Tamarack Valley Energy Announces Second Quarter 2023 Financial Results and Provides Operational Update
TSX: TVE
CALGARY, AB, July 27, 2023 /CNW/ - Tamarack Valley Energy Ltd. ("Tamarack" or the "Company") is pleased to announce its financial and operating results for the three and six months ended June 30, 2023. Selected financial and operating information is outlined below and should be read with Tamarack's consolidated financial statements and related management's discussion and analysis (MD&A) for the three and six months ended June 30, 2023, which will be available on SEDAR+ at www.sedarplus.ca and on Tamarack's website at www.tamarackvalley.ca.
Q2 2023 Financial and Operating Highlights
Commissioned a newly constructed, owned and operated Wembley gas plant June 9, delivering the project on budget and ahead of schedule with production ramping to the nameplate 15 MMcf/d of initial capacity;
Achieved quarterly volumes of 66,738 boe/d(2), representing a 52% year-over-year increase (or 21% on a per share basis). A successful second quarter development program was partially offset by the Company's loss of ~1,500 boe/d(3) of production owing to the direct and indirect impacts of the Alberta wildfires situation and unplanned third-party outages. Production impacts were largely restored prior to June 30, with second half production levels forecasted to average between 68,000-70,000 boe/d(5);
Despite the wildfire impacts, full year production guidance maintained at 67,000 to 71,000 boe/d(5) on the strength of better than anticipated drilling results in the Clearwater and Charlie Lake programs;
Invested $117.8 million during the quarter, including drilling, completion and equipping of 19 (19.0 net) Clearwater wells and five (5.0 net) Charlie Lake wells. The enhanced scale and scope of our Clearwater operations has led to greater capital efficiencies offsetting the increase in unit cost inflation that occurred through 2022 and delivering costs not seen since the first quarter of 2022;
Allocated $20 million in Q2/23 to strategic infrastructure, including costs associated with the Wembley plant and the Nipisi pipeline terminal. Both projects will drive lower operating and transportation costs enhancing free funds flow(1) in the second half of 2023 forward;
Generated Q2/23 adjusted funds flow(1) of $157.3 million and free funds flow(1) of $39.4 million reflecting production impacts from the wildfires and third-party outages, along with lower year-over-year commodity prices and a wider WCS differential;
Looking ahead the strengthening of WCS differentials coupled with the completion of our infrastructure initiatives will contribute to a stronger forecasted netback through the back half of the year and five-year plan;
Published the 2023 annual sustainability report highlighting Tamarack's commitment to environmental, social and governance (ESG) principles and sustainable practices during 2022; and
Subsequent to the quarter, entered into a definitive agreement for the sale of a minority interest in the Wembley gas plant and a gross overriding royalty (GORR) on select Clearwater and Charlie Lake properties for total consideration of $39.5 million. Following closing of the sale, Tamarack will continue to be the operator of the Wembley gas plant and will retain full access to 100% of the capacity.
Brian Schmidt (Aakaikkitstaki), Tamarack's President and CEO commented: "Tamarack's dominant position in the Clearwater and Charlie Lake plays are the foundation of our long-term strategic plan which is underpinned by a leading low sustaining free funds flow(1) breakeven in North America's most economic oil plays. Recent results at West Marten Hills, where the Company produced ~3,750 bopd from 13 wells on two pads in June, highlight the prolific nature of our Clearwater program. At the same time, we are drilling top tier Charlie Lake wells and flowing into our owned and operated infrastructure, driving long-term value creation. Our business is focused on delivering the most economic barrels to enhance returns and free funds flow(1) for shareholders."
