WHITECAP RESOURCES INC. ANNOUNCES 2023 RESULTS AND RESERVES, OPERATIONS UPDATE AND UPDATED 2024 GUIDANCE
Selected financial and operating information is outlined below and should be read with Whitecap's audited annual consolidated financial statements and related management's discussion and analysis for the three months and year ended
Financial ($ millions except for share amounts and percentages) |
Three months ended |
Year ended |
||
2023 |
2022 |
2023 |
2022 |
|
Petroleum and natural gas revenues |
914.1 |
1,116.5 |
3,551.6 |
4,452.9 |
Net income |
298.3 |
318.7 |
889.0 |
1,676.1 |
Basic ($/share) |
0.49 |
0.52 |
1.47 |
2.72 |
Diluted ($/share) |
0.49 |
0.52 |
1.46 |
2.70 |
Funds flow 1 |
462.3 |
593.6 |
1,791.4 |
2,322.8 |
Basic ($/share) 1 |
0.77 |
0.97 |
2.96 |
3.77 |
Diluted ($/share) 1 |
0.76 |
0.97 |
2.94 |
3.74 |
Dividends declared |
109.6 |
67.2 |
372.8 |
237.2 |
Per share |
0.18 |
0.11 |
0.62 |
0.39 |
Expenditures on property, plant and equipment 2 |
200.5 |
179.0 |
953.8 |
686.5 |
Free funds flow 1 |
261.8 |
414.6 |
837.6 |
1,636.3 |
Net Debt 1 |
1,385.5 |
1,913.1 |
1,385.5 |
1,913.1 |
Operating |
|
|
|
|
Average daily production |
|
|
|
|
Crude oil (bbls/d) |
88,687 |
91,812 |
85,718 |
86,417 |
NGLs (bbls/d) |
19,241 |
17,473 |
17,296 |
15,521 |
Natural gas (Mcf/d) |
351,757 |
342,640 |
320,922 |
254,708 |
Total (boe/d) 3 |
166,554 |
166,392 |
156,501 |
144,389 |
Average realized Price 1,4 |
|
|
|
|
Crude oil ($/bbl) |
93.98 |
102.50 |
95.05 |
114.68 |
NGLs ($/bbl) |
37.85 |
46.84 |
38.90 |
55.30 |
Natural gas ($/Mcf) |
2.48 |
5.56 |
2.84 |
5.62 |
Petroleum and natural gas revenues ($/boe) 1 |
59.66 |
72.94 |
62.17 |
84.49 |
Operating Netback ($/boe) 1 |
|
|
|
|
Petroleum and natural gas revenues1 |
59.66 |
72.94 |
62.17 |
84.49 |
Tariffs 1 |
(0.42) |
(0.49) |
(0.49) |
(0.46) |
Processing & other income 1 |
0.80 |
0.77 |
0.87 |
0.68 |
Marketing revenues 1 |
4.57 |
5.93 |
4.82 |
5.99 |
Petroleum and natural gas sales 1 |
64.61 |
79.15 |
67.37 |
90.70 |
Realized gain/(loss) on commodity contracts 1 |
(0.14) |
(1.43) |
0.34 |
(4.66) |
Royalties 1 |
(10.66) |
(13.34) |
(10.83) |
(16.35) |
Operating expenses 1 |
(13.41) |
(14.13) |
(14.10) |
(14.54) |
Transportation expenses 1 |
(2.09) |
(2.12) |
(2.17) |
(2.18) |
Marketing expenses 1 |
(4.54) |
(5.87) |
(4.79) |
(5.94) |
Operating netbacks |
33.77 |
42.26 |
35.82 |
47.03 |
Share information (millions) |
|
|
|
|
Common shares outstanding, end of period |
598.0 |
608.7 |
598.0 |
608.7 |
Weighted average basic shares outstanding |
603.2 |
610.8 |
605.1 |
616.5 |
Weighted average diluted shares outstanding |
607.3 |
613.8 |
608.6 |
621.1 |
2023 was a strong year for Whitecap both operationally and financially, highlighted by 11% production per share growth5 and the achievement of our second of two net debt milestones, prompting a 26% increase to our base dividend. The ongoing development of our high-quality drilling inventory has yielded exceptional results, with our team constantly evaluating options to further improve capital efficiencies and netbacks for increased profitability.
Average 2023 production of 156,501 boe/d, including 103,014 bbls/d of light oil and liquids and 320,922 mcf/d of natural gas, generated funds flow of
We are also pleased to report exceptional 2023 reserve values highlighted by per share organic growth across all three reserve categories. These organic growth additions resulted in proved developed producing ("PDP") and total proven ("TP") production replacement1 of 107% and 141%, respectively, and reflect our strong 2023 drilling program. Three-year average finding and development ("F&D") recycle ratios1 between 2.6 times and 3.3 times highlight the robust profitability of our asset base through commodity price cycles.
