CALGARY, Alberta, Feb. 16, 2023 (GLOBE NEWSWIRE) — (PIPE – TSX) Pipestone Energy Corp. (“Pipestone” or the “Company”) is pleased to provide an update on its operations, including record quarterly production and free cash flow(1) and substantial deleveraging during the fourth quarter; and to report its year-end 2022 independent reserves evaluation prepared by McDaniel & Associates Consultants Ltd. (“McDaniel”), effective December 31, 2022 (the “McDaniel Report”).
Operational results and reserve updates are consistent with Pipestone’s previously announced strategy of an increased focus on enhancing shareholder returns, by moderating its forecast average annual growth rate to ~10% over the next three years and shifting its focus toward maximizing free cash flow(1) generation so as to deliver shareholder returns.
(1) See “Advisory Regarding Non-GAAP Measures – Non-GAAP Measures” advisory.
Recent Corporate Highlights and Select Unaudited 2022 Results:
All financial and operating information in this press release for the fourth quarter and year ended December 31, 2022, such as production volumes, revenue, adjusted funds flow from operations(1), free cash flow(1), capital expenditures, net debt(1) and operating netback(1), are based on unaudited estimated results and have not been reviewed by the Company’s auditors. These estimates may be subject to change upon the completion of audited financial statements for the year ended December 31, 2022 and changes could be material. Pipestone anticipates filing its audited financial statements for the year ended December 31, 2022, on SEDAR on March 8th, 2023.
- Record Production Volumes: Q4 2022 production achieved a corporate record averaging 33,816 boe/d (30% condensate, 42% total liquids), representing a 5% increase over Q3 2022, and an 18% increase over Q4 2021. Based on field estimates, January 2023 production averaged 34,600 boe/d (30% condensate, 40% total liquids). Pipestone has not brought any new wells on production since November 2022;
- 2022 Production Guidance Achieved: 2022 production averaged 31,090 boe/d (29% condensate, 41% total liquids) within the previously announced guidance range of 31,000 – 33,000 boe/d;
- Fourth Quarter 2022 Revenue: As a result of increased production volumes, the Company generated revenue of $185.4 million which represents a $48.1 million or 35% increase from Q4 2021 revenue of $137.3 million and an $11.0 million or 6% increase from Q3 2022 revenue of $174.4 million;
- Record Quarterly Free Cash Flow(1): During the fourth quarter, Pipestone generated $99.7 million of adjusted funds flow from operations(1) ($0.36 per fully diluted share), which, after $29.6 million in capital expenditures, resulted in $70.1 million of free cash flow(1) ($0.25 per fully diluted share);
- Significant Deleveraging: During Q4 2022, the Company reduced its net debt(1) by $62.8 million (~35%) from $180.2 million to $117.4 million, resulting in a year-end 2022 net debt(1) to 2022 cash flow ratio of 0.3x; and
- 2023 Production Guidance: The Company reaffirms its full year 2023 production guidance range of 34,000 – 36,000 boe/d, with 26 net wells expected to be brought on stream, including six wells from the 11-05 pad during the first quarter of 2023.
(1) See "Advisory Regarding Non-GAAP Measures – Non-GAAP measures" advisory.
Operations Update:
Development Map:
A chart accompanying this announcement is available at https://www.globenewswire.com/NewsRoom/AttachmentNg/18b49eb0-8a8c-4f2e-9296-69c425769711
Production Update:
Based on field estimates, Pipestone delivered record quarterly production of 33,816 boe/d (30% condensate, 42% total liquids) during Q4 2022, resulting in full year 2022 production of 31,090 boe/d(1) (29% condensate, 41% total liquids) which is within the previously announced guidance of 31,000 – 33,000 boe/d. Positive momentum has continued into Q1 2023, with average January production of approximately 34,600 boe/d (30% condensate, 40% total liquids). The Company reaffirms its full year 2023 production guidance range of 34,000 – 36,000 boe/d, with 26 net wells expected to be brought on-stream, including six wells from the 11-05 pad during the first quarter of 2023.
Well Results:
During Q4 2022, Pipestone brought its two eastern most delineation wells on stream at the 9-14 pad, one in the Montney ‘B’ and one in the Lower Montney ‘D’ bench. Both wells are trending at or above type curve expectations and demonstrate the extent of highly economic resource potential in multiple development benches across the asset. The Montney ‘B’ well has achieved an IP90 of 4.3 MMcf/d raw gas + 283 bbls/d wellhead condensate (condensate-gas-ratio (“CGR”) of 66 bbl/MMcf). The Lower Montney ‘D’ well has achieved an IP90 of 3.9 MMcf/d raw gas + 391 bbls/d wellhead condensate (CGR of 100 bbl/MMcf). Until early February, the Lower Montney ‘D’ well was producing from only the first ~50% of its lateral length because of a bridge plug installed during its initial testing phase. Since the removal of this plug, the well has averaged 6.9 MMcf/d raw gas + 860 bbls/d wellhead condensate (CGR of ~125 bbl/MMcf) over the past seven days.
