CALGARY, Alberta, Aug. 03, 2023 (GLOBE NEWSWIRE) -- Hammerhead Energy Inc. (“Hammerhead” or the “Company”) (TSX: HHRS, HHRS.WT; NASDAQ: HHRS, HHRSW) is pleased to announce financial and operating results for the second quarter of 2023. During the quarter, the Company continued to execute on a two-rig program targeting Montney light oil growth in its three core areas (North Karr, South Karr and Gold Creek). The Company continues to progress critical infrastructure expansions which are on target to increase production capacity to over 80,000 boe/d. Operational cadence and execution during the quarter yielded significant and repeatable capital efficiency gains. Hammerhead’s development program is targeting oil-weighted assets that continue to demonstrate productive capability and returns at levels among the strongest in North America.
To date, Hammerhead production operations have not been materially impacted by the wildfires in Alberta. While they did create minor impacts affecting regional facility performance and liquids recoveries, the Company experienced no material production downtime and corporate guidance for 2023 remains unchanged.
Scott Sobie, President and CEO of Hammerhead, notes “Hammerhead continues to deliver peer-leading production and cash flow per share growth to date in 2023. The Company is executing operationally in what continues to prove to be best in class assets in terms of rock quality and production of Montney light oil. The depth and breadth of Hammerhead’s inventory of light oil prospects is complemented by infrastructure investments that have allowed us to drive lower lifting costs while maintaining complete operational control. South Karr is a very exciting expansion for the Company through the second half of 2023, and Lower Montney delineation continues, creating the potential for further increases to liquids leverage. We expect to see an inflection point in free cash flow generation in the second half of 2023. It is the current intention of the Company to introduce a robust shareholder return strategy beginning in 2024, subject to approval by Hammerhead’s Board of Directors.”
Second Quarter 2023 Highlights:
- Produced 39,009 boe/d (46% liquids)1 representing 15% growth on a year over year (“y-o-y”) basis. Crude oil production of 13,389 bbl/d in the quarter represents 34% growth on a y-o-y basis. Average quarterly production included the effect of approximately 800 boe/d of planned midstream maintenance at Gold Creek.
- Generated adjusted funds from operations2 of $103.5 million, representing a corporate netback3 of $29.16/boe which reflects outstanding natural gas pricing realizations due to the Company’s hedging and marketing strategy for natural gas. Adjusted funds from operations declined 14% on a y-o-y basis, largely a function of the reduction in oil and natural gas prices. Net cash from operating activities for the quarter was $75.9 million.
- Continued a two-rig development program with quarterly capital expenditures4 and net cash used in investing activities of $95.3 million and $132.3 million, respectively. The capital program included (i) the drilling of 10.0 gross (10.0 net), completion of seven gross (seven net), and on-stream of seven gross (seven net) Montney crude oil wells, (ii) continued investments in new surface infrastructure at Karr, and (iii) new water disposal wells throughout the land base.
- The recent nine-well pad at North Karr 5-12 continues to materially exceed performance expectations, establishing an average well IP180 of 1,542 boe/d (56% liquids)5 and resulting in a pad payout6 of four months. An additional 12-well pad at North Karr 10-14 was drilled in the quarter and is expected to be brought on-stream ahead of schedule in Q3 as a result of operational execution ahead of expectations. Subsequent to quarter end, in early July, completions on the 12 wells were also finished ahead of schedule and below budget. The Upper Montney wells on short duration clean-up test (24-72 hours) demonstrated flowback results that are in-line with our recent nine-well pad at North Karr 5-12. The two benches in the Upper Montney tested on average at 1,447 boe/d (1.9 mmcf/d raw natural gas, 1,131 bbls/d crude oil) which exceeds our type curve (six wells) and 916 boe/d (1.9 mmcf/d raw natural gas, 601 bbls/d crude oil), respectively, which is in-line with our type curve (six wells). At North Karr, 100% owned water disposal capability was expanded through the drilling and on-stream of two additional water disposal wells. Initial disposal rates are significantly ahead of expectations and since late June 2023, the wells have accommodated the full on-stream of the seven-well pad at North Karr 13-14. The seven-well pad at North Karr 13-14 drilled significantly faster than planned and has recently been brought on production after completing facility construction. These wells continue to clean up and are expected to deliver type curve EUR.
- The recently completed seven-well pad at Gold Creek 04-14 was tied in to existing infrastructure during the quarter and is producing at rates that are in-line with type curve expectations.
- Capital efficiency gains continued at North Karr as the Company is rapidly reducing well costs and improving cycle times. North Karr wells originally budgeted at 19 days are currently being drilled in an average of 13 days across the newly drilled 12-well pad at North Karr 10-14. Well costs at North Karr have been consistently coming in at less than $10.0 million DCET per well compared to type well cost of $10.6 million, and Hammerhead expects the latest 12-well pad to deliver average well costs under $9.0 million.
- At South Karr, greenfield infrastructure build-out remains on track to be on-stream in the fourth quarter. As a result of the North Karr drilling outperformance, new drilling activity has commenced ahead of schedule on the South Karr 5-11 nine-well pad which will include our most recent activity in the Lower Montney. Wells are expected to be ready for production in conjunction with the completion of the South Karr infrastructure.
