Hammerhead Energy Inc. Announces Record 2022 Annual Results, 2022 Year-end Reserves and Provides 2023 Guidance
CALGARY, Alberta, March 28, 2023 (GLOBE NEWSWIRE) -- Hammerhead Energy Inc. (“Hammerhead Energy” or “HEI”) (TSX: HHRS, HHRS.WT ; NASDAQ: HHRS, HHRSW) is pleased to announce record 2022 annual financial and operating results, year-end 2022 reserves and provide 2023 guidance.On February 23, 2023, HEI completed a plan of arrangement pursuant to a business combination agreement with Decarbonization Plus Acquisition Corporation IV (“DCRD”), an affiliate of HEI's controlling shareholder, Riverstone Holdings LLC, Hammerhead Resources Inc. (the "Company") and certain other parties and their respective shareholders. Pursuant to the plan of arrangement, DCRD amalgamated with a wholly owned subsidiary of the Company which was incorporated for the purpose of effecting the business combination to form Hammerhead Energy Inc. Also pursuant to the Plan of Arrangement, the Company amalgamated with a wholly owned subsidiary of DCRD incorporated to effect the business combination to form Hammerhead Resources ULC, a wholly owned subsidiary of HEI. In this press release, unless otherwise indicated or the context otherwise requires, "Hammerhead” and "the Company” refers to Hammerhead Resources Inc.
Scott Sobie notes “I am extremely proud of our accomplishments during 2022 as an organically grown business that continues to deliver sustainable and reliable energy while generating among the best returns in North America. Our successful entry into the public markets represents a significant milestone in the progression of our business. We are excited about the record results delivered in 2022, and our results to date in 2023 have been exceptional. Our corporate netback^8 in 2022 exceeded $36/boe and has continued in that range thus far in 2023 due to excellent operational execution and strong realized prices as a result of prudent hedging and natural gas marketing diversification. Prior to the most recent drop in oil prices, we added 7,000 bbl/d of new hedges for Q2 and Q3 2023 at US$75.28. Our Lower Montney lands remains 99% un-booked to date. Our recent 9-well 5-12 pad at North Karr has continued to deliver very strong production with nominal declines to date. A new 7-well pad at North Karr as well as a 7-well pad at Gold Creek are currently being completed and tied in. In 2023 we expect to generate significant cash flow per share growth and complete our infrastructure build-out, such that starting in 2024 we expect to generate substantial free cash flow.”
*2022** Highlights: *
· The Company achieved record annual average production of 32,081 boe/d (43% liquids)^1 for the year ended December 31, 2022. Liquids weighting increased to 43% from 39% in 2021 as the Company increased development in the Karr area. Annual average production increased 15% and oil production increased 40% over 2021.
· Oil and gas revenue was $844.6 million and operating netback^2 was $457.9 million or $39.10/boe for the year ended December 31, 2022, an increase of 146% from the same period of 2021.
· Net cash from operating activities for the year ended December 31, 2022 was $371.4 million. Adjusted funds from operations^3 was $423.5 million during the year ended December 31, 2022, which is a record level and an increase of 218% from the previous year.
· The Company reported record net profit of $225.1 million for the year ended December 31, 2022.
· The Company realized the benefit of market diversification for its natural gas production, generating an average 2022 natural gas price of $7.84/Mcf, 46% above the 2022 average AECO 5A monthly index price of $5.36/Mcf. The Company has 25 MMcf/d of exposure to Malin gas pricing, which averaged $11.20/Mcf for the year ended December 31, 2022.
· Net cash used in investing activities for the year ended December 31, 2022 was $368.2 million. Capital expenditures^4 during the year ended December 31, 2022 were $383.9 million, inclusive of $74.0 million of infrastructure expansion capital. The exploration and development program included the drilling of 31.0 gross (29.1 net), completion of 26.0 gross (26.0 net), and on-stream of 34.0 gross (34.0 net) Montney light-oil wells.
· Net cash from operating activities for the year ended December 31, 2022 was $371.4 million. In a year of significant production growth (up 15% year-over-year), during which the Company allocated substantial capital to Karr infrastructure expansion, the Company generated free funds flow^5 of $39.5 million.
· The Company exited 2022 with net debt^6 of $291.6 million and a net debt to adjusted EBITDA ratio of 0.7 times^7.
· On September 26, 2022 the Company and DCRD announced a business combination that resulted in the formation of HEI which commenced trading on the Toronto Stock Exchange (“TSX”) and the Nasdaq Stock Market LLC (“Nasdaq”) on February 27, 2023. As at March 28, 2023, HEI had 90,927,765 Class A common shares issued and outstanding (96,779,752 fully diluted).
*2022* *Reserves**:*
Hammerhead delivered substantial reserves additions in 2022, including the following highlights:
· Proved, Developed, Producing (“PDP”) reserves of 57 MMboe, an increase of 13% year-over-year, representing a 156% replacement of 2022 production. PDP reserves at the Karr core area increased 92% to 25 MMboe due to increased development, exceptional well results and infrastructure build-out.
· Total Proved (“1P”) reserves of 183 MMboe and Total Proved plus Probable (“2P”) reserves of 314 MMboe, an increase of 9% and 1% year-over-year, respectively.