Our balance sheet remains a priority for us and is in excellent condition with less than
Near the end of the fourth quarter, we completed a tuck-in acquisition of light oil Viking assets in one of our core areas in
We provide the following fourth quarter and full year 2023 financial and operating highlights:
-
Funds Flow. Full year and fourth quarter funds flow netbacks1 of
$31.36 per boe and$30.16 per boe, respectively, were strong despite average 2023 WTI crude oil prices being 18% lower and natural gas prices being 50% lower than in 2022. Operating costs of$14.10 per boe were down 3% from 2022, despite inflationary pressures persisting through the year. Full year funds flow of$1.8 billion equates to$2.94 per share, while fourth quarter funds flow of$462 million equates to$0.76 per share. -
Drilling Program. We were the fourth most active driller in
Western Canada in 2023, drilling 215 (189.0 net) wells, including 181 (158.2 net) wells in our East Division and 34 (30.8 net) wells in our West Division. Of the$954 million of capital expenditures incurred in 2023, 80% was allocated to drilling and completions, while 17% was directed to facilities spending, including initial work on our Musreau battery to supportMontney production additions in 2024 as well as an expansion to our 3-27 facility supporting regionalMontney andCharlie Lake development in the Peace River Arch. -
Increasing Return of Capital. We increased our dividend for the seventh time in three years to
$0.73 per share annually inOctober 2023 . We have been focused on delivering a strong return of capital to shareholders since paying our first dividend at the start of 2013, returning a total of$1.8 billion in dividends over the past eleven years. These returns have been further enhanced by repurchasing over 76 million shares for$612 million since 2017. Total return to shareholders of approximately$500 million in 2023 demonstrates a continuation of this strategy. -
Balance Sheet Strength. Year end net debt of
$1.4 billion equated to a debt to EBITDA ratio of 0.7 times and an EBITDA to interest expense ratio6 of 27.0 times, both well within our debt covenants of not greater than 4.0 times and not less than 3.5 times, respectively. We have significant financial flexibility with over$1.7 billion of available capacity on$3.1 billion of total credit capacity.
West Division
We continue to advance operations in our West Division including a buildout of new facilities and infrastructure to handle our production growth into the future. We are looking forward to our next stage of
At Kakwa, we are encouraged by strong initial results on our two most recent
Although early, we are encouraged by the initial results of these two pads and application of this well design and spacing strategy may be transferable to other areas of future
We also spud our first two 4-well pads (8.0 net wells) at Musreau in the fourth quarter, which are expected to be completed and ready to be brought on production upon completion of our 20,000 boe/d battery. The ramp up of production into this facility will occur during the second quarter, and we target facility capacity being reached as our third and fourth 4-well pads (8.0 net wells) are brought on production at Musreau later this year.
At Lator, we recently drilled a 2-well (2.0 net) pad as part of our validation and delineation efforts of this future area of
With respect to our
As part of the execution of our 2024 capital spending program and long-range planning scenarios, we have an active water management strategy to mitigate impacts of potential drought conditions in
East Division
2023 was a very strong operational year for our East Division with outperformance across all four regions. We drilled 181 (158.2 net) wells during the year, which included 151 (134.9 net) light oil wells into the Cardium,
In
Our
The profitability of our
We have also recently started CO2 injection at a pilot CO2 flood into the
In
Operational success and a deep set of highly economic inventory has resulted in strong year end reserve values. We continue to see the benefits of our consolidation strategy that began in late-2020 as greater scale and asset optimization opportunities have yielded consistent per share growth and increasing net present values.
One of the benefits of consolidating acreage has been an ability to drill longer laterals in areas that were previously restricted by ownership boundaries. In addition, we are consistently expanding the applicability of increased lateral lengths to greater portions of our asset base, giving potential for improved capital efficiencies and, therefore, increased profitability. At year end, we have identified 6,400 drilling locations9 in inventory which provides for over 25 years of sustainable and profitable growth.
We highlight the following 2023 year end reserve report results:
- Per Share Focus. Debt-adjusted reserves per share10 increased 6% on a PDP basis, 10% on a TP basis and 7% on a total proven plus probable ("TPP") basis despite net dispositions decreasing total reserves. Our focus on per share metrics along with strong return on capital execution will maximize long-term profits for our shareholders.
-
Production Replacement. Prior to the impact of net dispositions, we replaced 107% of production on a PDP basis, 141% of production on a TP basis and 107% of production on a
TPP basis. Strong operational execution along with a prolific asset base provide for increased sustainability over the long term. - Long-Dated Inventory. We have significant inventory life across all our assets, with a PDP reserve life index11 ("RLI") of 6 years, a TP RLI of 13 years, and a TPP RLI of 19 years. These are consistent with the three-year average and are reflective of the expansive opportunity we have to develop these assets over time.
-
Strong Recycle Ratios. Our PDP F&D1 cost of
$14.68 per boe, our TP F&D cost of$17.62 per boe and our TPP F&D cost of$20.46 per boe resulted in strong recycle ratios of 2.4 times, 2.0 times and 1.8 times, respectively. The three-year average F&D recycle ratios range from 2.6 times to 3.3 times, which emphasizes our strong asset base and our focus on long-term profitability.