- The Company exited the quarter with net debt7 of $388.6 million and a net debt to annualized adjusted EBITDA ratio8 of 0.9 times. Hammerhead’s net debt is expected to peak in late Q3 2023 or early Q4 2023 and fall thereafter as major infrastructure spending is completed.
- During the quarter, the Company purchased and cancelled 12,852,235 warrants to purchase Class A common shares (“Common Shares”) of the Company (“Warrants”) at an aggregate purchase price of US$12,852,235, or US$1.00 per Warrant, representing approximately 45% of the previously outstanding Warrants. At the option of Hammerhead, the remaining 15,697,756 Warrants may be redeemed at a price of US$0.10 per Warrant, upon at least 30 days' prior written notice, if, among other things, the last reported sales price of the Common Shares equals or exceeds US$10.00 per Common Share on the trading day prior to the date on which notice of the redemption is given. In such a case, Warrantholders will be able to exercise their Warrants prior to the date of redemption for a number of Common Shares determined in accordance with the Amended and Restated Warrant Agreement among Hammerhead, Computershare Inc. and Computershare Trust Company, N.A. dated February 22, 2023 (the "Warrant Agreement"). At this time, the Warrants are not redeemable and Hammerhead has not issued a notice of redemption. For further information regarding the terms of the remaining Warrants and the Warrant Agreement, see Hammerhead's Tender Offer Statement on Schedule TO, as amended, including the offer to purchase and accompanying issuer bid circular dated April 27, 2023, filed by Hammerhead on EDGAR with the U.S. Securities and Exchange Commission at www.sec.gov and with the applicable securities regulatory authorities in Canada under Hammerhead's SEDAR+ profile at www.sedarplus.ca.
- See "Reader Advisory - Oil and Gas" for such production by product type.
- Adjusted funds from operations is a non-GAAP financial measure which does not have any standardized meaning under International Financial Reporting Standards ("IFRS") and may not be comparable with similar measures presented by other entities. The most directly comparable generally accepted accounting principles ("GAAP") measure is net cash from operating activities. See "Non-GAAP and Other Financial Measures Advisory" for more information.
- Corporate netback per boe is a non-GAAP financial ratio which does not have any standardized meaning under IFRS and may not be comparable with similar measures presented by other entities. The most directly comparable GAAP measure is net cash from operating activities per boe. See "Non-GAAP and Other Financial Measures Advisory" for more information.
- Capital expenditures is a non-GAAP financial measure which does not have any standardized meaning under IFRS and may not be comparable with similar measures presented by other entities. The most directly comparable GAAP measure is net cash used in investing activities. See "Non-GAAP and Other Financial Measures Advisory" for more information.
- See "Reader Advisory - Oil and Gas" for such production by product type.
- Payout is an oil and gas metric that is calculated as the amount of time it takes for production from a well to fully pay for DCET capital.
- Net debt is a capital management measure. See "Non-GAAP and Other Financial Measures Advisory" for more information.
- Net debt to annualized adjusted EBITDA is a capital management measure. See "Non-GAAP and Other Financial Measures Advisory" for more information.
Reaffirming 2023 Corporate Outlook and Guidance
Based on results to date, Hammerhead remains well positioned to deliver on its 2023 annual guidance. Hammerhead is reaffirming its 2023 overall annual guidance as outlined below:
| Forward-looking information1 | Q2 results | H1 results | 2023 annual guidance2 | |
| Average production3 | boe/d | 39,009 | 39,498 | 40,200 |
| Crude oil4 | % | 34 | 36 | 33 |
| Natural gas liquids (“NGLs”) | % | 12 | 10 | 12 |
| Natural gas4 | % | 54 | 54 | 55 |
| Expenses | ||||
| Royalties | % | 10 | 11 | 13 |
| Operating | $/boe | 9.51 | 8.90 | 8.50 |
| Transportation | $/boe | 5.77 | 5.80 | 6.50 |
| Net general and administrative | $/boe | 2.73 | 2.49 | 1.60 |
| Cash interest and financing | $/boe | 1.75 | 1.45 | 1.40 |
| Cash taxes | $/boe | - | - | - |
| Capital expenditures5 | $MM | 95 | 268 | 525 |
- Forward looking information are not guarantees of future performance and involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated with forward looking information. See "Forward-Looking Statements" for more information.
- The Company's 2023 annual guidance is unchanged from the guidance previously announced on March 28, 2023 in the Company's 2022 management’s discussion and analysis for the year-ended December 31, 2022, and accompanying press release.
- See "Reader Advisory – Oil and Gas" for such production by product type.
- References in the table above to crude oil refer to the tight oil product type, and references to natural gas refer to the shale gas product type.
- See "Non-GAAP and Other Financial Measures Advisory" for more information.