· PDP net present value of reserves at a 10% discount rate (“NPV[10]”) of $901.4 million, 1P NPV[10] of $2.1 billion and 2P NPV[10] of $3.5 billion (an increase of 36% on 2P year-over-year).
· PDP Finding, Development and Acquisition (“FD&A”) cost of $21.06/boe (2.3x recycle ratio) and 3-year average PDP FD&A cost of $12.42/boe (3-year average recycle ratio of 2.3x), inclusive of significant infrastructure investments in 2022.
^1 ^See "Operational and Financial Summary" for such production by product type.
^2 ^Operating netback is a non-GAAP measure. Oil and gas revenue is the most directly comparable GAAP measure to operating netback. See “Non-GAAP and Other Financial Measures Advisory". Operating netback per boe is a non-GAAP measure. Oil and gas revenue per boe is the most directly comparable GAAP measure to operating netback per boe. See “Non-GAAP and Other Financial Measures Advisory".
^3 ^Adjusted funds from operations is a non-GAAP measure. Net cash from operating activities is the most directly comparable measure under generally accepted accounting principles ("GAAP") to adjusted funds from operations. See “Non-GAAP and Other Financial Measures Advisory".
^4 ^Capital expenditures is a non-GAAP measure. Net cash used in investing activities is the most directly comparable GAAP measure for capital expenditures, which is a non-GAAP measure. See “Non-GAAP and Other Financial Measures Advisory".
^5 ^Free funds flow is a non-GAAP measure. Net cash from operating activities is the most directly comparable GAAP measure to free funds flow. See “Non-GAAP and Other Financial Measures Advisory".
^6 ^Net debt is a non-GAAP measure. The Company's third party debt obligations of the bank debt and the term debt are the most directly comparable GAAP measures for net debt. See “Non-GAAP and Other Financial Measures Advisory".
^7 ^Net debt to adjusted EBITDA is a non-GAAP measure, derived from the net debt non-GAAP measure and adjusted EBITDA non-GAAP measure, where the directly comparable GAAP measures are the Company's debt obligations of bank debt and term debt, and the Company's net profit (loss), respectively. See “Non-GAAP and Other Financial Measures Advisory".
^8 ^Corporate netback per boe is calculated as adjusted funds from operations in the period divided by boe production in the period. Corporate netback per boe is a non-GAAP measure, see "Non-GAAP and Other Financial Measures Advisory"
*2023 Corporate Outlook and Guidance*
Hammerhead Energy's 2023 capital program is development-focused with a continuous 2-rig program expected to drill approximately 40 wells. HEI is continuing to increase its drilling focus on the North and South Karr assets with plans to allocate approximately 75% of drilling and completion activity to Karr with the remaining 25% at Gold Creek. Hammerhead Energy expects significant production and cash flow growth while targeting free funds flow neutrality in 2023 notwithstanding approximately $100.0 million in infrastructure expenditures at North and South Karr in the year. Significant investment in field infrastructure in 2022 and 2023 will maximize operational control, minimize cash costs and allow for “half cycle” economics from 2024 forward.
Hammerhead Energy is committing approximately $100.0 million to infrastructure expansions within its North and South Karr areas in order to accommodate its ongoing and expected growth in production at Karr. In the North Karr area, the Company completed a second expansion to its current facility in Q1 2023. In South Karr, HEI is building a new facility targeted to be on-stream by Q4 2023, bringing total in-field infrastructure capability to over 80,000 boe/d.
HEI expects to achieve an inflection point in material free funds flow generation in Q4 2023 as major infrastructure expansion capital expenditures will be largely complete. Hammerhead Energy plans to roughly double production in the next three years (as compared to the 2022 annual average) while generating significant amounts of free funds flow starting in the fourth quarter of this year.
Hammerhead Energy is providing its 2023 annual guidance as outlined below:
Forward looking information^1 *2023 guidance*
*Annual average production* boe/d *40,200*
Crude oil^2 % *33*
Natural gas liquids (“NGLs”) % *12*
Natural gas^2 % *55*
*Expenses*
Royalties % *13*
Operating $/boe *8.50*
Transportation $/boe *6.50*
Net general and administrative $/boe *1.60*
Cash interest and financing $/boe *1.40*
Cash taxes $/boe *-*
*Capital expenditures*^*3* $MM *525*
^1 ^Forward looking information are not guarantees of future performance and involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated with forward looking information. See "Forward-Looking Statements".
^2 ^References in the table above to crude oil refer to the tight oil product type, and references to natural gas refer to the shale gas product type.
^3 ^Capital expenditures is a non-GAAP measure. Net cash used in investing activities is the most directly comparable GAAP measure to capital expenditures. See “Non-GAAP and Other Financial Measures Advisory".
Hammerhead Energy is targeting greater than 25% production growth in 2023, with oil production growth expected to exceed 40%. HEI expects to achieve these results on an internally funded basis.