We have increased our 2024 average production guidance range to 165,000 – 170,000 boe/d (8% production per share growth) to reflect the Viking tuck-in acquisition along with the reduction in capital spending. Our capital budget is now expected to be
WTI crude oil prices continue to be relatively volatile but have been rangebound between
Natural gas prices are currently challenged with the lack of winter demand resulting in weak AECO prices forecasted through to the end of the summer, and a seasonal increase into next winter is anticipated. While the liquids component of our unconventional assets currently drives the economics, our growth in natural gas volumes is anticipated to coincide with the commissioning of LNG Canada in 2025. Completion of this facility is an important step for
At current strip prices12, we are forecasting 2024 funds flow of approximately
Our long term organic corporate growth outlook has been updated and increased to 210,000 boe/d by the end of 2028, which represents average organic growth of 5% on an annual basis, driven primarily by our liquids rich
We would like to emphasize that our objective is to provide sustainable and profitable growth to our shareholders, including a disciplined level of debt, while remaining committed to responsible development of our assets. Our strategy includes advancing our emission reduction strategy and utilizing our expertise in carbon sequestration.
On behalf of our employees, management team and Board of Directors, we would like to thank our shareholders for their support and look forward to an exciting 2024 and beyond.
NOTES
1 |
Funds flow, funds flow basic ($/share), funds flow diluted ($/share) and net debt are capital management measures. Average realized price and per boe disclosure figures are supplementary financial measures. Operating netback and free funds flow are non-GAAP financial measures. Operating netbacks ($/boe), F&D costs, funds flow netbacks ($/boe), free funds flow diluted ($/share) and recycle ratio are non-GAAP ratios. Refer to the Specified Financial Measures section in this press release for additional disclosure and assumptions. |
2 |
Also referred to herein as "capital expenditures", "capital investment" and "capital spending". |
3 |
Disclosure of production on a per boe basis in this press release consists of the constituent product types and their respective quantities disclosed herein. Refer to Barrel of Oil Equivalency and Production, Initial Production Rates and Product Type Information in this press release for additional disclosure. |
4 |
Prior to the impact of risk management activities and tariffs. |
5 |
Production per share is the Company's total crude oil, NGL and natural gas production volumes for the applicable period divided by the weighted average number of diluted shares outstanding for the applicable period. Production per share growth is determined in comparison to the applicable comparative period. |
6 |
Debt to EBITDA ratio and EBITDA to interest expense ratio are specified financial measures that are calculated in accordance with the financial covenants in our credit agreement. |
7 |
Also referred to herein as "half-cycle payout". Refer to Oil and Gas Metrics in this press release for additional disclosure. |
8 |
Also referred to herein as "operating netback". |
9 |
Disclosure of drilling locations in this press release consists of proved, probable, and unbooked locations and their respective quantities on a gross and net basis as disclosed herein. Refer to Drilling Locations in this press release for additional disclosure. |
10 |
"Debt-adjusted reserves per share" is calculated as year end reserves divided by year end fully diluted shares plus the annual change in net debt divided by the average annual share price. Debt-adjusted reserves per share growth is determined in comparison to the yar end reserves divided by year end fully diluted shares from the applicable comparative period. |
11 |
See "Production Replacement Ratio and Reserve Life Index". |
12 |
Based on the following strip commodity pricing and exchange rate assumptions for 2024: |
Our 2023-year end reserves were evaluated by independent reserves evaluator
Reserves included are Company share (gross) reserves which are the Company's total working interest reserves before the deduction of any royalties and including any royalty interests payable to the Company. Additional reserve information as required under NI 51-101 will be included in our Annual Information Form which will be filed on SEDAR+ at www.sedarplus.ca. The numbers in the tables below may not add due to rounding.
Reserves as at
|
Company Share (Gross) Reserves |
||
Description |
Light & Medium Oil (Mbbl) |
Tight Crude Oil (Mbbl) |
Conventional Natural Gas (MMcf) |
Proved developed producing |
201,566 |
737 |
318,561 |
Proved developed non-producing |
2,313 |
0 |
7,271 |
Proved undeveloped |
102,255 |
8,664 |
162,792 |
Total proved |
306,134 |
9,401 |
488,624 |
Probable |
108,069 |
8,000 |
196,423 |
Total proved plus probable |
414,203 |
17,400 |
685,046 |
Description |
|
Natural Gas Liquids (Mbbl) |
Total (Mboe) |
Proved developed producing |
319,542 |
51,755 |
360,409 |
Proved developed non-producing |
30,901 |
7,553 |
16,228 |
Proved undeveloped |
997,087 |
111,426 |
415,658 |
Total proved |
1,347,530 |
170,734 |
792,294 |
Probable |
869,388 |
84,194 |
377,897 |
Total proved plus probable |
2,216,918 |
254,927 |
1,170,191 |
Summary of Before Tax Net Present Values of Future Net Revenue (Forecast Pricing)
As at
|
Before Tax Net Present Value ($ millions) (1) |
||||
|
Discount Rate |
||||
Reserves Category |
0 % |
5 % |
10 % |
15 % |
20 % |
Proved Developed Producing |
8,052 |
6,765 |
5,593 |
4,779 |
4,201 |
Proved developed non-producing |
487 |
386 |
324 |
283 |
252 |
Proved undeveloped |
9,144 |
6,000 |
4,168 |
3,007 |
2,223 |
Total Proved |
17,683 |
13,151 |
10,085 |
8,068 |
6,676 |
Total Probable |
11,773 |
6,611 |
4,334 |
3,112 |
2,373 |
Total Proved + Probable |
29,456 |
19,762 |
14,419 |
11,180 |
9,049 |
(1) |
Includes abandonment and reclamation costs as defined in NI 51-101 for all of our facilities, pipelines and wells including those without reserves assigned. |
FDC reflects the best estimate of the capital cost to develop and produce reserves. FDC associated with our TP reserves at year end 2023 is
Also included in FDC are 1,590 (1,374 net) proved booked drilling locations and 323 (271 net) probable booked drilling locations.