Financial & Operating Results
Three months ended | Six months ended | ||||||
2023 | 2022 | % | 2023 | 2022 | % | ||
($ thousands, except per share) | |||||||
Total oil, natural gas and processing revenue | 398,319 | 407,195 | (2) | 777,774 | 706,090 | 10 | |
Cash flow from operating activities | 156,265 | 214,708 | (27) | 215,889 | 347,561 | (38) | |
Per share – basic | $ 0.28 | $ 0.49 | (43) | $ 0.39 | $ 0.81 | (52) | |
Per share – diluted | $ 0.28 | $ 0.49 | (43) | $ 0.39 | $ 0.81 | (52) | |
Adjusted funds flow (1) | 157,253 | 203,622 | (23) | 314,524 | 352,481 | (11) | |
Per share – basic (1) | $ 0.28 | $ 0.47 | (40) | $ 0.57 | $ 0.83 | (31) | |
Per share – diluted (1) | $ 0.28 | $ 0.46 | (39) | $ 0.56 | $ 0.82 | (32) | |
Net income | 25,735 | 143,507 | (82) | 28,240 | 169,964 | (83) | |
Per share – basic | $ 0.05 | $ 0.33 | (85) | $ 0.05 | $ 0.40 | (88) | |
Per share – diluted | $ 0.05 | $ 0.33 | (85) | $ 0.05 | $ 0.39 | (87) | |
Net debt (1) | (1,373,620) | (470,563) | 192 | (1,373,620) | (470,563) | 192 | |
Capital expenditures (4) | 117,831 | 109,483 | 8 | 265,993 | 234,850 | 13 | |
Weighted average shares outstanding | |||||||
Basic | 556,461 | 434,924 | 28 | 556,504 | 427,175 | 30 | |
Diluted | 560,016 | 438,206 | 28 | 560,437 | 430,406 | 30 | |
Share Trading | |||||||
High | $ 4.25 | $ 6.48 | (34) | $ 4.88 | $ 6.48 | (25) | |
Low | $ 2.99 | $ 4.12 | (27) | $ 2.99 | $ 3.90 | (23) | |
Average daily share trading volume (thousands) | 2,332 | 4,155 | (44) | 2,694 | 3,963 | (32) | |
Average daily production | |||||||
Light oil (bbls/d) | 16,382 | 18,233 | (10) | 16,706 | 18,052 | (7) | |
Heavy oil (bbls/d) | 35,373 | 10,805 | 227 | 34,889 | 9,172 | 280 | |
NGL (bbls/d) | 3,645 | 3,540 | 3 | 3,882 | 3,825 | 1 | |
Natural gas (mcf/d) | 68,027 | 67,195 | 1 | 71,143 | 69,082 | 3 | |
Total (boe/d) | 66,738 | 43,777 | 52 | 67,334 | 42,563 | 58 | |
Average sale prices | |||||||
Light oil ($/bbl) | 91.74 | 135.66 | (32) | 93.38 | 123.07 | (24) | |
Heavy oil, net of blending expense(1) ($/bbl) | 73.02 | 115.51 | (37) | 67.42 | 106.91 | (37) | |
NGL ($/bbl) | 36.64 | 63.61 | (42) | 41.53 | 59.65 | (30) | |
Natural gas ($/mcf) | 2.39 | 7.81 | (69) | 2.97 | 6.73 | (56) | |
Total ($/boe) | 65.66 | 102.16 | (36) | 63.63 | 91.54 | (30) | |
Operating netback ($/Boe) | |||||||
Average realized sales, net of blending expense (1) | 65.66 | 102.16 | (36) | 63.63 | 91.54 | (30) | |
Royalty expenses | (12.70) | (19.64) | (35) | (12.34) | (17.75) | (30) | |
Net production and transportation expenses (1) | (14.23) | (13.00) | 9 | (14.31) | (12.55) | 14 | |
Operating field netback ($/Boe) (1) | 38.73 | 69.52 | (44) | 36.98 | 61.24 | (40) | |
Realized commodity hedging loss | (2.05) | (9.40) | (78) | (1.56) | (6.79) | (77) | |
Operating netback ($/Boe) (1) | 36.68 | 60.12 | (39) | 35.42 | 54.45 | (35) | |
Adjusted funds flow ($/Boe) (1) | 25.89 | 51.11 | (49) | 25.81 | 45.75 | (44) | |
2023 Outlook & Guidance Update
The Company's capital budget range remains unchanged at $425 million to $475 million(4). Tamarack continues to focus on maximizing free funds flow(1) for debt repayment and enhancing shareholder returns as debt thresholds are met. Second half 2023 free funds flow(1) is expected to increase given the tighter WCS differentials, increased operating netback(1) realizations through our infrastructure initiatives resulting in lower opex and transportation, along with lower capital expenditures relative to the first half of 2023. Our 2023 capital guidance balances maximizing free funds flow(1) generation over both the short and long term, with a focus on debt repayment and accelerating the timing of our enhanced return framework.