*Hedging*
As at December 31, 2022, the Company held the following outstanding risk management contracts:
*Remaining Term* *Reference* *Total Daily Volume*
(bbls/d) *Weighted Average * (Price/bbls)
*Crude Oil Swaps*
Jan 1, 2023 – Jun 30, 2023 US$ WTI 1,000 87.00
Jan 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*
Apr 1, 2023 - Sep 30, 2023 CDN$ AECO 30,000 — 4.96 —
Jan 1, 2023 - Jun 30, 2023 US$ Dawn — 30,000 — 3.04
Jan 1, 2023 - Dec 31, 2023 US$ AECO - NYMEX — 30,000 — (1.48 )
*Natural Gas Collar*
Jan 1, 2023 - Dec 31, 2023 US$ NYMEX — 30,000 — 5.00 - 9.80Subsequent to year-end, the Company entered into the following risk management contract:
*Remaining Term* *Reference* *Total Daily Volume*
(bbls/d) *Weighted Average * (Price/bbls)
*Crude Oil Swaps*
Mar 1, 2023 - Sep 30, 2023 US$ WTI 7,000 75.28
*
Complete Annual Filings*
HEI has filed its annual report on Form 20-F and the Company's 2022 year-end audited financial statements and management’s discussion and analysis ("2022 Annual MD&A") on SEDAR and EDGAR, along with posting these documents on its website www.hhres.com.
*Senior Leadership Team Update*
HEI is pleased to announce the appointment of Dick Unsworth and Kurt Molnar to its Senior Leadership Team.
Dick Unsworth has assumed the role of Senior Vice President, Business & Organizational Effectiveness. Dick brings over 40 years of broad-based industry experience, including executive roles in multinational corporations working both domestically and internationally.
Kurt Molnar has assumed the role of Vice President, Capital Markets & Corporate Planning. Kurt brings over 35 years of highly diversified experience in energy finance and senior executive level exploration and production business development.
*
*
*Operational and Financial Summary*
Three Months Ended
December 31, Year Ended
December 31,
(Cdn$ thousands, except per share amounts, production and unit prices) *2022* 2021 % Change *2022* 2021 % Change
*Production volumes*
Crude oil (bbls/d)^1 *8,958* 7,135 26 *9,531* 6,816 40
Natural gas (Mcf/d)^1 *99,512* 101,028 (2) *110,273* 102,516 8
Natural gas liquids (bbls/d) *3,984* 3,787 5 *4,171* 3,903 7
Total (boe/d) *29,527* 27,760 6 *32,081* 27,805 15
*Liquids weighting %* *44* 39 *43* 39
*Oil and gas revenue ($/boe)* *73.14* 54.50 34 *72.13* 43.34 66
*Operating netback* *($/boe)*^*2* *43.96* 20.22 117 *39.10* 15.90 146
*Oil and gas revenue* *198,676* 139,183 43 *844,644* 439,843 92
*Operating netback*^*3* *119,414* 51,653 131 *457,884* 161,274 184
*Net cash from operating activities* *76,131* 33,540 127 *371,355* 121,111 207
Per common share – basic *0.19* 0.09 111 *0.95* 0.31 206
Per common share – diluted *0.07* 0.04 75 *0.39* 0.31 26
*Adjusted funds from operations*^*4* *108,937* 43,528 150 *423,533* 133,130 218
Per common share – basic^5 *0.28* 0.11 155 *1.08* 0.34 218
Per common share – diluted^5 *0.10* 0.05 100 *0.44* 0.34 29
*Net profit (loss)* *67,298* 37,139 81 *225,100* (71,821) N/A
*Net profit (loss) attributable to ordinary equity holders* *60,584* 31,344 93 *199,865* (93,601) N/A
Per common share – basic *0.15* 0.08 88 *0.51* (0.24) N/A
Per common share – diluted *0.06* 0.03 100 *0.21* (0.24) N/A
*Net cash used in investing activities* *145,556* 42,190 245 *368,153* 91,180 304
*Capital expenditures*^*6* *173,669* 68,385 154 *383,876* 138,544 177
*Free funds flow*^*7* *(64,732**)* (24,857) 160 *39,534* (5,414) N/A
*Weighted average common shares outstanding*^*8*
Basic *392,556* 391,117 — *391,803* 391,106 —
Diluted *1,058,515* 952,281 11 *961,751* 391,106 146 As at December 31,
*FINANCIAL* *2022* 2021 % Change
Adjusted working capital deficit^9 *32,915* 52,443 (37)
Available funding^10 *309,985* 188,957 64
Net debt^1^1 *291,647* 293,490 (1)
^1 ^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.
^2 ^Operating netback per boe is a non-GAAP measure. Oil and gas revenue per boe is the most directly comparable GAAP measure to operating netback per boe. See “Non-GAAP and Other Financial Measures Advisory".
^3 ^Operating netback is a non-GAAP measure. Oil and gas revenue is the most directly comparable GAAP measure to operating netback. See “Non-GAAP and Other Financial Measures Advisory".
^4 ^Adjusted funds from operations is a non-GAAP measure. Net cash from operating activities is the most directly comparable GAAP measure to adjusted funds from operations. See “Non-GAAP and Other Financial Measures Advisory".
^5 ^Adjusted funds from operations per basic and diluted common share are non-GAAP measures. Net cash from operating activities per basic and diluted share are the most directly comparable GAAP measure to adjusted funds from operations per basic and diluted common share. See “Non-GAAP and Other Financial Measures Advisory".