Hedging
As at June 30, 2023, the Company held the following outstanding risk management contracts:
| Remaining Term | Reference | Total Daily Volume (bbls/d) | Weighted Average (Price/bbls) |
| Crude Oil Swaps | |||
| Jul 1, 2023 – Sep 30, 2023 | US$ WTI | 7,000 | 75.28 |
| Jul 1, 2023 – Dec 31, 2023 | US$ WTI | 1,100 | 65.00 |
| Remaining Term | Reference | Total Daily Volume (GJ/d) | Total Daily Volume (MMbtu/d) | Weighted Average (CDN$/GJ) | Weighted Average (US$/MMbtu) | |
| Natural Gas Swaps | ||||||
| Jul 1, 2023 - Sep 30, 2023 | CDN$ AECO | 30,000 | — | 4.96 | — | |
| Jul 1, 2023 - Dec 31, 2023 | US$ AECO - NYMEX | — | 30,000 | — | (1.48 | ) |
| Natural Gas Collar | ||||||
| Jul 1, 2023 - Dec 31, 2023 | US$ NYMEX | — | 30,000 | — | 5.00 - 9.80 | |
Complete Quarterly Filings
Hammerhead has filed its quarterly report on Form 6-K on EDGAR at www.sec.gov and the Company's second quarter 2023 unaudited financial statements and management’s discussion and analysis ("Q2 2023 MD&A") on SEDAR+ at www.sedarplus.ca, along with posting these documents on its website www.hhres.com.
Operational and Financial Summary
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||
| (Cdn$ thousands, except per share amounts, production and unit prices) | 2023 | 2022 | % Change | 2023 | 2022 | % Change | |||
| Production volumes1 | |||||||||
| Crude oil (bbls/d) | 13,389 | 10,025 | 34 | 14,097 | 9,950 | 42 | |||
| Natural gas (Mcf/d) | 126,349 | 116,667 | 8 | 126,833 | 115,193 | 10 | |||
| Natural gas liquids (bbls/d) | 4,561 | 4,397 | 4 | 4,261 | 4,215 | 1 | |||
| Total (boe/d) | 39,009 | 33,867 | 15 | 39,498 | 33,363 | 18 | |||
| Liquids weighting % | 46 | 43 | 46 | 42 | |||||
| Oil and gas revenue ($/boe) | 48.19 | 81.09 | (41 | ) | 54.29 | 72.77 | (25 | ) | |
| Operating netback ($/boe)2 | 33.64 | 41.75 | (19 | ) | 36.44 | 39.04 | (7 | ) | |
| Oil and gas revenue | 171,072 | 249,908 | (32 | ) | 388,126 | 439,450 | (12 | ) | |
| Operating netback3 | 119,437 | 128,673 | (7 | ) | 260,460 | 235,781 | 10 | ||
| Net cash from operating activities | 75,855 | 129,623 | (41 | ) | 191,396 | 200,086 | (4 | ) | |
| Per common share – basic4 | 0.83 | 5.19 | (84 | ) | 2.68 | 8.01 | (67 | ) | |
| Per common share – diluted4 | 0.79 | 2.08 | (62 | ) | 2.68 | 3.24 | (17 | ) | |
| Adjusted funds from operations5 | 103,515 | 119,906 | (14 | ) | 232,309 | 220,370 | 5 | ||
| Per common share – basic4,6 | 1.14 | 4.80 | (76 | ) | 3.26 | 8.82 | (63 | ) | |
| Per common share – diluted4,6 | 1.08 | 1.92 | (44 | ) | 3.26 | 3.57 | (9 | ) | |
| Corporate netback ($/boe) 5 | 29.16 | 38.91 | (25 | ) | 32.50 | 36.49 | (11 | ) | |
| Net profit (loss) | 20,743 | 96,993 | (79 | ) | (112,916 | ) | 90,551 | N/A | |
| Net profit (loss) attributable to ordinary equity holders | 20,743 | 90,825 | (77 | ) | (117,006 | ) | 78,500 | N/A | |
| Per common share – basic4 | 0.23 | 3.63 | (94 | ) | (1.64 | ) | 3.14 | N/A | |
| Per common share – diluted4 | 0.22 | 1.46 | (85 | ) | (1.64 | ) | 1.27 | N/A | |
| Net cash used in investing activities | 132,309 | 68,414 | 93 | 274,632 | 163,928 | 68 | |||
| Capital expenditures5 | 95,266 | 50,387 | 89 | 267,708 | 132,875 | 101 | |||
| Free funds flow7 | 8,195 | 69,519 | (88 | ) | (35,453 | ) | 87,372 | N/A | |
| Weighted average common shares outstanding 8 | |||||||||
| Basic 4 | 91,000 | 24,996 | 264 | 71,306 | 24,995 | 185 | |||
| Diluted 4 | 96,206 | 62,345 | 54 | 71,306 | 61,741 | 15 | |||
| As at | |||||||||
| FINANCIAL | June 30, 2023 | December 31, 2022 | % Change | ||||||
| Adjusted working capital deficit9 | 30,824 | 32,915 | (6 | ) | |||||
| Available funding10 | 43,184 | 309,985 | (86 | ) | |||||
| Net debt5 | 388,606 | 291,647 | 33 | ||||||
- See "Reader Advisory – Oil and Gas" for such production by product type.
- Operating netback per boe is a non-GAAP financial ratio which does not have any standardized meaning under IFRS and may not be comparable with similar measures presented by other entities. The most directly comparable GAAP measure is oil and gas revenue per boe. See “Non-GAAP and Other Financial Measures Advisory” for more information.
- Operating netback is a non-GAAP financial measure which does not have any standardized meaning under IFRS and may not be comparable with similar measures presented by other entities. The most directly comparable GAAP measure is oil and gas revenue. See “Non-GAAP and Other Financial Measures Advisory” for more information.