($ millions) |
Total Proved |
Total Proved plus Probable |
2024 |
999 |
1,024 |
2025 |
1,206 |
1,244 |
2026 |
1,218 |
1,341 |
2027 |
1,154 |
1,269 |
2028 |
1,112 |
1,331 |
Remainder |
954 |
2,160 |
Total FDC, Undiscounted |
6,641 |
8,370 |
Total FDC, Discounted at 10% |
4,856 |
5,857 |
The following table highlights F&D and FD&A costs and associated recycle ratios, including FDC, based on the evaluation of our petroleum and natural gas reserves prepared by McDaniel:
|
2023 |
2022 |
2021 |
Three Year Weighted Average |
Proved Developed Producing |
|
|
|
|
F&D costs per boe (1) |
|
|
|
|
F&D recycle ratio (2) |
2.4x |
3.6x |
1.8x |
2.6x |
FD&A costs per boe (3) |
|
|
|
|
FD&A recycle ratio (2) |
2.1x |
2.0x |
2.6x |
2.2x |
Total Proved |
|
|
|
|
F&D costs per boe (1) |
|
|
|
|
F&D recycle ratio (2) |
2.0x |
2.8x |
5.9x |
3.3x |
FD&A costs per boe (3) |
|
|
|
|
FD&A recycle ratio (2) |
1.6x |
3.1x |
2.6x |
2.4x |
Total Proved Plus Probable |
|
|
|
|
F&D costs per boe (1) |
|
|
|
|
F&D recycle ratio (2) |
1.8x |
2.4x |
6.4x |
3.2x |
FD&A costs per boe (3) (4) |
nm |
|
|
nm |
FD&A recycle ratio (2) (4) |
nm |
4.1x |
3.1x |
nm |
(1) |
F&D costs are non-GAAP ratios and are calculated as the sum of development capital of |
(2) |
Recycle ratio is a non-GAAP ratio and is calculated as operating netback divided by F&D or FD&A costs. Our operating netback in 2023 was |
(3) |
FD&A costs are non-GAAP ratios and are calculated as the sum of development capital of |
(4) |
The impact of net dispositions in 2023 results in a very low denominator value and therefore the 2023 FD&A cost of |
The following table highlights our production replacement ratio and reserve life index ("RLI") based on the evaluation of our petroleum and natural gas reserves prepared by McDaniel, including the impact of net dispositions in 2023:
In 2023, prior to the impact of net dispositions, we replaced 107% of production on a PDP reserves basis, 141% of production on a TP reserves basis and 107% of production on a
|
2023 |
2022 |
2021 |
Three Year Weighted Average |
Proved Developed Producing |
|
|
|
|
Production replacement (1) |
71 % |
208 % |
372 % |
211 % |
RLI (years) (2) |
5.9 |
6.2 |
7.3 |
6.4 |
Total Proved |
|
|
|
|
Production replacement (1) |
80 % |
589 % |
545 % |
389 % |
RLI (years) (2) |
13.0 |
13.2 |
12.5 |
12.9 |
Total Proved Plus Probable |
|
|
|
|
Production replacement (1) |
16 % |
952 % |
737 % |
553 % |
RLI (years) (2) |
19.1 |
20.1 |
17.6 |
19.1D |
(1) |
Production replacement ratio is calculated as total reserve additions (including acquisitions net of dispositions) divided by annual production. Whitecap's production averaged 156,501 boe/d in 2023. |
(2) |
RLI is calculated as total Company share reserves divided by the annualized fourth quarter actual production of 166,554 boe/d. |
Whitecap has scheduled a conference call and webcast to begin promptly at
The conference call dial-in number is: 1-888-390-0605 or (587) 880-2175 or (416) 764-8609
A live webcast of the conference call will be accessible on Whitecap's website at www.wcap.ca by selecting "Investors", then "Presentations & Events". Shortly after the live webcast, an archived version will be available for approximately 14 days.