^6 ^Capital expenditures is a non-GAAP measure. Net cash used in investing activities is the most directly comparable GAAP measure to capital expenditures. See “Non-GAAP and Other Financial Measures Advisory".
^7 ^Free funds flow is a non-GAAP measure. Net cash from operating activities is the most directly comparable GAAP measure to free funds flow. See “Non-GAAP and Other Financial Measures Advisory".
^8 ^Represents issued and outstanding common shares of Hammerhead Resources Inc. on a basic and fully diluted basis. Following the transaction referred to in subsection "Business Combination" in the 2022 Annual MD&A, HEI has 90,927,765 Class A common shares issued and outstanding (96,779,752 fully diluted) and 28,549,991 warrants issued and outstanding as of March 28, 2023.
^9 ^Adjusted working capital deficit is a capital management measure. See “Non-GAAP and Other Financial Measures Advisory".
^10 ^Available funding is a non-GAAP measure. Working capital deficit is the most directly comparable GAAP measure to available funding. See “Non-GAAP and Other Financial Measures Advisory".
^11 ^Net debt is a non-GAAP measure. The Company's third party debt obligations of the bank debt and the term debt are the most directly comparable GAAP measures for net debt. See “Non-GAAP and Other Financial Measures Advisory".
*2022 Reserves*
Hammerhead delivered substantial reserves additions in 2022, including the following highlights:
· PDP reserves of 57 MMboe, an increase of 13% year-over-year, representing a 156% replacement of 2022 production. PDP reserves at the Karr core area increased 92% to 25 MMboe due to increased development, exceptional well results and infrastructure build-out.
· 1P reserves of 183 MMboe and 2P reserves of 314 MMboe, an increase of 9% and 1% year-over-year, respectively.
· PDP NPV[10] of $901.4 million, 1P NPV[10] of $2.1 billion and 2P NPV[10] of $3.5 billion (an increase of 36% on 2P year-over-year).
· PDP FD&A cost of $21.06/Boe (2.3x recycle ratio) and 3-year average PDP FD&A cost of $12.42/Boe (3-year average recycle ratio of 2.3x), inclusive of significant infrastructure investments in 2022.
The Company's 2022 year-end reserves evaluation was conducted by McDaniel & Associates Consultants Ltd. ("McDaniel"), the
Company's independent qualified reserves evaluator with an effective date of December 31, 2022 (the "McDaniel Report").
The following summarizes certain information contained in the McDaniel Report, which was prepared in accordance with National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) and the definitions, standards, and procedures contained in the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”). McDaniel evaluated 100% of the Company’s reserves. The McDaniel Report is based on forecast prices and costs and applies the McDaniel’s, GLJ Ltd.'s and Sproule Associates Limited's average forecast escalated commodity price deck, foreign exchange rate and inflation rate assumptions as at December 31, 2022/January 1, 2023 (the “Average Commodity Price Forecast”). Estimated future net revenue is stated without any provisions for interest costs, other debt service charges or general and administrative expenses, and after the deduction of royalties, operating costs, estimated well abandonment and reclamation costs and estimated future development costs.
*Summary of Corporate Reserves*^*1,2*
The following table is a summary of the Company’s estimated reserves at December 31, 2022, as evaluated in the McDaniel Report:
*Crude Oil*^*3* *Natural Gas
Liquids* *Natural Gas*^*3* *Barrels of Oil
Equivalent*^*4* *(MMbbl)* *(MMbbl)* *(Bcf)* *(MMboe)* *% Liquids*
Proved
Developed Producing 14 8 211 57 39
Undeveloped ("PUD") 46 15 390 126 48
*Total Proved* *60* *23* *601* *183* *45*
Probable 51 15 390 131 50
*Total Proved plus Probable* *110* *38* *991* *314* *47*
^1 ^Reserves are presented on a “Company gross” basis, which is defined as Hammerhead’s working interest (operating and non-operating) share before deduction of royalties and without including any royalty interest of the Company.
^2 ^Based on the Average Commodity Price Forecast below.
^3 ^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.
^4 ^Oil equivalent amounts have been calculated using a conversion ratio of six thousand cubic feet of natural gas to one barrel of oil. See “Oil and Gas Advisory".
*Proved Developed Producing*
Proved developed producing reserves at December 31, 2022 were 57 MMboe, an increase of 13% from 51 MMboe at December 31, 2021, and representing a 156% replacement of 2022 production (December 31, 2021 - 143%). The increase was primarily a result of successful execution of the capital program.
At December 31, 2022, the proved developed producing NPV[10] was $901.4 million, representing a 42% increase from $632.6 million at December 31, 2021. The increase was primarily due to improved commodity price forecasts in addition to volume growth.
FD&A costs associated with proved developed producing reserves were $21.06/boe (December 31, 2021 - $9.57/boe), resulting in a recycle ratio of 2.3x (December 31, 2021 - 2.6x).
*Total Proved*
Total proved reserves at December 31, 2022 were 183 MMboe, an increase of 9% from 167 MMboe at December 31, 2021. The increase was primarily due to additional development in North and South Karr bringing additional probable wells into proved.
At December 31, 2022, the total proved NPV[10 ]was $2.1 billion, a 50% increase from $1.4 billion at December 31, 2021. The increase was primarily due to improved commodity price forecasts and acceleration of some locations from probable to proved reserves.