Drilling & Completions Update:
Pipestone successfully executed on all of its planned Q4 2022 development activities. During the quarter, the Company drilled six wells on the 11-05 pad, which were subsequently completed in late 2022 through January 2023. These wells are being equipped and will be on production by the beginning of March. The 11-05 pad includes the longest wells drilled since inception, with two wells drilled southeast off the pad at a lateral length of approximately 4,500 metres. Increasing lateral length allows the Company to minimize its surface footprint while simultaneously driving positive drilling cost efficiencies. Pipestone currently has two rigs drilling four wells on the 2-31 pad and four wells on the 2-25 pad. Both pads will be completed during Q1 2023 with expected on-stream timing of Q2 2023.
Delineation Activity:
Recently, competitors have demonstrated strong results in the Montney volatile oil window offsetting the Company’s southeastern acreage. In February, Pipestone will spud the first of two planned delineation wells off the 11-09 pad in the southeast portion of the Company’s acreage position, with frac operations to follow immediately in Q1 of 2023. An existing well on the 11-09 pad, which was drilled and completed by Pipestone’s predecessor company in 2018, achieved a last 24-hour test rate of 2.6 MMcf/d raw gas + 855 bbls/d wellhead condensate (CGR of 329 bbl/MMcf).
2022 Independent Reserves Evaluation(1):
- Pipestone delivered 32% growth in Proved Developed Producing (“PDP”) reserves from 41 MMboe in 2021 to 53 MMboe in 2022 and achieved a finding & development (“F&D”) cost of $10.16/boe, coupled with a full year 2022 operating netback(1) of $40.96/boe (exclusive of hedging losses) which drives a 2022 PDP F&D recycle ratio(2) of 4.0x;
- Total Proved (“1P”) reserves volumes are flat year-over-year at ~160 MMboe, with 100% of the Company’s 2022 production replaced. Since December 31, 2019, the Company has grown its 1P reserves volume from 112 MMboe to 160 MMboe (+47 MMboe / +42%), replacing 168% of production over that same period;
- Total Proved plus Probable (“2P”) reserves volumes decreased year-over-year from 275 MMboe to 230 MMboe (-45 MMboe / -16%). As announced in November 2022, this reduction is attributable to both lower expected absolute productivity and lower expectations for initial and terminal CGRs on the go-forward development wells. Also as previously announced, the majority of Pipestone’s Proved Undeveloped locations at year-end 2022 carry a modified lower CGR (VRGC1) type curve, with a reduction in the number of higher CGR (VRGC2 & VRGC3) type curve booked locations remaining(3);
- Going forward, estimated undeveloped 1P F&D cost (future development capital (“FDC”) divided by Proved Undeveloped reserves) is $11.68/boe and Undeveloped 2P F&D cost is $9.20/boe; and
- Updated 1P and 2P net asset value per share (“NAVPS”)(4) of $4.61 and $6.70 per basic share, respectively, utilizing a 10% discount rate at the year-end 3-consultant (“3C”) average forecast pricing. These NAVPS(4) values reflect a premium of 54% and 123%, for 1P and 2P respectively, over the current share price(5) of $3.00.
| (1) | 2022 annual production volumes, capital expenditures and operating netbacks referenced throughout this press release are unaudited. All reserve volumes are reported on a net working interest, gross of royalties basis. Operating netback is a non-GAAP measure – see “Advisory Regarding Non-GAAP Measures – Non-GAAP measures” advisory. | |
| (2) | Recycle ratio is calculated by dividing operating netback per boe by F&D costs per boe. 2022 operating netback (unaudited) used to calculate recycle ratio is exclusive of realized hedging impacts and is calculated as revenue less royalties, operating, and transportation costs. Recycle ratio is a non-GAAP ratio and operating netback is a Non-GAAP measure – see “Advisory Regarding Non-GAAP Measures – Non-GAAP measures” and " – Non-GAAP ratios" advisory . | |
| (3) | Please refer to Pipestone’s updated February 2023 Corporate presentation for further details on specific type curve information, located at www.pipestonecorp.com. “VRGC” means very rich gas condensate. | |
| (4) | NAVPS is a non-GAAP ratio – see “Advisory Regarding Non-GAAP Measures – Non-GAAP ratios”. | |
| (5) | Current share price as at February 14, 2023. |
Year-End 2022 Reserve Results:
| December 31, 2022(1) | December 31, 2021(2) | ||||||||
| Total by Category | Volume | Weight | Volume | Weight | Chg. | ||||
| Proved Developed Producing | Mboe | 53,343 | 23 | % | 40,510 | 15 | % | 32 | % |
| Proved Developed Non-Producing | Mboe | 961 | 0 | % | 4,394 | 2 | % | (78 | %) |
| Proved Undeveloped | Mboe | 105,624 | 46 | % | 115,244 | 42 | % | (8 | %) |
| Total Proved | Mboe | 159,928 | 69 | % | 160,148 | 58 | % | 0 | % |
| Probable | Mboe | 70,369 | 31 | % | 115,075 | 42 | % | (39 | %) |
| Total Proved + Probable | Mboe | 230,297 | 100 | % | 275,223 | 100 | % | (16 | %) |
| (1) | Volumes calculated using the 3C average forecast pricing as of January 1, 2023. The 3C average forecast pricing includes pricing forecasts from McDaniel, GLJ Ltd. and Sproule Associates Limited. | |
| (2) | Volumes calculated using the 3C average forecast pricing as of January 1, 2022. |
2022 Independent Reserves Evaluation:
The McDaniel Report was prepared in accordance with definitions, standards, and procedures contained in the Canadian Oil and Gas Evaluation Handbook and NationaI Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities. The McDaniel Report was based on 3C average forecast pricing and foreign exchange rates at January 1, 2023, as outlined in this press release.