This press release contains forward-looking statements and forward-looking information (collectively "forward-looking information") within the meaning of applicable securities laws relating to the Company's plans and other aspects of our anticipated future operations, management focus, strategies, financial, operating and production results and business opportunities. Forward-looking information typically uses words such as "anticipate", "believe", "continue", "trend", "sustain", "project", "expect", "forecast", "budget", "goal", "guidance", "plan", "objective", "strategy", "target", "intend", "estimate", "potential", or similar words suggesting future outcomes, statements that actions, events or conditions "may", "would", "could" or "will" be taken or occur in the future, including statements about our strategy, plans, focus, objectives, priorities and position.
In particular, and without limiting the generality of the foregoing, this press release contains forward-looking information with respect to: that we will supplement our base dividend with share repurchases on our NCIB; that our balance sheet will further strengthen for both downside protection and value enhancing opportunities in the future as we allocate a portion of our free funds flow towards debt reduction; that the Musreau battery will support
The forward-looking information is based on certain key expectations and assumptions made by our management, including: that we will continue to conduct our operations in a manner consistent with past operations except as specifically noted herein (and for greater certainty, the forward-looking information contained herein excludes the potential impact of any acquisitions or dispositions that we may complete in the future); the general continuance or improvement in current industry conditions; the continuance of existing (and in certain circumstances, the implementation of proposed) tax, royalty and regulatory regimes; expectations and assumptions concerning prevailing and forecast commodity prices, exchange rates, interest rates, inflation rates, applicable royalty rates and tax laws, including the assumptions specifically set forth herein; the ability of OPEC+ nations and other major producers of crude oil to adjust crude oil production levels and thereby manage world crude oil prices; the impact (and the duration thereof) of the ongoing military actions in the
Although we believe that the expectations and assumptions on which such forward-looking information is based are reasonable, undue reliance should not be placed on the forward-looking information because Whitecap can give no assurance that they will prove to be correct. Since forward-looking information addresses future events and conditions, by its very nature it involves inherent risks and uncertainties. These include, but are not limited to: the risk that the funds that we ultimately return to shareholders through dividends and/or share repurchases is less than currently anticipated and/or is delayed, whether due to the risks identified herein or otherwise; the risk that any of our material assumptions prove to be materially inaccurate, including our 2024 forecast (including for commodity prices and exchange rates); the risks associated with the oil and gas industry in general such as operational risks in development, exploration and production, including the risk that weather events such as wildfires, flooding, droughts or extreme hot or cold temperatures forces us to shut-in production or otherwise adversely affects our operations; pandemics and epidemics; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of estimates and projections relating to reserves, production, costs and expenses; risks associated with increasing costs, whether due to high inflation rates, high interest rates, supply chain disruptions or other factors; health, safety and environmental risks; commodity price and exchange rate fluctuations; interest rate fluctuations; inflation rate fluctuations; marketing and transportation risks; loss of markets; environmental risks; competition; incorrect assessment of the value of acquisitions; failure to complete or realize the anticipated benefits of acquisitions or dispositions; the risk that going forward we may be unable to access sufficient capital from internal and external sources on acceptable terms or at all; failure to obtain required regulatory and other approvals; reliance on third parties and pipeline systems; changes in legislation, including but not limited to tax laws, production curtailment, royalties and environmental (including emissions) regulations; the risk that we do not successfully defend against previously disclosed and ongoing reassessments received from the
Readers are cautioned that the foregoing lists of factors are not exhaustive. Additional information on these and other factors that could affect our operations or financial results are included in reports on file with applicable securities regulatory authorities and may be accessed through the SEDAR+ website (www.sedarplus.ca).
These forward-looking statements are made as of the date of this press release and we disclaim any intent or obligation to update publicly any forward-looking information, whether as a result of new information, future events or results or otherwise, other than as required by applicable securities laws.
This press release contains future-oriented financial information and financial outlook information (collectively, "FOFI") about our forecast 2024 capital expenditures; our forecast for
All reserve references in this press release are "Company share (gross) reserves". Company share reserves are our total working interest reserves before the deduction of any royalties and including any royalty interests payable to the Company.
It should not be assumed that the present worth of estimated future amounts presented in the tables above represents the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions will be attained, and variances could be material. The recovery and reserve estimates of the crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquids reserves may be greater than or less than the estimates provided herein.
"Boe" means barrel of oil equivalent. All boe conversions in this press release are derived by converting gas to oil at the ratio of six thousand cubic feet ("Mcf") of natural gas to one barrel ("Bbl") of oil. Boe may be misleading, particularly if used in isolation. A Boe conversion rate of 1 Bbl : 6 Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio of oil compared to natural gas based on currently prevailing prices is significantly different than the energy equivalency ratio of 1 Bbl : 6 Mcf, utilizing a conversion ratio of 1 Bbl : 6 Mcf may be misleading as an indication of value.
This press release contains metrics commonly used in the oil and natural gas industry which have been prepared by management, such as "acquisition capital", "development capital", "F&D costs", "FD&A costs", "half-cycle payout","operating netback", "production replacement", "production replacement ratio", "recycle ratio", and "reserve life index". These terms do not have a standardized meaning and may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons.