Tamarack is maintaining prior 2023 production guidance of 67,000 to 71,000 boe/d(5) which was outlined in May 2023. Production guidance reflects the impact of the wildfires which is expected to be offset through the second half of the year by strong performance from our Clearwater and Charlie Lake drilling programs. Guidance for operating costs, transportation expense, royalties, G&A and interest ranges remain unchanged.
Unchanged Current | ||
as presented May 10, 2023 | ||
Capital Budget ($MM)(4) | $425 – $475 | |
Annual Average Production (boe/d)(5) | 67,000 – 71,000 | |
Average Oil & NGL Weighting | 81% – 83% | |
Expenses: | ||
Royalty Rate (%) | 19% – 21% | |
Operating ($/boe) | $9.00 – $9.50 | |
Transportation ($/boe) | $3.50 – $4.00 | |
General and Administrative ($/boe)(6) | $1.25 – $1.35 | |
Interest ($/boe) | $3.80 – $4.00 | |
Taxes ($/boe)(7) | $3.75 – $4.10 | |
Leasing Expenditures ($MM) | $3.5 – $4.5 |
Operations Update
Infrastructure
Tamarack completed the construction and commissioning of its owned and operated 15 MMcf/d Wembley gas plant, which will process associated natural gas from the Company's highly economic and core Charlie Lake play. The plant was completed on budget and brought onstream June 9, 2023, ahead of schedule.
As development continues to expand across Tamarack's Clearwater lands, the Company is investing in gas conservation and recently acquired strategic natural gas infrastructure at West Marten Hills. This facility offers the potential to become a conservation hub for the area and is expected to initially conserve 6 MMcf/d of natural gas commencing in Q1/24. Expansion of this facility is underway and is expected to support long term regional development of the Clearwater play while also delivering line of sight to lowering Tamarack's emissions intensity.
The Nipisi terminal and pipeline project continues to track on time, affording enhanced netback realizations through blending cost benefits and reduced transportation expense. In addition, Tamarack is working with third parties to establish a new Clearwater Heavy Oil benchmark which could provide for improved pricing over time.
Tamarack has significantly expanded its Clearwater and Charlie Lake infrastructure footprint year-to-date. Looking ahead, capital for the balance of 2023 will focus on the drill bit. The Company anticipates delivering increased free funds flow(1) and material debt reduction exiting the year, reflecting higher H2/23 production and narrowing WCS differentials.
Clearwater
Clearwater production averaged 37,800 boe/d(8) in the second quarter, representing 57% of corporate production. During the quarter, the Company drilled and brought onstream 19 (19.0 net) and 22 (22.0 net) wells respectively. In addition, Tamarack drilled two (2.0 net) injector wells. Tamarack currently has six rigs running (three at Nipisi / West Marten Hills, two at Marten Hills and one at Southern Clearwater). Operational and capital synergies are being realized through the execution of a larger Clearwater development program. Performance gains, enhanced well design and pad efficiency enabled Clearwater drilling costs in Q2/23 ($/lateral meter) to be realized at Q1/22 levels offsetting inflationary impacts experienced over the prior year.
Strong well results at West Marten Hills reflects success of the Company's development program. In June, the Company averaged approximately 3,750 bopd of heavy oil from two multi-well pads that included the 11-10-076-05W5 ten-well pad and 15-15-076-05W5 three well pad. Further to this, certain wells averaged initial production rates in excess of 400 bopd from the aforementioned pads, significantly outperforming internal type curve forecasts.
Expansion of the Nipisi waterflood program is ongoing following the successful 102/13-19-076-08W5 pilot which continues to produce at ~390 bopd with cumulative production of over 190,000 barrels of oil to date. Water injection rates at Nipisi averaged ~2,100 bbl/d in June and completion of the centralized water facility at the 15-22-076-07W5 battery in Q4/23 will support the ongoing ramp of total injection exiting the year.
At Marten Hills, Tamarack has more than doubled the rate at the 103/15-02-075-25W4 injector since acquiring Deltastream Energy Corporation in Q4/22. Current injection is demonstrating a positive result as oil tests and the offsetting producer are now ~30% (>50 bbl/d) higher than production rates prior to increasing injection. Tamarack's first "W" pattern well conversion has been online since May and shows very encouraging injectivity. With current water injection rates of ~900 bbl/d, the Company plans to further increase injection and accelerate fill-up.