- In comparative periods, per common share amounts are Hammerhead Resources Inc. The weighted average common shares outstanding in these periods has been scaled by the applicable exchange ratio following the completion of the business combination with Decarbonization Plus Acquisition Corporation IV.
- See “Non-GAAP and Other Financial Measures Advisory” for more information.
- Adjusted funds from operations per share - basic and per share - diluted are non-GAAP financial ratios which do not have any standardized meaning under IFRS and may not be comparable with similar measures presented by other entities. The most directly comparable GAAP measure is net cash from operating activities per share - basic and per share - diluted. See “Non-GAAP and Other Financial Measures Advisory” for more information.
- Free funds flow is a non-GAAP financial measure which does not have any standardized meaning under IFRS and may not be comparable with similar measures presented by other entities. The most directly comparable GAAP measure is net cash from operating activities. See “Non-GAAP and Other Financial Measures Advisory” for more information.
- The Company has 91,076,480 HEI Common Shares, 15,697,756 HEI Warrants, 5,052,777 Legacy RSUs, 650,495 Legacy Options, and 1,945,115 RSAs issued and outstanding as of the date of this press release.
- Adjusted working capital deficit is a capital management measure. See “Non-GAAP and Other Financial Measures Advisory” for more information.
- Available funding is a non-GAAP financial measure which does not have any standardized meaning under IFRS and may not be comparable with similar measures presented by other entities. The most directly comparable GAAP measure is working capital deficit. See “Non-GAAP and Other Financial Measures Advisory” for more information.
About Hammerhead Energy Inc.
Hammerhead is a Calgary, Canada-based energy company, with assets and operations in Alberta targeting the Montney formation. Hammerhead Resources Inc., the predecessor entity to Hammerhead Resources ULC, a wholly owned subsidiary of Hammerhead, was formed in 2009.
Contacts:
For further information, please contact:
Scott Sobie
President & CEO
Hammerhead Energy Inc.
403-930-0560
Mike Kohut
Senior Vice President & CFO
Hammerhead Energy Inc.
403-930-0560
Kurt Molnar
Vice President Capital Markets & Corporate Planning
Hammerhead Energy Inc.
403-930-0560
Reader Advisory
Currency
All amounts in this press release are stated in Canadian dollars unless otherwise specified.
Forward Looking Statements
Certain information contained herein may constitute forward-looking statements and information (collectively, “forward-looking statements”) within the meaning of applicable securities legislation, including Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, that involve known and unknown risks, assumptions, uncertainties and other factors. Undue reliance should not be placed on any forward-looking statements. Forward-looking statements may be identified by words like “anticipates”, “estimates”, “expects”, “indicates”, “forecast”, “intends”, “may”, “believes”, “could”, “should”, “would”, “plans”, “proposed”, “potential”, “will”, “target”, “approximate”, “continue”, “might”, “possible”, “predicts”, “projects” and similar expressions, but the absence of these words does not mean that a statement is not forward-looking. Forward-looking statements in this press release include but are not limited to: the Company's assessment of future plans, operations and strategies; expectations for 2023 and benefits to be derived therefrom; the Company's 2023 capital program and drilling plans; the expected additional infrastructure expansion at South Karr, including the capacity and the anticipated timing thereof; production from the South Karr well pad and anticipated timing thereof; anticipated average well costs; the Company's 2023 corporate outlook and guidance, including anticipated production, royalties, operating costs, transportation costs, net general and administrative costs, cash interest and financing costs, cash taxes and capital expenditures; the greenfield infrastructure build-out and the anticipated timing and benefits thereof; the Company's ability to redeem the Warrants; the Company's plans to concentrate its development activities in certain of its operating areas and the Company’s expectation to deliver on its 2023 guidance; the performance of the North Karr wells; the focus of the Company's operations and the Company's drilling plans and targets and the timing thereof; anticipated well performance; the Company's expectations regarding in-field infrastructure capability by the end of 2023; the Company’s expectation for net debt to peak in late Q3 2023 or early Q4 2023; the Company's expectations regarding free cash flow generation and seeing an inflection point in free cash flow generation including the anticipated timing thereof; the Company's intention to implement a robust shareholder return strategy and the anticipated timing thereof; the Company's expected production growth; the Company's general strategy for its business and assets; and other matters related to the foregoing.
