SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
F O R M 6-K
REPORT OF FOREIGN PRIVATE ISSUER PURSUANT
TO RULE 13a-16 OR 15d-16 UNDER THE
SECURITIES EXCHANGE ACT OF 1934
For the month of
October 2024
Commission File Number 001-36258
Veren Inc.
(Name of Registrant)
Suite 2000,
585-8th Avenue S.W.
Calgary, Alberta, T2P 1G1
(Address of Principal Executive Office)
Indicate by check mark whether the registrant files or
will file annual reports under cover of Form 20-F or Form 40-F.
Form
20-F ☐ Form
40-F ☒
_______
DOCUMENTS FILED AS PART OF THIS FORM 6-K:
|
Exhibit No.
99.1 |
Description
News Release dated October 31, 2024 |
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act
of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| |
Veren Inc. |
|
| |
(Registrant) |
|
| |
|
|
|
| |
By: |
/s/ Ken Lamont |
|
| |
Name: |
Ken Lamont |
|
| |
Title: |
Chief Financial Officer |
Date: October 31, 2024
EXHIBITS
Exhibit 99.1
Veren Announces Q3 2024 Results & Updated
Outlook
CALGARY, AB, Oct. 31, 2024 /CNW/ - 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% |
| 1) |
Revised total annual average production (boe/d) is comprised of approximately 65% Oil, Condensate & NGLs and 35% Natural Gas |
| 2) |
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% |
| 1) |
Total annual average production (boe/d) is comprised of approximately 65% Oil, Condensate & NGLs and 35% Natural Gas |
| 2) |
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.
View original content:https://www.prnewswire.com/news-releases/veren-announces-q3-2024-results--updated-outlook-302292290.html
SOURCE Veren Inc.
View original content: http://www.newswire.ca/en/releases/archive/October2024/31/c7396.html
%CIK: 0001545851
CO: Veren Inc.
CNW 06:30e 31-OCT-24
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