Charlie Lake
Activity in the Charlie Lake resulted in the drilling of five (5.0 net) wells and completion of eight (8.0 net) wells with six (6.0 net) wells coming on stream during the second quarter. Production averaged 15,000 boe/d(9), representing 22% of the total corporate production for the period. Benefitting from the early commissioning of the Wembley plant, recent production in the Charlie Lake is achieving rates of ~17,000 boe/d(10). This compares to rates of ~12,500 boe/d(11) announced in Q2/21 underscoring Tamarack's ability to successfully deliver on organic drilling and development and secure access to egress and ownership of key infrastructure, while executing on and integrating strategic acquisitions to become a dominant Charlie Lake producer.
Tamarack drilled five (5.0 net) wells ahead of the Wembley commissioning which are now flowing through the plant. These wells are all outperforming forecasts with initial rates averaging 800 – 900 bopd (1,100 – 1,200 boe/d)(12) per well. Despite limited planned activity for the remainder of the year, Charlie Lake rates are expected to remain stable in the 16,000 – 17,000 boe/d(13) range. Activity for the fall is expected to commence in August drilling one well (0.5 net) and continue in late September with three (3.0 net) operated wells planned for Q4/23.
Return of Capital
The Company remains committed to balancing long-term sustainable free funds flow(1) growth with returning capital to shareholders. The base dividend is currently $0.15/share annually which represents a 4.1% yield at the current share price. Debt repayment remains the immediate focus to achieve our enhanced return of capital thresholds whereby the Company will return from 25% up to 75% of excess funds flow on a quarterly basis.
Risk Management
The Company takes a systematic approach to manage commodity price risk and volatility to ensure sustaining capital, debt servicing requirements and the base dividend are protected through a prudent hedging management program. For the remainder of 2023, approximately 56% of net after royalty oil production is hedged against WTI with an average floor price of greater than US$67.50/bbl. Our strategy focuses on downside protection while maintaining upside opportunity. Tamarack will continue to utilize financial instruments, including base commodity, associated differentials and foreign exchange. Additional details of the current hedges in place can be found in the corporate presentation on the Company website (www.tamarackvalley.ca) or Tamarack's consolidated financial statements and related MD&A for the three and six months ended June 30, 2023, which will be available on SEDAR+ (www.sedarplus.ca).
Investor Call Information July 27, 2023 9:30 AM MDT (11:30 AM EDT) |
Tamarack will host a webcast at 9:30 AM MDT (11:30 AM EDT) on Thursday, July 27, 2023 to discuss the second quarter financial results and an operational update. Participants can access the live webcast via this link or through links provided on the Company's website. A recorded archive of the webcast will be available on the Company's website following the live webcast. |
About Tamarack Valley Energy Ltd.
Tamarack is an oil and gas exploration and production company committed to creating long-term value for its shareholders through sustainable free funds flow generation, financial stability and the return of capital. The Company has an extensive inventory of low-risk, oil development drilling locations focused primarily on Charlie Lake, Clearwater and enhanced oil recovery (EOR) plays in Alberta. Operating as a responsible corporate citizen is a key focus to ensure we deliver on our environmental, social and governance (ESG) commitments and goals. For more information, please visit the Company's website at www.tamarackvalley.ca.
