somani, Manager, Investor Relations

Telephone: (403) 693-0020 Toll-free (US and Canada): 888-693-0020

Address: Veren Inc. Suite 2000, 585 - 8th Avenue S.W. Calgary AB T2P 1G1

www.vrn.com

Veren shares are traded on the Toronto Stock Exchange and New York Stock Exchange under the symbol VRN.

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SOURCE Veren Inc.

Veren Announces Q3 2024 Results & Updated Outlook