Future development costs associated with total proved reserves at December 31, 2022 were $1.7 billion, an increase of 30% from $1.3 billion at December 31, 2021. The increase was largely a result of cost inflation. FD&A costs, including future development costs associated with total proved reserves of $29.02/boe (December 31, 2021 - $10.13/boe), resulting in a recycle ratio of 1.7x (December 31, 2021 - 2.5x).
*Total Proved Plus Probable*
Total proved plus probable reserves at December 31, 2022 were 314 MMboe, an increase of 1% from 310 MMboe at December 31, 2021 as new reserve bookings were largely offset by production in 2022.
At December 31, 2022, the total proved plus probable NPV[10 ]was $3.5 billion, a 36% increase compared to $2.6 billion at December 31, 2021. The increase was primarily due to improvements in price forecasts.
Future development costs associated with total proved plus probable reserves at December 31, 2022 were $2.8 billion, an increase of 17% from $2.4 billion at December 31, 2021. The increase was largely a result of cost inflation. FD&A costs, including future development costs associated with total proved plus probable reserves of $52.27/boe (December 31, 2021 - $3.87/boe), resulting in a recycle ratio of 0.9x (December 31, 2021 - 6.5x).
*Net Present Value of Future Net Revenue Before Income Taxes Discounted at (%/year)*^*1,2,3,4*
The following table is a summary of the estimated net present value of future net revenue (before income taxes) associated with the Company's reserves as at December 31, 2022, discounted at the indicated percentage rates per year, as evaluated in the McDaniel Report:
*NPV (Before Income Tax) Discounted at*
(Cdn$ thousands) ***%* *5**%* *10**%* *15**%* *20**%*
Proved
Developed Producing 1,134,415 1,009,792 901,429 817,217 751,641
Undeveloped 2,265,435 1,655,568 1,243,408 954,340 744,673
*Total Proved* *3,399,850* *2,665,360* *2,144,837* *1,771,557* *1,496,314*
Probable 3,071,686 1,973,029 1,348,133 969,212 726,687
*Total Proved plus Probable* *6,471,536* *4,638,389* *3,492,970* *2,740,769* *2,223,001*
^1 ^The forecast of commodity prices used in the McDaniel Report can be found at mcdan.com, gljpc.com and sproule.com. Also see “Average Commodity Price Forecast” below.
^2 ^Estimated future net revenues are stated without any provision for interest costs, other debt service charges or general and administrative expenses, and after deduction of royalties, operating costs, estimated well abandonment and reclamation costs and estimated future development costs.
^3 ^Estimated future net revenue, whether discounted or not, does not represent fair market value.
^4 ^Net present values of future net revenue after income taxes are estimated to approximate the before income tax values based on the estimated future revenues, available tax pools and future deductible expenses.
*Average Commodity Price Forecast (McDaniel, GLJ and Sproule)*^*1,2*The following table summarizes the average commodity price forecast, foreign exchange rate and inflation rate assumptions as at December 31, 2022/January 1, 2023, as applied in the McDaniel Report, for the next ten years.
*Year* *Edm Light *
(C$/bbl) *WTI Oil*
(US$/bbl) *AECO Gas*
(C$/MMBtu) *Henry Hub*
($US/MMBtu) *Exchange Rate *
(US$/C$)
2023 103.76 80.33 4.23 4.74 0.75
2024 97.74 78.50 4.40 4.50 0.77
2025 95.27 76.95 4.21 4.31 0.77
2026 95.58 77.61 4.27 4.40 0.77
2027 97.07 79.16 4.34 4.49 0.78
2028 99.01 80.74 4.43 4.58 0.78
2029 100.99 82.36 4.51 4.67 0.78
2030 103.01 84.00 4.60 4.76 0.78
2031 105.07 85.69 4.69 4.86 0.78
2032 106.69 87.40 4.79 4.95 0.78
2033 108.83 89.15 4.88 5.05 0.78
Thereafter +2.0% per year +2.0% per year +2.0% per year +2.0% per year 0.78
^1 ^The commodity price forecast, foreign exchange rate and inflation rate assumptions were determined using three independent reserve evaluator's price forecasts: McDaniel, GLJ Ltd. and Sproule Associates Limited effective December 31, 2022/January 1, 2023.
^2 ^Inflation is accounted for at 2.0% per year.
*Reconciliation of Company Gross Reserves Based on Forecast Prices and Costs*^*1*^*,2*The following table summarizes the change in total proved plus probable reserves from 2021 to 2022:
*Crude Oil*^*4
**(MMbbl)* *Natural Gas Liquids
(MMbbl)* *Natural Gas*^*4** (Bcf)* *Combined*^*3
**(MMboe)*
*Factors* *1P* *2P* *1P* *2P* *1P* *2P* *1P* *2P*
December 31, 2021 49 102 21 37 585 1,026 168 310
Extensions and improved recovery 17 16 4 3 145 119 45 39
Technical revisions (4) (6) (2) (2) (105) (140) (23) (32)
Discoveries — — — — — — — —
Acquisitions — — — — — — — —
Dispositions — — — — — — — —
Economic factors 1 2 1 1 17 26 5 7
Production (3) (3) (1) (1) (40) (40) (11) (12)
*December 31, 2022* *60* *111* *23* *38* *601* *991* *183* *314*
^1 ^Company gross reserves exclude royalty volumes.