Abbreviations
AECO | the natural gas storage facility located at Suffield, Alberta connected to TC |
ARO | asset retirement obligation; may also be referred to as decommissioning |
bbls | barrels |
bbls/d | barrels per day |
boe | barrels of oil equivalent |
boe/d | barrels of oil equivalent per day |
bopd | barrels of oil per day |
GJ | gigajoule |
IFRS | International Financial Reporting Standards as issued by the International |
IP30 | average production for the first 30 days that a well is onstream |
mcf | thousand cubic feet |
mcf/d | thousand cubic feet per day |
MM | Million |
mmcf/d | million cubic feet per day |
MSW | Mixed sweet blend, the benchmark for conventionally produced light sweet |
NGL | Natural gas liquids |
WCS | Western Canadian select, the benchmark for conventional and oil sands |
WTI | West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, |
Reader Advisories
Notes to Press Release
(1) | See "Specified Financial Measures" |
(2) | Q2 2023 production of 66,738 boe/d comprised of 16,382 bbl/d light and medium oil, 35,373 bbl/d heavy oil, 3,645 bbl/d NGL and 68,027 mcf/d natural gas. |
(3) | Production impacts of approximately 1,500 boe/d comprised of 548 bbl/d light and medium oil, 473 bbl/d heavy oil, 86 bbl/d NGL and 2,349 mcf/d natural gas. |
(4) | Capital expenditures include exploration and development capital, ESG initiatives, facilities land and seismic but exclude asset acquisitions and dispositions as well as ARO. Capital budget includes exploration and development capital, ARO, ESG initiatives, facilities land and seismic but excludes asset acquisitions and dispositions. The key difference between these two metrics is the inclusion (capital budget) or exclusion (capital expenditures) of ARO. |
(5) | Target production is comprised of 17,000-17,500 bbl/d light and medium oil, 34,700-36,500 bbl/d heavy oil, 3,500-4,500 bbl/d NGL and 71,000-75,000 mcf/d natural gas. |
(6) | G&A noted excludes the effect of cash settled stock-based compensation. |
(7) | Tax numbers in the annual guidance numbers are based on 2023 average pricing assumptions of: US$80.00/bbl WTI; US$22.00/bbl WCS; US$3.00/bbl MSW; $4.00/GJ AECO; and $1.3200 CAD/USD. |
(8) | Q2 2023 Clearwater production of 37,800 boe/d is comprised of approximately 35,930 bbl/d heavy oil, 120 bbl/d NGL and 10,479 mcf/d natural gas. |
(9) | Q2 2023 Charlie Lake production of 15,000 boe/d is comprised of approximately 8,620 bbl/d light and medium oil, 2,058 bbl/d NGL and 26,096 mcf/d natural gas. |
(10) | Recent Charlie Lake production of 17,000 boe/d is comprised of approximately 10,100 bbl/d light and medium oil, 2,200 bbl/d NGL and 28,500 mcf/d natural gas. |
(11) | Charlie Lake rates of 12,500 boe/d announced Q2 2021 were comprised of 7,592 bbl/d light and medium oil, 1,642 bbl/d NGL and 19,596 mcf/d natural gas. |
(12) | Charlie Lake rates of 1,100 – 1,200 boe/d comprised of approximately 800 - 900 bbl/d light and medium oil and 1,600 – 1,800 mcf/d natural gas. |
(13) | Charlie Lake rates of 16,000 – 17,000 boe/d for the balance of 2023 comprised of approximately 9,735 bbl/d light and medium oil, 2,145 bbl/d NGL and 27,720 mcf/d natural gas. |
Disclosure of Oil and Gas Information
Unit Cost Calculation. For the purpose of calculating unit costs, natural gas volumes have been converted to a boe using six thousand cubic feet equal to one barrel unless otherwise stated. A boe conversion ratio of 6:1 is based upon an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. This conversion conforms with Canadian Securities Administrators' National Instrument 51 101 - Standards of Disclosure for Oil and Gas Activities ("NI 51-101"). Boe may be misleading, particularly if used in isolation.
References in this press release to "crude oil" or "oil" refers to light, medium and heavy crude oil product types as defined by NI 51-101. References to "NGL" throughout this press release comprise pentane, butane, propane, and ethane, being all NGL as defined by NI 51-101. References to "natural gas" throughout this press release refers to conventional natural gas as defined by NI 51-101.
Forward Looking Information
This press release contains certain forward-looking information (collectively referred to herein as "forward-looking statements") within the meaning of applicable Canadian securities laws. Forward-looking statements are often, but not always, identified by the use of words such as "guidance", "outlook", "anticipate", "target", "plan", "continue", "intend", "consider", "estimate", "expect", "may", "will", "should", "could" or similar words suggesting future outcomes. More particularly, this press release contains statements concerning: Tamarack's business strategy, objectives, strength and focus; the completion of the sale of the minority interest in the Wembley gas plant and the GORR; future consolidation and disposition activity, organic growth and development and portfolio rationalization; future intentions with respect to debt repayment and reduction and return of capital, including enhanced dividends and share buybacks; oil and natural gas production levels, adjusted funds flow and free funds flow; anticipated operational results for the remainder of 2023 including, but not limited to, estimated or anticipated production levels, capital expenditures, drilling plans and infrastructure initiatives; the anticipated benefits of the Company's major infrastructure projects and the costs and timing thereof, including the Wembley gas plant and gas conservation investments; the Company's capital program, guidance and budget for 2023 and flexibility with respect thereto; the potential damage to the Company's facilities and other impacts on operations and production from the Alberta wildfires; expectations regarding commodity prices; the performance characteristics of the Company's oil and natural gas properties; decline rates and enhanced recovery, including waterflood initiatives; exploration activities; continued integration of the Deltastream assets; the ability of the Company to achieve drilling success consistent with management's expectations; risk management activities, including the Company's hedging management program; Tamarack's commitment to ESG principles and sustainability; and the source of funding for the Company's activities including development costs. Future dividend payments and share buybacks, if any, and the level thereof, are uncertain, as the Company's return of capital framework and the funds available for such activities from time to time is dependent upon, among other things, free funds flow financial requirements for the Company's operations and the execution of its growth strategy, fluctuations in working capital and the timing and amount of capital expenditures, debt service requirements and other factors beyond the Company's control. Further, the ability of Tamarack to pay dividends and buyback shares will be subject to applicable laws (including the satisfaction of the solvency test contained in applicable corporate legislation) and contractual restrictions contained in the instruments governing its indebtedness, including its credit facility.