Reserves included herein are stated on a company gross basis (working interest before deduction of royalties without the inclusion of any royalty interest) unless otherwise noted. In addition to the information disclosed in this news release, more detailed information will be included in Pipestone’s annual information form for the year ended December 31, 2022, which will be available on the Company’s website at www.pipestonecorp.com and on SEDAR at www.sedar.com on or before March 31, 2023.
Company Gross (before royalties) Working Interest Reserves:
| 2022 Year-End Reserves (Working Interest)(1) | ||||
| Natural Gas | Total | |||
| Tight Oil | Shale Gas | Liquids(2) | Company | |
| Reserve Category | (Mbbl) | (MMcf) | (Mbbl) | (Mboe) |
| Proved | ||||
| Developed Producing | 25 | 191,143 | 21,460 | 53,342 |
| Developed Non-Producing | – | 3,297 | 412 | 961 |
| Undeveloped | – | 366,315 | 44,572 | 105,624 |
| Total Proved | 25 | 560,755 | 66,443 | 159,928 |
| Total Probable | 6 | 246,512 | 29,277 | 70,369 |
| Total Proved + Probable(3) | 32 | 807,267 | 95,721 | 230,297 |
| (1) | Volumes calculated using the 3C average forecast pricing as of January 1, 2023. | |
| (2) | Natural Gas Liquids includes condensate volumes. Booked 2P condensate volumes (including pentanes plus) are 66,584 Mbbls as at December 31, 2022. | |
| (3) | Amounts may not add due to rounding. |
Company Net Present Value of Future Net Revenue Using 3C Average Pricing Forecast (1):
| Before Income Taxes | |||||||||||||||
| $C Millions | Discount Factor (% / Year) | ||||||||||||||
| Reserve Category | 0% | 5% | 10% | 15% | 20% | ||||||||||
| Proved | |||||||||||||||
| Developed Producing | $929 | $796 | $695 | $619 | $562 | ||||||||||
| Developed Non-Producing | $22 | $19 | $18 | $16 | $15 | ||||||||||
| Undeveloped | $1,378 | $965 | $696 | $514 | $387 | ||||||||||
| Total Proved(2) | $2,329 | $1,780 | $1,409 | $1,150 | $964 | ||||||||||
| Probable | $1,271 | $831 | $585 | $438 | $344 | ||||||||||
| Total Proved + Probable(2) | $3,600 | $2,611 | $1,994 | $1,588 | $1,308 | ||||||||||
| (1) | Calculated using the 3C average pricing forecast as of January 1, 2023. | |
| (2) | Amounts may not add due to rounding. |
FDC and F&D Costs:
FDC reflects McDaniel’s best estimate of the future cost to bring Pipestone’s proved and probable developed and undeveloped reserves on production. Changes in forecasted FDC occur annually as a result of development activities, acquisition and disposition activities, changes in capital cost estimates based on improvements in well design and performance, and changes in service costs. Undiscounted 2P FDC at December 31, 2022 increased by $488 million relative to December 31, 2021, to total $1,477 million. The year-over-year increase in FDC incorporates capital cost inflation expectations, increased average completion scope, as well as incremental facilities capital to improve base production performance and reduce long-term operating costs.