" Acquisition capital" is a non-GAAP financial measure used in the determination of FD&A costs, which is a non-GAAP ratio. The most directly comparable GAAP measure to acquisition capital is expenditures on corporate acquisitions, net of cash acquired, and expenditures on property acquisitions. For property acquisitions, acquisition capital is the purchase price, including cash and/or shares of assets acquired (disposed). For corporate acquisitions, it is the purchase price (cash and/or shares plus assumed bank debt, if applicable) including any estimated working capital surplus or deficit rather than the amounts allocated to PP&E for accounting purposes. The following table details the calculation of Acquisition capital for the periods indicated:
|
Year ended |
||
($ millions) |
2023 |
2022 |
2021 |
Property acquisitions |
165.5 |
7.9 |
154.1 |
Corporate acquisitions |
- |
2,001.6 |
1,432.4 |
Less: Property dispositions |
394.4 |
24.4 |
188.2 |
|
(228.9) |
1,985.1 |
1,398.4 |
"Development capital" is a non-GAAP financial measure used in the determination of F&D costs and FD&A costs, which are non-GAAP ratios. The most directly comparable GAAP measure to development capital is expenditures on property, plant, and equipment. Development capital means the aggregate exploration and development costs incurred in the financial year on reserves that are categorized as development. Development capital excludes corporate and capitalized general and administrative expenses. The following table reconciles expenditures on property, plant and equipment to Development capital for the periods indicated:
|
Year ended |
||
($ millions) |
2023 |
2022 |
2021 |
Expenditures on property, plant and equipment |
953.8 |
686.5 |
428.5 |
Less: expenditures on corporate and capitalized general and administrative expenses |
14.2 |
16.6 |
14.6 |
|
939.6 |
669.9 |
413.9 |
"F&D costs" are calculated as the sum of development capital plus the change in FDC for the period when appropriate, divided by the change in reserves that are characterized as development for the period. Development capital is a non-GAAP financial measure used as a component of F&D costs. Management uses F&D costs as a measure of capital efficiency for organic reserves development.
"FD&A costs" are calculated as the sum of development capital plus acquisition capital plus the change in FDC for the period when appropriate, divided by the change in total reserves, other than from production, for the period. Development capital and acquisition capital are non-GAAP financial measures used as components of FD&A costs. Management uses FD&A costs as a measure of capital efficiency for organic and acquired reserves development.
"Half-cycle payout" is the time period for the operating netback of a well to equate to the individual cost of drilling, completing and equipping the well. Management uses half-cycle payout as a measure of capital efficiency of a well to make capital allocation decisions.
" Production replacement ratio" or "production replacement" is calculated as total reserve additions (including acquisitions net of dispositions) divided by annual production.
" Recycle ratio" is calculated by dividing operating netback per boe by F&D costs or FD&A costs for the year. Operating netback per boe is a non-GAAP ratio that uses operating netback, a non-GAAP financial measure, as a component. Development capital, a non-GAAP financial measure, is used as a component of F&D costs. Development capital and acquisition capital, both non-GAAP financial measures, are used as components of FD&A costs. Management uses recycle ratio to relate the cost of adding reserves to the expected cash flows to be generated.
" Reserve life index" or "RLI" is calculated as total Company share reserves divided by annualized fourth quarter actual production.
Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare our operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this press release, should not be relied upon for investment or other purposes.
This press release discloses drilling inventory in two categories: (i) booked locations (proved and probable); and (ii) unbooked locations. Booked locations represent the summation of proved and probable locations, which are derived from
- Of the 6,400 (5,600 net) drilling locations identified herein, 1,590 (1,374 net) are proved locations, 323 (271 net) are probable locations, and 4,487 (3,955 net) are unbooked locations.
Unbooked locations consist of drilling locations that have been identified by management as an estimation of our multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that we will drill all of these drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which we drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While certain of the unbooked drilling locations have been de-risked by drilling existing wells in relative close proximity to such unbooked drilling locations, other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production.
Production, Initial Production Rates & Product Type Information
References to petroleum, crude oil, natural gas liquids ("NGLs"), natural gas and average daily production in this press release refer to the light and medium crude oil, tight crude oil, conventional natural gas, shale gas and NGLs product types, as applicable, as defined in National Instrument 51-101 ("NI 51-101"), except as noted below.
NI 51-101 includes condensate within the NGLs product type. The Company has disclosed condensate as combined with crude oil and separately from other NGLs since the price of condensate as compared to other NGLs 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 therefrom. Crude oil therefore refers to light oil, medium oil, tight oil and condensate. NGLs refers to ethane, propane, butane and pentane combined. Natural gas refers to conventional natural gas and shale gas combined.
Any reference in this news release to initial production rates (IP(60), IP(90), IP(120)) are useful in confirming the presence of hydrocarbons, however such rates are not determinative of the rates at which such wells will continue production and decline thereafter. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for Whitecap.