^2 ^The Company's reserves for the year ended December 31, 2021 were evaluated by McDaniel in accordance with NI 51-101 and the COGE Handbook with an effective date of December 31, 2021.
^3 ^Oil equivalent amounts have been calculated using a conversion ratio of six thousand cubic feet of natural gas to one barrel of oil. See “Oil and Gas Advisory".
^4 ^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.
*FD&A Costs & Recycle Ratios*^*1*^*,*^*2*^*,*^*3*^*,4*The following table summarizes Company’s FD&A costs and recycle ratios for the year ended and three years ended December 31, 2022:
*2022* *Three-Year Average* *FD&A
Cost* *Reserve
Additions* *FD&A* *Recycle
Ratio* *FD&A
Cost* *Reserve
Additions* *FD&A* *Recycle
Ratio* (Cdn$ millions) (MMboe) ($/boe) (x) (Cdn$ millions) (MMboe) ($/boe) (x)
PDP *384* *18* *21.06* *2.3* 617 50 12.42 2.3
1P *796* *27* *29.02* *1.7* 649 17 37.96 0.7
2P *798* *15* *51.86* *0.7* (204) (63) N/A N/A
^1 ^FD&A cost per boe is calculated as the sum of capital expenditures plus the change in future development costs (“FDC”) for the period when appropriate, divided by the change in reserves within the applicable reserves category, inclusive of changes due to acquisitions and dispositions.
^2 ^Recycle ratio is calculated by dividing the operating netback, excluding realized losses on risk management contracts per boe by the FD&A cost per boe over the period.
^3 ^Three-year average FD&A costs were calculated by dividing total FD&A cost over the period by the aggregate reserves additions in the period. The associated recycle ratios were calculated by dividing the weighted average operating netback, excluding realized losses on risk management contracts, per boe over the period by the three-year average FD&A costs.
^4 ^Reserve additions is calculated as the changes to reserves in such reserves category from the prior period from extensions/improved recovery, technical revisions, discoveries, acquisitions, dispositions and economic factors, expressed in Boe.
*Land Acreage*
Hammerhead’s Montney land position is summarized below:
*December 31, 2022* December 31, 2021 *Gross acres* *Net acres* *Working interest
percentage* Gross acres Net acres Working interest
percentage
Gold Creek *44,000* *44,000* *100* 46,560 46,560 100
Karr *56,000* *55,920* *100* 59,698 59,618 100
Latornell *18,560* *6,880* *37* 20,480 7,552 37
TOTAL *118,560* *106,800* *90* 126,738 113,730 90
*
About Hammerhead Energy Inc. *
Hammerhead Energy is a Calgary, Canada-based energy company, with assets and operations in Alberta targeting the Montney formation. Hammerhead, a wholly owned subsidiary of HEI, was formed in 2009.
*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 (the “Securities Act”), 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: HEI's assessment of future plans, operations and strategies; expectations for 2023 and benefits to be derived therefrom for 2024; hedges for Q2 and Q3 2023; HEI's 2023 capital program and drilling plans, including the allocation of capital between Karr and Gold Creek; the expected additional infrastructure expansion at South Karr, including the amount thereof and the anticipated timing of a new facility being brought on-steam; HEI's intended delivery of substantial production and significant cash flow growth while targeting free cash flow neutrality in 2023; HEI'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; HEI's expectation that production growth will be internally funded; HEI's plans to concentrate its development activities in certain of its operating areas; the focus of HEI's operations and HEI's drilling plans; HEI's expectations regarding in-field infrastructure capability by the end of 2023; HEI's expectation regarding material free fund flow generation including the anticipated timing thereof; HEI's production growth over the next three years; HEI's general strategy for its business and assets; and other matters related to the foregoing. In addition, forward-looking statements contained in this document include statements relating to "reserves", which are by their nature 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. The recovery and reserve estimates of the Company's reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered.
Such forward-looking statements reflect the current views of HEI 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; HEI's ability to access sufficient capital from internal and external sources; Hammerhead Energy’s success in retaining or recruiting, or changes required in, its officers, key employees or directors following the proposed business combination; litigation and regulatory enforcement risks, including the diversion of management time and attention and the additional costs and demands on HEI's resources; the ability of HEI 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 (including COVID-19) and epidemics, and general political and economic instability (including the ongoing Russian-Ukrainian conflict); severe weather conditions 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 HEI's future business; availability of adequate levels of insurance; difficulty in obtaining necessary regulatory approvals and the maintenance of such approvals; risk that HEI's 2023 capital program and drilling plans, including the allocation of capital between its properties is different than anticipated; the anticipated timing of a new facility being brought on-steam is delayed; HEI is unable to deliver substantial production and significant cash flow growth while targeting free cash flow neutrality in 2023; risk that HEI'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; and HEI's expectation that production growth is not internally funded. 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, HEI 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 HEI operates; the timely receipt of any required regulatory approvals; the ability of HEI to obtain qualified staff, equipment and services in a timely and cost efficient manner; that HEI 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 HEI's conduct and results of operations will be consistent with its expectations; that HEI will have the ability to develop its oil and gas properties in the manner currently contemplated; the estimates of HEI's reserves and production volumes and the assumptions related thereto (including commodity prices and development costs) are accurate in all material respects; HEI’s ability to add production and reserves through development and exploration activities; and other matters. Although HEI 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 HEI's current and future operations and such information may not be appropriate for other purposes. HEI'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 HEI 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 Energy’s views as of any subsequent date, and except as expressly required by applicable securities laws, Hammerhead Energy 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.