Such forward-looking statements reflect the current views of the Company with respect to future events and are subject to certain risks, uncertainties and assumptions that could cause results to differ materially from those expressed in the forward-looking statements. These risks and uncertainties include but are not limited to: the impact of general economic conditions; volatility in market prices for crude oil and natural gas; industry conditions; currency fluctuations; imprecision of reserve estimates; liabilities inherent in crude oil and natural gas operations; environmental risks; incorrect assessments of the value of acquisitions and exploration and development programs; the lack of availability of qualified personnel, drilling rigs or other services; changes in income tax laws or changes in royalty rates and incentive programs relating to the oil and gas industry including abandonment and reclamation programs; hazards such as fire, explosion, blowouts, and spills, each of which could result in substantial damage to wells, production facilities, other property and the environment or in personal injury; the Company's ability to access sufficient capital from internal and external sources; Hammerhead’s success in retaining or recruiting, or changes required in, its officers, key employees or directors; litigation and regulatory enforcement risks, including the diversion of management time and attention and the additional costs and demands on the Company's resources; the ability of the Company to execute its business plan; general economic and business conditions; the risks of the oil and natural gas industry, such as operational risks in exploring for, developing and producing crude oil and natural gas and market demand; pricing pressures and supply and demand in the oil and gas industry; fluctuations in currency and interest rates; inflation; risks of war, hostilities, civil insurrection, pandemics and epidemics, and general political and economic instability (including the ongoing Russian-Ukrainian conflict); severe weather conditions, including risks related to Alberta’s wildfires, and risks related to climate change; terrorist threats; risks associated with technology; changes in laws and regulations, including environmental, regulatory and taxation laws, and the application of such changes to the Company's future business; availability of adequate levels of insurance; difficulty in obtaining necessary regulatory approvals and the maintenance of such approvals; risk that the Company's 2023 capital program and drilling plans are different than anticipated; risk that the Company's net debt does not peak on the timing anticipated; risk that the anticipated timing of a new facility being brought on-steam is delayed; risk that the Company does not generate material free cash flow and is unable to return cash flow to shareholders or implement a shareholder return strategy on the timing anticipated or at all; and risk that the Company's 2023 corporate outlook and guidance, including anticipated production, royalties, operating costs, transportation costs, net general and administrative costs, cash interest and financing costs, cash taxes and capital expenditures is different than anticipated. Readers are cautioned that the foregoing list is not exhaustive of all possible risks and uncertainties.
With respect to forward-looking statements contained in this press release, the Company has made assumptions regarding, among other things: availability of future acquisition opportunities; future capital expenditure levels; future oil and natural gas prices; future oil and natural gas production levels; future currency exchange rates and interest rates; ability to obtain equipment and services in a timely manner to carry out development activities; ability to market oil and natural gas successfully to current and new customers; the impact of competition; the general stability of the economic and political environments in which the Company operates; the timely receipt of any required regulatory approvals; the ability of the Company to obtain qualified staff, equipment and services in a timely and cost efficient manner; that the Company will have sufficient cash flow, debt or equity sources or other financial resources required to fund its capital and operating expenditures and requirements as needed; that the Company's conduct and results of operations will be consistent with its expectations; that the Company will have the ability to develop its oil and gas properties in the manner currently contemplated; the estimates of the Company's reserves and production volumes and the assumptions related thereto (including commodity prices and development costs) are accurate in all material respects; the Company’s ability to add production and reserves through development and exploration activities; and other matters. Although the Company believes that the expectations reflected in the forward-looking statements contained in this press release, and the assumptions on which such forward-looking statements are made, are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned that the foregoing list is not an exhaustive list of all assumptions which have been considered.
Management has included the above summary of assumptions and risks related to forward-looking information provided in this document in order to provide shareholders with a more complete perspective on the Company's current and future operations and such information may not be appropriate for other purposes. the Company's actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do, what benefits the Company will derive. The forward-looking statements contained in this press release speak only as of the date of this press release. Accordingly, forward-looking statements should not be relied upon as representing Hammerhead’s views as of any subsequent date, and except as expressly required by applicable securities laws, Hammerhead does not undertake any obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.
Hammerhead's future shareholder returns, if any, and the level thereof is uncertain. Any decision to return cash flow to shareholders will be subject to the discretion of the board of directors of Hammerhead and may depend on a variety of factors, including, without limitation, Hammerhead's business performance, financial condition, financial requirements, growth plans, expected capital requirements and other conditions existing at such future time including, without limitation, contractual restrictions and satisfaction of the solvency tests imposed on Hammerhead under applicable corporate law. Further, the actual amount and timing of any shareholder returns are subject to the discretion of the board of directors of Hammerhead. There can be no assurance that Hammerhead will make any returns to shareholders.
This press release contains information that may be considered a financial outlook under applicable securities laws about the Company's potential financial position, including, but not limited to, the Company's 2023 anticipated royalties, operating costs, transportation costs, net general and administrative costs, cash interest and financing costs, cash taxes and capital expenditures and the Company's net debt, all of which are subject to numerous assumptions, risk factors, limitations and qualifications, including those set forth in the above paragraphs. The actual results of operations of the Company and the resulting financial results will vary from the amounts set forth in this press release and such variations may be material. This information has been provided for illustration only and with respect to future periods are based on budgets and forecasts that are speculative and are subject to a variety of contingencies and may not be appropriate for other purposes. Accordingly, these estimates are not to be relied upon as indicative of future results. Except as required by applicable securities laws, the Company undertakes no obligation to update such financial outlook. The financial outlook contained in this press release was made as of the date of this press release and was provided for the purpose of providing further information about the Company's potential future business operations. Readers are cautioned that the financial outlook contained in this press release is not conclusive and is subject to change.