| Total Proved | ||||
| Total Proved | + Probable | |||
| Year | (C$MM) | (C$MM) | ||
| 2023 | $243 | $243 | ||
| 2024 | $287 | $287 | ||
| 2025 | $279 | $279 | ||
| 2026 | $257 | $257 | ||
| 2027 | $138 | $172 | ||
| Remainder Thereafter | $30 | $240 | ||
| Total FDC Undiscounted(1) | $1,234 | $1,477 | ||
| Total FDC Discounted (10%) | $997 | $1,132 | ||
| (1) | Amounts may not add due to rounding. |
| Proved Developed Producing | |||||||||||||||||||||||||||||||||
| Year | PDP Reserves (Mboe) |
Production (Mboe) |
Change in PDP (Mboe) |
Capital Expenditures ($MM) |
F&D Cost ($/boe) |
Operating Netback (1) (Estimated) ($/boe) |
Recycle Ratio(2) |
||||||||||||||||||||||||||
| 2019 | 18,529 | 1,738 | |||||||||||||||||||||||||||||||
| 2020 | 31,735 | 5,683 | 18,889 | $105 | $5.54 | $8.49 | 1.5x | ||||||||||||||||||||||||||
| 2021 | 40,510 | 8,973 | 17,748 | $187 | $10.53 | $27.72 | 2.6x | ||||||||||||||||||||||||||
| 2022 | 53,343 | 11,348 | 24,181 | $246 | $10.16 | $40.96 | 4.0x | ||||||||||||||||||||||||||
| 3-Year Weighted Average: | $ | 8.83 | $ | 29.30 | 3.3x | ||||||||||||||||||||||||||||
| Total Proved | |||||||||||||||||||||||||||||||||
| Year | Proved Reserves (Mboe) |
Production (Mboe) |
Change in Proved Reserves (Mboe) |
CAPEX ($MM) |
FDC ($MM) | F&D Cost (No FDC) ($/boe) |
F&D Cost (with FDC) ($/boe) |
Operating Netback(1) ($/boe) |
Recycle Ratio(2) (No FDC) |
Recycle Ratio(2) (with FDC) |
|||||||||||||||||||||||
| 2019 | 112,495 | 1,738 | $790 | ||||||||||||||||||||||||||||||
| 2020 | 113,977 | 5,683 | 27,165 | $105 | $640 | $3.85 | ($1.67 | ) | $8.49 | 2.2x | (5.1x) | ||||||||||||||||||||||
| 2021 | 160,148 | 8,973 | 35,144 | $187 | $708 | $5.32 | $7.25 | $27.72 | 5.2x | 3.8x | |||||||||||||||||||||||
| 2022 | 159,928 | 11,348 | 11,128 | $246 | $1,234 | $22.08 | $69.34 | $40.96 | 1.9x | 0.6x | |||||||||||||||||||||||
| 3-Year Weighted Average: | $7.31 | $13.36 | $29.30 | 4.0x | 2.2x | ||||||||||||||||||||||||||||
|
Total Proved + Probable |
|||||||||||||||||||||||||||||||||
| Year | 2P Reserves (Mboe) |
Production (Mboe) |
Change in 2P Reserves (Mboe) |
CAPEX ($MM) |
FDC ($MM) | F&D Cost (No FDC) ($/boe) |
F&D Cost (with FDC) ($/boe) |
Operating Netback(1) ($/boe) |
Recycle Ratio(2) (No FDC) |
Recycle Ratio(2) (with FDC) |
|||||||||||||||||||||||
| 2019 | 183,585 | 1,738 | $1,114 | ||||||||||||||||||||||||||||||
| 2020 | 227,672 | 5,683 | 49,770 | $105 | $936 | $2.10 | ($1.48 | ) | $8.49 | 4.0x | (5.8x) | ||||||||||||||||||||||
| 2021 | 275,223 | 8,973 | 56,524 | $187 | $989 | $3.31 | $4.21 | $27.72 | 8.4x | 6.5x | |||||||||||||||||||||||
| 2022 | 230,297 | 11,348 | (33,578 | ) | $246 | $1,477 | ($7.32 | ) | ($21.86 | ) | $40.96 | (5.6x) | (1.9)x | ||||||||||||||||||||
| 3-Year Weighted Average: | $7.39 | $12.38 | $29.30 | 4.0x | 2.4x | ||||||||||||||||||||||||||||
| (1) | 2022 Operating netback (unaudited) used to calculate recycle ratio is exclusive of realized hedging impacts and is calculated as revenue less royalties, operating, and transportation costs. Operating netback is a non-GAAP measure, see “Advisory Regarding Non-GAAP Measures – Non-GAAP measures” advisory. | |
| (2) | Recycle ratio is a Non-GAAP ratio – see “Advisory Regarding Non-GAAP Measures – Non-GAAP ratios”. |
| 1P / 2P Future Undeveloped F&D Costs | ||
| Proved Undeveloped | ||
| 1P Future Development Capital | $MM | $1,234 |
| Proved Undeveloped Reserves | Mboe | 105,624 |
| 1P F&D | $/boe | $11.68 |
| Proved + Probable | ||
| 2P Future Development Capital | $MM | $1,477 |
| Proved + Probable Undeveloped Reserves | Mboe | 160,652 |
| 2P F&D | $/boe | $9.19 |
Annual Reserve Reconciliation
| Tight Oil | Natural Gas | Natural Gas Liquids(1) | Company Total | |||||
| Company Gross | (Mbbl) | (MMcf) | (Mbbl) | (Mboe) | ||||