This press release contains information that may be considered a financial outlook under applicable securities laws about HEI's potential financial position, including, but not limited to, HEI's 2023 anticipated royalties, operating costs, transportation costs, net general and administrative costs, cash interest and financing costs, cash taxes and capital expenditures; HEI's expectation that production growth will be internally funded; HEI's intended delivery of substantial production and significant cash flow growth while targeting free cash flow neutrality in 2023; and HEI's expectation regarding material free fund flow generation including the anticipated timing thereof, 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 HEI 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, HEI 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 HEI'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 three months and year ended December 31, 2022 and 2021, and the references to “natural gas”, “crude oil" and "NGLs”, reported in this press release consist of the following product types, as defined in NI 51-101 and using a conversion ratio of 6 mcf : 1 bbl where applicable:
*Q4 2022* Q4 2021 *YE 2022* YE 2021
Tight oil (bbls/d) *8,958* 7,135 *9,531* 6,816
Shale gas (Mcf/d) *99,512* 101,028 *110,273* 102,516
Natural gas liquids (bbls/d) *3,984* 3,787 *4,171* 3,903
Total (boe/d) *29,527* 27,760 *32,081* 27,805
*
Oil and Gas Metrics*
This press release contains certain oil and gas metrics, including reserves replacement, FD&A cost, 3-year average FD&A cost, and recycle ratio, 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. 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.
*Reserves Advisory*
The recovery and reserve estimates of crude oil reserves provided in this news release are estimates only, and there is no guarantee that the estimated reserves will be recovered. Actual crude oil reserves may eventually prove to be greater than, or less than, the estimates provided herein. All December 31, 2022 reserves presented are based on McDaniel’s, GLJ Ltd.'s and Sproule Associates Limited's December 31, 2022/January 1, 2023 average commodity price forecast and costs. All December 31, 2021 reserves presented are based on McDaniel’s, GLJ Ltd.'s and Sproule Associates Limited's January 1, 2022 average commodity price forecast and costs.
It should not be assumed that the estimates of future net revenues presented herein represent the fair market value of the reserves. There are numerous uncertainties inherent in estimating quantities of crude oil, reserves and the future cash flows attributed to such reserves. The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation.
“Proved Developed Producing Reserves" are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.
"Proved reserves" are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.
"Probable reserves" are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.
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/d barrels per day Crude oil Tight oil as defined in National Instrument 51-101
Bcf Billion cubic feet 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 G&A general and administrative
Mcf thousand cubic feet WTI West Texas Intermediate
Mcf/d thousand cubic feet per day USD U.S. dollars
MMbbl million barrel CAD Canadian dollars
MMcf/d million cubic feet per day US United States
MMboe million barrels of oil equivalent CDN Canadian
mmbtu million British Thermal Units GJ gigajoule
NGL Natural gas liquids
*
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
December 31, Year Ended
December 31,
(Cdn$ thousands) *2022* 2021 *2022* 2021 2020
Net cash used in investing activities *145,556* 42,190 *368,153* 91,180 113,328
Proceeds from asset disposition *—* — *—* 10,027 —
Net change in accounts payable related to the addition of PP&E *28,113* 26,195 *15,723* 37,337 (18,966 )
Capital expenditures *173,669* 68,385 *383,876* 138,544 94,362
*
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) *December 31, 2022* December 31, 2021
Adjusted working capital deficit *(32,915* *)* (52,443 )
Debt capacity *170,200* 68,700
Equity commitment *172,700* 172,700
Available funding *309,985* 188,957
*
Operating Netback*
Operating netback is calculated by deducting royalties, operating expense, transportation expense, and realized (losses) gains 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
December 31, Year Ended
December 31,
(Cdn$ thousands) *2022* 2021 % Change *2022* 2021 % Change 2020
Revenue *198,676* 139,183 43 *844,644* 439,843 92 263,514
Royalties *(22,855* *)* (14,511 ) 58 *(104,508* *)* (38,577 ) 171 (17,185 )
Operating expense *(26,803* *)* (21,402 ) 25 *(106,592* *)* (82,721 ) 29 (77,477 )
Net transportation expense *(17,202* *)* (15,409 ) 12 *(69,683* *)* (61,864 ) 13 (56,982 )
Operating netback, excluding realized losses on risk management contracts *131,816* 87,861 50 *563,861* 256,681 120 111,870
Realized losses on risk management contracts *(12,402* *)* (36,208 ) (66 ) *(105,977* *)* (95,407 ) 11 66,121
Operating netback *119,414* 51,653 131 *457,884* 161,274 184 177,991
(Cdn$ per boe)
Revenue *73.14* 54.50 34 *72.13* 43.34 66 23.97