Oil and Gas
The Company’s aggregate production for the selected periods below, and the references to “natural gas”, “crude oil" and "NGLs”, reported in this press release consist of shale gas, tight oil and natural gas liquid product types, respectively, as defined in National Instrument 51-101 and using a conversion ratio of 6 mcf : 1 bbl where applicable:
| Q2 2023 | Q2 2022 | H1 2023 | |
| Tight oil (bbls/d) | 13,389 | 10,025 | 14,097 |
| Shale gas (Mcf/d) | 126,349 | 116,667 | 126,833 |
| Natural gas liquids (bbls/d) | 4,561 | 4,397 | 4,261 |
| Total (boe/d) | 39,009 | 33,867 | 39,498 |
Nine-well pad at North Karr 5-12:
| IP180 | |
| Tight oil (bbls/d) | 708 |
| Shale gas (Mcf/d) | 4,109 |
| Natural gas liquids (bbls/d) | 149 |
| Total (boe/d) | 1,542 |
Oil and Gas Metrics
This press release contains certain oil and gas metrics, including operating netback, EUR, payout and DCET capital, which do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies and should not be used to make comparisons. Such metrics have been included in this document to provide readers with additional measures to evaluate the Company's performance; however, such measures are not reliable indicators of the Company's future performance and future performance may not compare to the Company's performance in previous periods and therefore such metrics should not be unduly relied upon. DCET includes all capital spent to drill, complete equip and tie-in a well. EUR represents the estimated ultimate recovery of resources associated with the applicable type curve prepared by management of Hammerhead. Payout means the anticipated years of production from a well required to fully pay for the DCET of such well. Management uses these oil and gas metrics for its own performance measurements and to provide security holders with measures to compare the Company's operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this news release, should not be relied upon for investment or other purposes.
In this press release, Hammerhead references certain type curves and well economics which are based on Hammerhead's historical production. Such type curves and well economics are useful in understanding management's assumptions of well performance in making investment decisions in relation to development drilling in certain areas and for determining the success of the performance of wells; however, such type curves and well economics are not necessarily determinative of the production rates and performance of existing and future wells and such type curves do not reflect the type curves used by Hammerhead's independent qualified reserves evaluator in estimating Hammerhead's reserves volumes. The type curves can differ as a result of varying horizontal well length, stage count and stage spacing. The type curves represent the average type curves expected. In this press release, EUR represents the estimated ultimate recovery associated with the type curves prepared by management of Hammerhead; however, there is no certainty that Hammerhead will ultimately recover such volumes from the wells it drills.
References to initial production test rates (IP180), “short duration clean up tests” and "peak rates" are useful in confirming the presence of hydrocarbons; however, such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long-term performance or ultimate recovery. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for Hammerhead. Hammerhead has not conducted a pressure transient analysis or well-test interpretation on a subset of the wells referenced in this press release. As such, all data should be considered to be preliminary until such analysis or interpretation has been completed.
The term "Boe" means a barrel of oil equivalent on the basis of 6 Mcf of natural gas to 1 barrel of oil ("bbl"). Boe’s may be misleading, particularly if used in isolation. A boe conversation ratio of 6 Mcf: 1 bbl 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 the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion ratio at 6:1 may be misleading as an indication of value.
Abbreviations
The following is a list of abbreviations that may be used in this press release:
| bbl | barrel | AECO | AECO “C” hub price index for Alberta natural gas |
| bbls | barrels | Crude oil | Tight oil as defined in National Instrument 51-101 |
| bbls/d | barrels per day | Natural gas | Shale gas as defined in National Instrument 51-101 |
| boe | barrels of oil equivalent | GAAP | generally accepted accounting principles |
| boe/d | barrels of oil equivalent per day | WTI | West Texas Intermediate |
| Mcf | thousand cubic feet | CDN | Canadian |
| Mcf/d | thousand cubic feet per day | GJ | gigajoule |
| MMBoe | million barrels of oil equivalent | Legacy RSUs | Legacy Restricted Share Units |
| MMBtu | million British thermal units | RSAs | Restricted Share Awards |
| NGLs | Natural gas liquids | DCET | Drilling, Completion, Equipment & Tie-in |
| EUR | Estimated Ultimate Recovery |
Non-GAAP and Other Financial Measures Advisory
This press release includes certain meaningful performance measures commonly used in the oil and natural gas industry that are not defined under IFRS, as outlined below. These performance measures should not be considered in isolation or as a substitute for performance measures prepared in accordance with IFRS and should be read in conjunction with the consolidated financial statements. Readers are cautioned that these non-GAAP and capital management measures are not standardized financial measures under IFRS, and might not be comparable to similar financial measures disclosed by other entities. The non-GAAP and capital management measures used in this report are summarized as follows:
Non-GAAP Financial Measures
Capital Expenditures
Management uses capital expenditures to determine the amount of cash flow used for capital reinvestment and compare its capital expenditures to budget. The measure is comprised of additions to property, plant and equipment ("PP&E") per the consolidated statements of cash flows. See the following table for the reconciliation of capital expenditures to net cash used in investing activities, the most directly comparable GAAP measure.
| Three Months Ended June 30, | ||||
| (Cdn$ thousands) | 2023 | 2022 | ||
| Net cash used in investing activities | 132,309 | 68,414 | ||
| Net change in accounts payable related to the addition of PP&E | (37,043 | ) | (18,027 | ) |
| Capital expenditures | 95,266 | 50,387 | ||
Available Funding
The available funding measure allows management and other users to evaluate the Company’s short term liquidity, and its capital resources available at a point in time. Available funding is comprised of adjusted working capital, the undrawn component of Hammerhead’s Credit Facilities, plus the remaining equity commitment related to any outstanding investment agreements. Available funding reconciles to the capital management measure, adjusted working capital and its related balance sheet line items.