| Proved Developed Producing | ||||||||
| Balance – December 31, 2021 | 22.7 | 145,910 | 16,169 | 40,510 | ||||
| Extensions | – | 1,478 | 328 | 574 | ||||
| Economic Factors | 10.5 | 11,325 | 1,126 | 3,024 | ||||
| Technical Revisions | 26.0 | (3,483 | ) | (161 | ) | (716 | ) | |
| Technical Revisions – PUD Transfer | – | 75,910 | 8,646 | 21,298 | ||||
| Production | (33.9 | ) | (39,997 | ) | (4,648 | ) | (11,348 | ) |
| Balance – December 31, 2022(2) | 25.3 | 191,143 | 21,460 | 53,343 | ||||
| Total Proved | ||||||||
| Balance – December 31, 2021 | 22.7 | 553,877 | 67,813 | 160,148 | ||||
| Extensions | – | 129,578 | 18,302 | 39,899 | ||||
| Economic Factors | 10.5 | 19,490 | 2,075 | 5,334 | ||||
| Technical Revisions | 26 | (78,760 | ) | (13,052 | ) | (26,153 | ) | |
| Technical Revision – PUD Transfer | – | (23,434 | ) | (4,047 | ) | (7,953 | ) | |
| Production | (33.9 | ) | (39,997 | ) | (4,648 | ) | (11,348 | ) |
| Balance – December 31, 2022(2) | 25.3 | 560,755 | 66,443 | 159,928 | ||||
| Total Probable | ||||||||
| Balance – December 31, 2021 | 6.9 | 403,757 | 47,775 | 115,075 | ||||
| Extensions | – | (28,101 | ) | (2,138 | ) | (6,821 | ) | |
| Economic Factors | 35.6 | 14,425 | 1,569 | 4,008 | ||||
| Technical Revisions | (36.0 | ) | (133,395 | ) | (16,349 | ) | (38,618 | ) |
| Technical Revision – PUD Transfer | – | (10,174 | ) | (1,580 | ) | (3,275 | ) | |
| Production | – | – | – | – | ||||
| Balance – December 31, 2022(2) | 6.5 | 246,512 | 29,277 | 70,369 | ||||
| Proved + Probable | ||||||||
| Balance – December 31, 2021 | 29.5 | 957,632 | 115,588 | 275,223 | ||||
| Extensions | – | 101,477 | 16,165 | 33,077 | ||||
| Economic Factors | 46.1 | 33,916 | 3,644 | 9,342 | ||||
| Technical Revisions | (10.0 | ) | (212,156 | ) | (29,401 | ) | (64,770 | ) |
| Technical Revision – PUD Transfer | – | (33,608 | ) | (5,627 | ) | (11,228 | ) | |
| Production | (33.9 | ) | (39,997 | ) | (4,648 | ) | (11,348 | ) |
| Balance – December 31, 2022(2) | 31.7 | 807,267 | 95,721 | 230,297 |
| (1) | Natural gas liquids includes condensate volumes. Booked 2P condensate volumes (including pentanes plus) are 66,584 Mbbls as of December 31, 2022. | |
| (2) | Amounts may not add due to rounding. |
Pre-Tax Net Asset Value – Excludes Unbooked Land Value:
| As at December 31, 2022 |
||||
| Total |
Total Proved |
|||
| $C Millions | Proved |
and Probable |
||
| Reserves, Before-Tax NPV10% (3C Price Forecast) | $1,409 | $1,994 | ||
| (-) Abandonment Obligations (Estimated) | ($14 | ) | ($14 | ) |
| (-) Mark-to-Market of Hedges(1) | $7 | $7 | ||
| (-) Net Debt (Estimated)(2) | ($117 | ) | ($117 | ) |
| = Implied Net Asset Value | $1,285 | $1,870 | ||
| Fully Diluted Shares Outstanding (millions)(3) | 279 | 279 | ||
| Net Asset Value per Share ($/share) | $4.61 | $6.70 | ||
Note: The above net asset value excludes any additional land value for approximately 50 net sections of unbooked undeveloped land, which represents approximately 35% of the Company’s total land base.
| (1) | Mark-to-market calculation reflects commodity prices as at December 31, 2022. | |
| (2) | Net debt represents bank debt and the addition of working capital excluding dividends payable. Net Debt is a non-GAAP measure – see “Advisory Regarding Non-GAAP Measures – Non-Gap measures” advisory. | |
| (3) | Fully diluted shares outstanding as at December 31, 2022. |
Q4 2022 and Full Year 2022 Financial Results Conference Call
Fourth quarter and full year 2022 results are expected to be released before market open on March 8, 2023. A conference call has been scheduled for March 8, 2023 at 10:00 a.m Mountain Time (12:00 p.m Eastern Time) for interested investors, analysts, brokers, and media representatives.