Royalties *(8.41* *)* (5.68 ) 48 *(8.93* *)* (3.80 ) 135 (1.56 )
Operating expense *(9.87* *)* (8.38 ) 18 *(9.10* *)* (8.15 ) 12 (7.05 )
Net transportation expense *(6.33* *)* (6.04 ) 5 *(5.95* *)* (6.09 ) (2 ) (5.18 )
Operating netback, excluding realized losses on risk management contracts *48.53* 34.40 41 *48.15* 25.30 90 10.18
Realized losses on risk management contracts *(4.57* *)* (14.18 ) (68 ) *(9.05* *)* (9.40 ) (4 ) 6.02
Operating netback per boe *43.96* 20.22 117 *39.10* 15.90 146 16.20
*
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
December 31, Year Ended
December 31,
(Cdn$ thousands) *2022* 2021 *2022* 2021 2020
Net cash from operating activities *76,131* 33,540 *371,355* 121,111 119,686
Changes in non-cash working capital *29,958* (3,231 ) *38,657* (6,131 ) 9,801
Realized foreign exchange loss on debt repayment *—* — *(5,168* *)* — —
Settlement of decommissioning obligations *—* — *123* — —
Loss on settlement under long term retention program *—* — *—* (527 ) —
Funds from operations *106,089* 30,309 *404,967* 114,453 129,487
Optimization fees *—* 13,665 *—* 19,708 670
Transaction costs *3,059* — *19,080* — —
(Gain) loss on foreign exchange *(944* *)* (621 ) *7,229* (350 ) 817
Unrealized gain (loss) on foreign exchange *1,112* 630 *(4,804* *)* 341 (813 )
Other income, excluding transportation income *(379* *)* (455 ) *(2,939* *)* (1,022 ) (1,143 )
Adjusted funds from operations *108,937* 43,528 *423,533* 133,130 129,018
Capital expenditures *(173,669* *)* (68,385 ) *(383,876* *)* (138,544 ) (94,362 )
Settlement of decommissioning obligations *—* — *(123* *)* — —
Free funds flow *(64,732* *)* (24,857 ) *39,534* (5,414 ) 34,656
*
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*Management calculates corporate netback per boe as adjusted funds from operations in the period divided by boe production in the period.
*Adjusted Funds from Operations per boe and Adjusted Funds from Operations per Basic Share and Diluted Share*
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.
Adjusted funds from operations 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. Adjusted funds from operations per boe and adjusted funds from operations per basic share and diluted share are disclosed in the "Operational and Financial Summary" section within this press release.
*Finding, Development and Acquisition Costs (“FD&A Costs”)*
Finding, Development and Acquisition Costs (“FD&A costs”) is a non-GAAP ratio that helps to explain the cost of finding and developing additional oil and gas reserves. FD&A costs are determined by dividing capital expenditures in the period plus the change in finding and development costs plus acquisition costs divided by boe reserve additions in the period.
*Recycle Ratio*
Recycle ratio is a non-GAAP ratio that measures the profit per barrel of oil to the cost of finding and developing that barrel of oil. Recycle ratio is calculated by dividing the operating netback, excluding realized losses on risk management contracts, per boe by the FD&A cost, per boe over the period.
*Capital Management Measures*
*Adjusted EBITDA*
Adjusted EBITDA is calculated as net profit (loss) before interest and financing expenses, income taxes, depletion, depreciation and amortization, adjusted for certain non-cash items, or other items that are not considered part of normal business operations. 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:
Year Ended
December 31,
(Cdn$ thousands) *2022* 2021 2020
Net profit (loss) before income tax *256,820* (71,821 ) 53,410
Add (deduct):
Unrealized (gain) loss on risk management contracts *(38,112* *)* 16,649 18,353
Optimization fees *—* 19,708 670
Transaction costs *19,080* — —
Share-based compensation *10,044* 14,039 7,155
Depletion and depreciation *147,168* 127,333 135,184
Finance expense *25,497* 21,264 37,344
Loss (gain) on foreign exchange *7,229* (350 ) 817
Loss (gain) on warrant liability *10,611* 96 (3,981 )
Loss (gain) on debt repayment *218* — (88,160 )
Loss on asset disposition *—* 13,813 —
Loss on settlement under long term retention program *—* 527 —
Other income, excluding transportation income *(2,939* *)* (1,022 ) (4,639 )
Adjusted EBITDA *435,616* 140,236 156,153
*
Adjusted Working Capital Deficit*
Previously, working capital was computed including risk management contracts and the current portion of lease obligations. As at December 31, 2022 and 2021, 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) *December 31, 2022* December 31, 2021
Cash *(8,833* *)* (12,239 )
Accounts receivable *(89,235* *)* (49,433 )
Prepaid expenses and deposits *(4,564* *)* (2,751 )
Accounts payable and accrued liabilities *135,547* 116,866
Adjusted working capital deficit *32,915* 52,443
*
Net Debt and Net Debt to Adjusted EBITDA*
Net debt is calculated as the outstanding balance on the Company’s bank debt, the term debt and adjusted working capital. The term debt (2020 Senior Notes) are 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 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 adjusted EBITDA are disclosed in the "Highlights" section within this press release.
CONTACT: 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