The Company's average daily production for the three and twelve months ended
Whitecap Corporate |
Q4/2023 |
Q4/2022 |
2023 |
2022 |
Light and medium oil (bbls/d) |
76,942 |
80,776 |
75,432 |
80,441 |
Tight oil (bbls/d) |
11,745 |
11,036 |
10,286 |
5,976 |
Crude oil (bbls/d) |
88,687 |
91,812 |
85,718 |
86,417 |
|
|
|
|
|
NGLs (bbls/d) |
19,241 |
17,473 |
17,296 |
15,521 |
|
|
|
|
|
Shale gas (Mcf/d) |
196,540 |
181,478 |
171,178 |
97,299 |
Conventional natural gas (Mcf/d) |
155,217 |
161,162 |
149,744 |
157,409 |
Natural gas (Mcf/d) |
351,757 |
342,640 |
320,922 |
254,708 |
|
|
|
|
|
Total (boe/d) |
166,554 |
166,392 |
156,501 |
144,389 |
Whitecap Corporate / Initial Production Rates |
2024 Guidance
( |
Kakwa (IP(120)) |
Lator (IP(60)) |
Kaybob (IP(90)) |
Light and medium oil (bbls/d) |
75,000 |
- |
- |
- |
Tight oil (bbls/d) |
14,200 |
394 |
683 |
407 |
Crude oil (bbls/d) |
89,200 |
394 |
683 |
407 |
|
|
|
|
|
NGLs (bbls/d) |
17,800 |
216 |
57 |
162 |
|
|
|
|
|
Shale gas (Mcf/d) |
217,000 |
7,674 |
5,490 |
6,186 |
Conventional natural gas (Mcf/d) |
146,000 |
- |
- |
- |
Natural gas (Mcf/d) |
366,000 |
7,674 |
5,490 |
6,186 |
|
|
|
|
|
Total (boe/d) |
167,500 |
1,889 |
1,655 |
1,600 |
|
|
|
|
|
Light and medium oil (bbls/d) |
|
|
|
14,000 |
Tight oil (bbls/d) |
|
|
|
- |
Crude oil (bbls/d) |
|
|
|
14,000 |
|
|
|
|
|
NGLs (bbls/d) |
|
|
|
500 |
|
|
|
|
|
Shale gas (Mcf/d) |
|
|
|
- |
Conventional natural gas (Mcf/d) |
|
|
|
- |
Natural gas (Mcf/d) |
|
|
|
- |
|
|
|
|
|
Total (boe/d) |
|
|
|
14,500 |
This press release includes various specified financial measures, including non-GAAP financial measures, non-GAAP ratios, capital management measures and supplementary financial measures as further described herein. These financial measures are not standardized financial measures under International Financial Reporting Standards ("IFRS" or, alternatively, "GAAP") and, therefore, may not be comparable with the calculation of similar financial measures disclosed by other companies.
"
"Average realized prices" for crude oil, NGLs and natural gas are supplementary financial measures calculated by dividing each of these components of petroleum and natural gas revenues, disclosed in Note 16 "Revenue" to the Company's audited annual consolidated financial statements for the year ended
"Free funds flow" is a non-GAAP financial measure calculated as funds flow less expenditures on property, plant and equipment ("PP&E"). Management believes that free funds flow provides a useful measure of Whitecap's ability to increase returns to shareholders and to grow the Company's business. Free funds flow is not a standardized financial measure under IFRS and, therefore, may not be comparable with the calculation of similar financial measures disclosed by other entities. The most directly comparable financial measure to free funds flow disclosed in the Company's primary financial statements is cash flow from operating activities. Refer to the "Cash Flow from Operating Activities, Funds Flow and Payout Ratios" section of our management's discussion and analysis for the year ended
|
Three months ended |
Year ended |
||
($ millions) |
2023 |
2022 |
2023 |
2022 |
Cash flow from operating activities |
476.2 |
555.8 |
1,742.5 |
2,183.1 |
Net change in non-cash working capital items |
(13.9) |
37.8 |
48.9 |
139.7 |
Funds flow |
462.3 |
593.6 |
1,791.4 |
2,322.8 |
Expenditures on PP&E |
200.5 |
179.0 |
953.8 |
686.5 |
Free funds flow |
261.8 |
414.6 |
837.6 |
1,636.3 |
Funds flow per share, basic |
0.77 |
0.97 |
2.96 |
3.77 |
Funds flow per share, diluted |
0.76 |
0.97 |
2.94 |
3.74 |
"Free funds flow diluted ($/share)" is a non-GAAP ratio calculated by dividing free funds flow by the weighted average number of diluted shares outstanding for the relevant period. Free funds flow is a non-GAAP financial measure component of free funds flow diluted ($/share). Free funds flow diluted ($/share) is not a standardized financial measure under IFRS and therefore may not be comparable with the calculation of similar financial measures disclosed by other entities.