Conference Call Details:
Please use the following participant URL to register for the Q4 2022 financial results conference call: https://register.vevent.com/register/BIf2529ca87a7949c8bece6d62670b175b. This registration link can also be found on the Company’s website. This link will provide each registrant with a toll-free dial-in number and a unique PIN to connect to the call.
Pipestone Energy Corp.
Pipestone is an oil and gas exploration and production company focused on developing its large contiguous and condensate rich Montney asset base in the Pipestone area near Grande Prairie. Pipestone is committed to building long term value for our shareholders while maintaining the highest possible environmental and operating standards, as well as being an active and contributing member to the communities in which it operates. Pipestone has achieved certification of all its production from its Montney asset under the Equitable Origin EO100TM Standard for Responsible Energy Development. Pipestone shares trade under the symbol PIPE on the TSX. For more information, visit www.pipestonecorp.com.
Pipestone Energy Contacts:
| Paul Wanklyn President and Chief Executive Officer (587) 392-8407 paul.wanklyn@pipestonecorp.com |
Craig Nieboer Chief Financial Officer (587) 392-8408 craig.nieboer@pipestonecorp.com |
| Dan van Kessel VP Corporate Development (587) 392-8414 dan.vankessel@pipestonecorp.com |
Advisory Regarding Non-GAAP Measures
Non-GAAP measures
This press release includes references to financial measures commonly used in the oil and natural gas industry. The terms ”adjusted funds flow from operations”, “free cash flow”, “operating netback”, “net debt”, “NAVPS” and “recycle ratio” are not defined under IFRS, which have been incorporated into Canadian GAAP, as set out in Part 1 of the Chartered Professional Accountants Canada Handbook – Accounting, are not separately defined under GAAP, and may not be comparable with similar measures presented by other companies. The reconciliations of these non-GAAP measures to the nearest GAAP measure are discussed in the MD&A dated November 9, 2022, a copy of which is available electronically on Pipestone’s SEDAR profile at www.sedar.com.
Management of the Company believes the presentation of non-GAAP measures and non-GAAP ratios provides useful information to investors and shareholders as the measures provide increased transparency and the opportunity to better analyze and compare performance against prior periods.
Adjusted funds flow from operations
“Adjusted funds flow from operations” is a non-GAAP measure that is calculated as cash from operating activities before changes in non-cash working capital, cash share-based compensation and decommissioning provision costs incurred, if applicable and is not defined under IFRS. Adjusted funds flow from operations should not be considered an alternative to, or more meaningful than, cash from operating activities, income (loss) or other measures determined in accordance with IFRS as an indicator of the Company’s performance. Management uses adjusted funds flow from operations to analyze operating performance and leverage and believes it is a useful supplemental measure as it provides an indication of the funds generated by Pipestone Energy’s principal business activities prior to consideration of changes in working capital, cash share-based compensation and decommissioning provision costs incurred.
Free cash flow
“Free cash flow” is a non-GAAP measure that is calculated as cash from operating activities plus the change in non-cash working capital and cash share-based compensation less capital expenditures, and is not defined under IFRS. Free cash flow should not be considered an alternative to, or more meaningful than, cash from operating activities as determined in accordance with IFRS as an indicator of financial performance. Free cash flow is presented to assist management of the Company and investors in analyzing operating performance by the business and how much cash flow is available for deleveraging and/or shareholder returns in the stated period after capital expenditures have been incurred.
Operating netback
“Operating netback” is a non-GAAP measure that is calculated on either a total dollar or per-unit-of-production basis and is determined by deducting royalties, operating and transportation expenses from liquids and natural gas sales adjusted for realized gains/losses on commodity risk management contracts.
Operating netback is a common metric used in the oil and natural gas industry and is used by the Company’s management to measure operating results on a per boe basis to better analyze and compare performance against prior periods, as well as formulate comparisons against peers. This measure should not be considered an alternative to or more meaningful than cash from operating activities as determined in accordance with IFRS as an indicator of financial performance.
Net debt
“Net debt” is a non-GAAP measure that equals bank debt outstanding plus adjusted working capital excluding dividends payable. Net debt is considered to be a useful measure in assisting management of the Company and investors to evaluate Pipestone’s financial strength.