| (Cdn$ thousands) | June 30, 2023 | December 31, 2022 | ||
| Adjusted working capital deficit | (30,824 | ) | (32,915 | ) |
| Debt capacity | 74,008 | 170,200 | ||
| Equity commitment | — | 172,700 | ||
| Available funding | 43,184 | 309,985 | ||
Operating Netback
Operating netback is calculated by deducting royalties, operating expense, transportation expense, and realized gains (losses) from risk management contracts from oil and gas revenue. Management believes that operating netback is a key industry performance indicator to assess the profitability of the Company's developed and producing assets, and to provide investors with information that is also commonly presented by peers within the industry. See the following table for the reconciliation of operating netback to oil and gas revenue, the most directly comparable GAAP measure.
| Three Months Ended June 30, | ||||||
| (Cdn$ thousands) | 2023 | 2022 | % Change | |||
| Revenue | 171,072 | 249,908 | (32 | ) | ||
| Royalties | (16,572 | ) | (32,034 | ) | (48 | ) |
| Operating expense | (33,757 | ) | (28,503 | ) | 18 | |
| Net transportation expense | (20,481 | ) | (18,168 | ) | 13 | |
| Operating netback, excluding risk management contracts | 100,262 | 171,203 | (41 | ) | ||
| Realized gain (loss) on risk management contracts | 19,175 | (42,530 | ) | (145 | ) | |
| Operating netback | 119,437 | 128,673 | (7 | ) | ||
| Average Realized Prices | ||||||
| Crude oil and field condensate ($/bbl) | 96.09 | 137.14 | (30 | ) | ||
| Natural gas ($/Mcf)1 | 2.97 | 8.68 | (66 | ) | ||
| Natural gas liquids ($/bbl) | 47.93 | 81.56 | (41 | ) | ||
| Total ($/boe) | 48.19 | 81.09 | (41 | ) | ||
| (Cdn$ per boe) | ||||||
| Revenue2 | 48.19 | 81.09 | (41 | ) | ||
| Royalties2 | (4.67 | ) | (10.39 | ) | (55 | ) |
| Operating expense2 | (9.51 | ) | (9.25 | ) | 3 | |
| Net transportation expense2 | (5.77 | ) | (5.90 | ) | (2 | ) |
| Operating netback, excluding risk management contracts2 | 28.24 | 55.55 | (49 | ) | ||
| Realized gain (loss) on risk management contracts2 | 5.40 | (13.80 | ) | (139 | ) | |
| Operating netback per boe2 | 33.64 | 41.75 | (19 | ) | ||
- At the Company’s current heating value of 42.0 GJ/e3m3, 1 mcf of natural gas is approximately 1.18 GJ.
- Supplementary Financial Measure. See “Non-GAAP and Other Financial Measures Advisory” for more information.
Funds from Operations, Adjusted Funds from Operations and Free Funds Flow
Funds from operations is comprised of cash provided by operating activities, excluding the impact of changes in non-cash working capital and settlement of decommissioning obligations. Management believes excluding the changes in non-cash working capital provides a meaningful performance measure of the Company's operations on an ongoing basis, as it removes the impact of changes in timing of collections and payments, which are variable. Decommissioning provision costs incurred also vary depending upon the Company’s planned capital program and the maturity of operating areas requiring environmental remediation.
Adjusted funds from operations is funds from operations adjusted for other items that are not considered part of the long-term operating performance of the business. Management considers these measures to be key, as they demonstrate the Company's ability to generate the necessary funds to maintain production and fund future growth. Funds from operations and adjusted funds from operations as presented should not be considered an alternative to, or more meaningful than, cash flow from operating activities, net profits or other measures of financial performance calculated in accordance with IFRS.
Free funds flow is an indicator of the efficiency and liquidity of the business, and provides an indication of funds the Company has available for future capital allocation decisions such as the repayment of long-term debt. The measure is calculated as adjusted funds from operations less capital expenditures and settlement of decommissioning obligations.
The following table reconciles funds from operations, adjusted funds from operations and free funds flow to net cash from operating activities, which is the most directly comparable GAAP measure:
| Three Months Ended June 30, | ||||
| (Cdn$ thousands) | 2023 | 2022 | ||
| Net cash from operating activities | 75,855 | 129,623 | ||
| Changes in non-cash working capital | 27,538 | (8,038 | ) | |
| Realized foreign exchange loss on debt repayment | 196 | — | ||
| Settlement of decommissioning obligations | 54 | — | ||
| Funds from operations | 103,643 | 121,585 | ||
| Transaction costs | 94 | — | ||
| (Gain) loss on foreign exchange | (3,274 | ) | 4,720 | |
| Unrealized gain (loss) on foreign exchange | 3,346 | (4,460 | ) | |
| Other income, excluding transportation income | (294 | ) | (1,939 | ) |
| Adjusted funds from operations | 103,515 | 119,906 | ||
| Capital expenditures | (95,266 | ) | (50,387 | ) |
| Settlement of decommissioning obligations | (54 | ) | — | |
| Free funds flow | 8,195 | 69,519 | ||
Non-GAAP Financial Ratios
Operating Netback per boe
Management calculates operating netback per boe as operating netback divided by the Company's total production. Operating netback is a non-GAAP financial measure component of operating netback per boe. Management believes this performance measure provides key information about the profitability of the Company's developed and producing assets, isolated for the impact of changes in production volumes. Operating netback per boe is disclosed in the "Operational and Financial Summary" section within this press release.