" Funds flow", "funds flow basic ($/share)" and "funds flow diluted ($/share)" are capital management measures and are key measures of operating performance as they demonstrate Whitecap's ability to generate the cash necessary to pay dividends, repay debt, make capital investments, and/or to repurchase common shares under the Company's normal course issuer bid. Management believes that by excluding the temporary impact of changes in non-cash operating working capital, funds flow, funds flow basic ($/share) and funds flow diluted ($/share) provide useful measures of Whitecap's ability to generate cash that are not subject to short-term movements in non-cash operating working capital. Whitecap reports funds flow in total and on a per share basis (basic and diluted), which is calculated by dividing funds flow by the weighted average number of basic shares and weighted average number of diluted shares outstanding for the relevant period. See Note 5(e)(ii) "Capital Management – Funds Flow" in the Company's audited annual consolidated financial statements for the year ended December 31, 2023 for additional disclosures.
"Funds flow netback ($/boe)" is a non-GAAP ratio calculated by dividing funds flow by the total production for the period. Funds flow netback per boe is not a standardized financial measure under IFRS and, therefore may not be comparable with the calculation of similar financial measures disclosed by other entities. Presenting funds flow netback on a per boe basis allows management to better analyze performance against prior periods on a comparable basis.
" Net Debt" is a capital management measure that management considers to be key to assessing the Company's liquidity. See Note 5(e)(i) "Capital Management – Net Debt and Total Capitalization" in the Company's audited annual consolidated financial statements for the year ended December 31, 2023 for additional disclosures. The following table reconciles the Company's long-term debt to net debt:
Net Debt ($ millions) |
|
|
|
|
Long-term debt |
|
|
1,356.1 |
1,844.6 |
Accounts receivable |
|
|
(400.2) |
(480.2) |
Deposits and prepaid expenses |
|
|
(32.9) |
(22.7) |
Non-current deposits |
|
|
(82.9) |
- |
Accounts payable and accrued liabilities |
|
|
509.0 |
549.1 |
Dividends payable |
|
|
36.4 |
22.3 |
Net Debt |
|
|
1,385.5 |
1,913.1 |
"Operating netback" is a non-GAAP financial measure determined by adding marketing revenues and processing & other income, deducting realized losses on commodity risk management contracts or adding realized gains on commodity risk management contracts and deducting tariffs, royalties, operating expenses, transportation expenses and marketing expenses from petroleum and natural gas revenues. The most directly comparable financial measure to operating netback disclosed in the Company's primary financial statements is petroleum and natural gas sales. Operating netback is a measure used in operational and capital allocation decisions. Operating netback is not a standardized financial measure under IFRS and, therefore, may not be comparable with the calculation of similar financial measures disclosed by other entities. For further information, refer to the "Operating Netbacks" section of our management's discussion and analysis for the year ended
|
Three months ended |
Year ended |
||
Operating Netbacks ($ millions) |
2023 |
2022 |
2023 |
2022 |
Petroleum and natural gas revenues |
914.1 |
1,116.5 |
3,551.6 |
4,452.9 |
Tariffs |
(6.4) |
(7.5) |
(27.9) |
(24.1) |
Processing & other income |
12.2 |
11.8 |
49.8 |
35.9 |
Marketing revenues |
70.1 |
90.8 |
275.4 |
315.7 |
Petroleum and natural gas sales |
990.0 |
1,211.6 |
3,848.9 |
4,780.4 |
Realized gain (loss) on commodity contracts |
(2.1) |
(21.9) |
19.5 |
(245.5) |
Royalties |
(163.4) |
(204.2) |
(618.9) |
(861.8) |
Operating expenses |
(205.5) |
(216.3) |
(805.4) |
(766.3) |
Transportation expenses |
(32.1) |
(32.5) |
(123.8) |
(114.8) |
Marketing expenses |
(69.6) |
(89.8) |
(273.9) |
(313.0) |
Operating netbacks |
517.3 |
646.9 |
2,046.4 |
2,479.0 |
"Operating netback ($/boe)" is a non-GAAP ratio calculated by dividing operating netbacks by the total production for the period. Operating netback is a non-GAAP financial measure component of operating netback per boe. Operating netback per boe is not a standardized financial measure under IFRS and, therefore may not be comparable with the calculation of similar financial measures disclosed by other entities. Presenting operating netback on a per boe basis allows management to better analyze performance against prior periods on a comparable basis.
"Petroleum and natural gas revenues ($/boe)", "Tariffs ($/boe)", "Processing and other income ($/boe)" and "Marketing revenues ($/boe)" are supplementary financial measures calculated by dividing each of these components of petroleum and natural gas sales, disclosed in Note 16 "Revenue" to the Company's audited annual consolidated financial statements for the year ended
"Per boe" or "($/boe)" disclosures for petroleum and natural gas sales, royalties, operating expenses, transportation expenses and marketing expenses are supplementary financial measures that are calculated by dividing each of these respective GAAP measures by the Company's total production volumes for the period.
"Realized gain (loss) on commodity contracts ($/boe)" is a supplementary financial measure calculated by dividing realized gain (loss) on commodity contracts, disclosed in Note 5(d) "Financial Instruments and Risk Management – Market Risk" to the Company's audited annual consolidated financial statements for the year ended
Per Share Amounts
Per share amounts noted in this press release are based on fully diluted shares outstanding unless noted otherwise.
SOURCE