Non-GAAP ratios
NAVPS
NAVPS is a non-GAAP ratio calculated as the before-tax NPV for 1P and 2P reserves discounted at 10%, less abandonment obligations, mark-to-market of hedges and net debt divided by the fully diluted common shares outstanding as at December 31, 2022. Net debt, a non-GAAP measure, is used as a component of the non-GAAP ratio. Management uses NAVPS as a measure to evaluate and compare its current share price to the net asset value per share of its Total Proved and Total Proved plus Probable reserves.
Recycle Ratio
Recycle ratio is a non-GAAP ratio calculated by dividing the operating netback, excluding realized hedging impacts, by the F&D cost per boe for the year. Operating netback, a non-GAAP measure, is used as a component of the non-GAAP ratio. Recycle ratio is considered to be a useful measure in the oil and gas industry which management uses to evaluate the efficiency of its capital program by comparing the Company’s operating netback to its F&D cost per boe for the year.
Advisory Regarding Forward-Looking Statements
In the interest of providing shareholders of Pipestone and potential investors information regarding Pipestone, this news release contains certain information and statements (“forward-looking statements”) that constitute forward-looking information within the meaning of applicable Canadian securities laws. Forward-looking statements relate to future results or events, are based upon internal plans, intentions, expectations and beliefs, and are subject to risks and uncertainties that may cause actual results or events to differ materially from those indicated or suggested therein. All statements other than statements of current or historical fact constitute forward-looking statements. Forward-looking statements are typically, but not always, identified by words such as “anticipate”, “estimate”, “expect”, “intend”, “forecast”, “continue”, “propose”, “may”, “will”, “should”, “believe”, “plan”, “target”, “objective”, “project”, “potential” and similar or other expressions indicating or suggesting future results or events.
Forward-looking statements are not promises of future outcomes. There is no assurance that the results or events indicated or suggested by the forward-looking statements, or the plans, intentions, expectations or beliefs contained therein or upon which they are based, are correct or will in fact occur or be realized (or if they do, what benefits Pipestone may derive therefrom).
In particular, but without limiting the foregoing, this news release contains forward-looking statements pertaining to: expected timing for filing Pipestone’s audited financial statements for the year ended December 31, 2022; the expectation that 26 net wells will be brought on stream in the first quarter of 2023; expectations regarding the resource potential in the Montney ‘B’ and Montney ‘D’ bench; expected timing for equipping and bringing the the 11-05 pad wells on production; expected timing for completing the 2-31 pad and the 2-25 pad and bringing them on-stream; and Pipestone’s plan to spud two planned delineation wells off the 11-09 pad and expected timing for frac operations. In addition, statements relating to reserves are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described can be profitably produced in the future.
With respect to the forward-looking statements contained in this news release, Pipestone has assessed material factors and made assumptions regarding, among other things: future commodity prices and currency exchange rates, including consistency of future oil, NGLs and natural gas prices with current commodity price forecasts; Pipestone’s continued ability to obtain qualified staff and equipment in a timely and cost-efficient manner; the predictability of future results based on past and current experience; the predictability and consistency of the legislative and regulatory regime governing royalties, taxes, environmental matters and oil and gas operations, both provincially and federally; Pipestone’s ability to successfully market its production of oil, NGLs and natural gas; the timing and success of drilling and completion activities (and the extent to which the results thereof meet expectations); Pipestone’s future production levels and amount of future capital investment, and their consistency with Pipestone’s current development plans and budget; future capital expenditure requirements and the sufficiency thereof to achieve Pipestone’s objectives; the successful application of drilling and completion technology and processes; the applicability of new technologies for recovery and production of Pipestone’s reserves and other resources, and their ability to improve capital and operational efficiencies in the future; the recoverability of Pipestone ‘s reserves and other resources; Pipestone’s ability to economically produce oil and gas from its properties and the timing and cost to do so; the performance of both new and existing wells; future cash flows from production; future sources of funding for Pipestone’s capital program, and its ability to obtain external financing when required and on acceptable terms; future debt levels; geological and engineering estimates in respect of Pipestone’s reserves and other resources; the accuracy of geological and geophysical data and the interpretation thereof; the geography of the areas in which Pipestone conducts exploration and development activities; the timely receipt of required regulatory approvals; the access, economic, regulatory and physical limitations to which Pipestone may be subject from time to time; and the impact of industry competition.