Corporate Netback per boe and Adjusted Funds from Operations per Basic Share and Diluted Share
Corporate netback per boe (or adjusted funds from operations per boe) is calculated by dividing adjusted funds from operations by the Company's total production. Adjusted funds from operations per basic share and diluted share is calculated by dividing adjusted funds from operations by the Company's basic and diluted weighted average shares outstanding. Adjusted funds from operations is a non-GAAP financial measure component of adjusted funds from operations per boe, and adjusted funds from operations per basic share and diluted share.
Corporate netback per boe is utilized by management to assess the profitability of the Company's developed and producing assets, adjusted for items that are not considered part of the long-term operating performance of the business, and to compare current results to prior periods or to peers by isolating for the impact of changes in production volumes. Adjusted funds from operations per basic share and diluted share is utilized by management to indicate the funds generated from the business that could be allocated to each shareholder's equity position. Corporate netback per boe is disclosed in the "Highlights" section within this press release and adjusted funds from operations per basic share and diluted share are disclosed in the "Operational and Financial Summary" section within this press release.
Capital Management Measures
Adjusted EBITDA and Annualized Adjusted EBITDA
Adjusted EBITDA is calculated as net profit (loss) before interest and financing expenses, income taxes, depletion, depreciation and impairment, adjusted for certain non-cash items, or other items that are not considered part of normal business operations. Annualized adjusted EBITDA is adjusted EBITDA for the quarter, multiplied by four. Adjusted EBITDA indicates the Company's ability to generate funds from its asset base on a continuing and long-term basis, for future development of its capital program and settlement of financial obligations.
Adjusted EBITDA as presented should not be considered an alternative to, or more meaningful than, net profit (loss) before income tax, or other measures of financial performance calculated in accordance with IFRS. The following is a reconciliation of adjusted EBITDA to the most directly comparable GAAP measure, net profit (loss) before income tax:
| Three Months Ended June 30, | ||||||
| (Cdn$ thousands) | 2023 | 2022 | % Change | |||
| Net profit before income tax | 28,475 | 96,993 | (71 | ) | ||
| Add (deduct): | ||||||
| Unrealized loss (gain) on risk management contracts | 11,674 | (26,173 | ) | N/A | ||
| Transaction costs | 94 | — | 100 | |||
| Share-based compensation | 2,454 | 4,712 | (48 | ) | ||
| Depletion, depreciation and impairment | 57,057 | 37,230 | 53 | |||
| Finance expense | 8,755 | 6,352 | 38 | |||
| (Gain) loss on foreign exchange | (3,274 | ) | 4,720 | N/A | ||
| Loss on warrant liability | 4,794 | 145 | 3,206 | |||
| Other income, excluding transportation income | (294 | ) | (1,939 | ) | (85 | ) |
| Adjusted EBITDA | 109,735 | 122,040 | (10 | ) | ||
| Annualized adjusted EBITDA | 438,940 | 488,160 | (10 | ) | ||
Adjusted Working Capital Deficit
Previously, working capital was computed including risk management contracts and the current portion of lease obligations. As at June 30, 2023 and 2022, adjusted working capital has been computed excluding these items. The current presentation of adjusted working capital is aligned with measures used by management to monitor its liquidity for use in budgeting and capital management decisions. Adjusted working capital is defined as the sum of cash, accounts receivable, prepaid expenses and deposits and accounts payable and accrued liabilities.
| (Cdn$ thousands) | June 30, 2023 | December 31, 2022 | ||
| Cash | (4,960 | ) | (8,833 | ) |
| Accounts receivable | (59,071 | ) | (89,235 | ) |
| Prepaid expenses and deposits | (12,905 | ) | (4,564 | ) |
| Accounts payable and accrued liabilities | 107,760 | 135,547 | ||
| Adjusted working capital deficit | 30,824 | 32,915 | ||
Net Debt, Net Debt to Adjusted EBITDA, and Net Debt to Annualized Adjusted EBITDA
Net debt is calculated as the outstanding balance on the Company’s bank debt, term debt and adjusted working capital. Term debt (2020 Senior Notes) is calculated as the principal amount outstanding, plus accrued PIK interest, converted to Canadian dollars at the closing exchange rate for the period. Net debt to adjusted EBITDA is net debt divided by adjusted EBITDA. Net debt to annualized adjusted EBITDA is net debt divided by annualized adjusted EBITDA. Net debt is used to assess and monitor liquidity at a point in time, while the net debt to EBITDA ratios assist the Company in monitoring its capital structure and financing requirements.
Net debt and net debt to annualized adjusted EBITDA are disclosed in the "Highlights" section within this press release.
Supplementary Financial Measures
Throughout the Press Release, the Company presents certain financial figures, in accordance with IFRS, stated in dollars per boe ($/boe). These figures are determined by dividing the applicable financial figure as prescribed under IFRS by the Company’s total production for the respective period. Below is a list of figures which have been presented in the Press Release in $/boe:
- Average realized prices ($/boe);
- Revenue ($/boe);
- Royalty expense ($/boe);
- Operating expense ($/boe);
- Transportation expense ($/boe); and
- Realized gain (loss) on risk management contracts ($/boe)