The forward-looking statements contained herein reflect management of the Company’s current views, but the assessments and assumptions upon which they are based may prove to be incorrect. Although Pipestone believes that its underlying assessments and assumptions are reasonable based on currently available information, undue reliance should not be placed on forward-looking statements, which are inherently uncertain, depend upon the accuracy of such assessments and assumptions, and are subject to known and unknown risks, uncertainties and other factors, both general and specific, many of which are beyond Pipestone’s control, that may cause actual results or events to differ materially from those indicated or suggested in the forward-looking statements. Such risks and uncertainties include, but are not limited to, volatility in market prices and demand for oil, NGLs and natural gas and hedging activities related thereto; the ability to successfully manage the Company’s operations; general economic, business and industry conditions; variance of Pipestone’s actual capital costs, operating costs and economic returns from those anticipated; the ability to find, develop or acquire additional reserves and the availability of the capital or financing necessary to do so on satisfactory terms; and the availability of sufficient natural gas processing capacity; and risks related to the exploration, development and production of oil and natural gas reserves. Additional risks, uncertainties and other factors are discussed in the MD&A dated November 9, 2022 and in Pipestone’s annual information form dated March 9, 2022, copies of which are available electronically on Pipestone’s SEDAR at www.sedar.com.
The forward-looking statements contained in this news release are made as of the date hereof and Pipestone assumes no obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, unless required by applicable securities laws. All forward-looking statements herein are expressly qualified by this advisory.
Advisories Regarding Oil and Gas Information
Basis of Barrel of Oil Equivalent
Petroleum and natural gas reserves and production volumes are stated as a “barrel of oil equivalent” (boe), derived by converting natural gas to oil equivalency in the ratio of 6,000 cubic feet of gas to one barrel of oil. Readers are cautioned that boe figures may be misleading, particularly if used in isolation. A boe conversion ratio of 6,000 cubic feet of gas to one barrel of oil is based on energy equivalency, which is primarily applicable at the burner tip, and does not represent a value equivalency at the wellhead.
Initial Production Rates and Short-Term Test Rates
Any references in this news release to test rates of production or initial production rates for certain wells over short periods of time (i.e. IP90 and other short-term periods), are preliminary and not determinative of the rates at which those or any other wells will commence production and thereafter decline. Short-term test rates are not necessarily indicative of long-term well or reservoir performance or of ultimate recovery. Although such rates are useful in confirming the presence of hydrocarbons, they are preliminary in nature, are subject to a high degree of predictive uncertainty as a result of limited data availability and may not be representative of stabilized on-stream production rates. Initial production rates indicate the average daily production over the indicated daily period.
Production over a longer period will also experience natural decline rates, which can be high in the Montney play and may not be consistent over the longer term with the decline experienced over an initial production period. Initial production or test rates may also include recovered “load” fluids used in well completion stimulation operations. Actual results will differ from those realized during an initial production period or short-term test period, and the difference may be material. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for Pipestone. Accordingly, Pipestone cautions that the test results should be considered to be preliminary.
Production
References to natural gas and condensate production in this news release refer to the shale gas and natural gas liquids (which includes condensate), respectively, product types as defined in National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities. References to liquids include tight oil and NGLs (including condensate, butane and propane).
CGR
Any references herein to “CGR” mean condensate/gas ratio and is expressed as a volume of condensate (expressed in barrels) per million cubic feet (mmcf) of natural gas.
F&D Costs
The calculation of F&D costs includes all exploration and development capital for the year plus the change in future development capital for the year. This total capital including the change in future development capital is divided by the change in reserves for the year.
Abbreviations
The following summarizes the abbreviations used in this document:
| Crude Oil, Condensate and other Natural Gas Liquids and Natural Gas | |||
| bbl | barrel | MMboe | Million barrels of oil equivalent |
| bbls/d | barrels per day | NGL | natural gas liquids, consisting of ethane (C2), propane (C3) and butane (C4) |
| boe | barrel of oil equivalent | condensate | Pentanes plus (C5+) separated at the field level and C5+ separated from the NGL mix at the facility level |
| boe/d | barrel of oil equivalent per day | Mcf | thousand cubic feet |
| GJ | Gigajoule; 1 Mcf of natural gas is about 1.05 GJ | MMcf | million cubic feet |
| Mboe | thousand barrels of oil equivalent | MMcf/d | million cubic feet per day |
| Mboe/d | thousand barrels of oil equivalent per day | ||
| Other Abbreviations |
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| adjusted working capital | working capital (current assets less current liabilities), excluding financial derivative instruments and lease liabilities | ||
| C$ | Canadian dollars | ||
| GAAP | generally accepted accounting principles | ||
| IFRS | International Financial Reporting Standards | ||
| Q1 | first quarter ended March 31st | ||
| Q2 | second quarter ended June 30th | ||
| Q3 | third quarter ended September 30th | ||
| Q4 | fourth quarter ended December 31st | ||
| TSX | Toronto Stock Exchange | ||
| US$ | United States dollars | ||
| WTI | West Texas Intermediate | ||