The forward-looking statements contained in this document are based on certain key expectations and assumptions made by Tamarack, including those relating to: the business plan of Tamarack; the satisfaction of all conditions to the completion of the sale of the minority interest in the gas plant and the GORR; the timing of and success of future drilling, development and completion activities; the geological characteristics of Tamarack's properties; the characteristics of recently acquired assets, including the Deltastream assets; the continued integration of recently acquired assets into Tamarack's operations; prevailing commodity prices, price volatility, price differentials and the actual prices received for the Company's products (including expectations concerning narrowing WCS differentials); the availability and performance of drilling rigs, facilities, pipelines and other oilfield services; the timing of past operations and activities in the planned areas of focus; the drilling, completion and tie-in of wells being completed as planned; the performance of new and existing wells; the application of existing drilling and fracturing techniques; prevailing weather and break-up conditions; royalty regimes and exchange rates; impact of inflation on costs; the application of regulatory and licensing requirements; the continued availability of capital and skilled personnel; the ability to maintain or grow the banking facilities; the accuracy of Tamarack's geological interpretation of its drilling and land opportunities, including the ability of seismic activity to enhance such interpretation; and Tamarack's ability to execute its plans and strategies.
Although management considers these assumptions to be reasonable based on information currently available, undue reliance should not be placed on the forward-looking statements because Tamarack can give no assurances that they may prove to be correct. By their very nature, forward-looking statements are subject to certain risks and uncertainties (both general and specific) that could cause actual events or outcomes to differ materially from those anticipated or implied by such forward-looking statements. These risks and uncertainties include, but are not limited to: risks relating to inclement and severe weather events and natural disasters, including fire, drought and flooding, including in respect of safety, asset integrity, shutting in production, impact on production, maintaining 2023 guidance and resumption of operations; risks with respect to unplanned third-party pipeline outages; the risk that future dividend payments thereunder are reduced, suspended or cancelled; unforeseen difficulties in integrating of recently acquired assets into Tamarack's operations, including the Deltastream assets; incorrect assessments of the value of benefits to be obtained from acquisitions and exploration and development programs; risks associated with the oil and gas industry in general (e.g. operational risks in development, exploration and production; and delays or changes in plans with respect to exploration or development projects or capital expenditures); commodity prices; the uncertainty of estimates and projections relating to production, cash generation, costs and expenses, including increased operating and capital costs due to inflationary pressures; volatility in the stock market and financial system; health, safety, litigation and environmental risks; access to capital; the COVID-19 pandemic; and Russia's military actions in Ukraine. Due to the nature of the oil and natural gas industry, drilling plans and operational activities may be delayed or modified to respond to market conditions, results of past operations, regulatory approvals or availability of services causing results to be delayed. Please refer to the Company's AIF for the period ended December 31, 2022 and the MD&A for the period ended June 30, 2023 for additional risk factors relating to Tamarack, which can be accessed either on Tamarack's website at www.tamarackvalley.ca or under the Company's profile on www.sedarplus.ca.The forward-looking statements contained in this press release are made as of the date hereof and the Company does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, except as required by applicable law. The forward-looking statements contained herein are expressly qualified by this cautionary statement.
This press release contains future-oriented financial information and financial outlook information (collectively, "FOFI") about generating sustainable long-term growth in free funds flow, dividends and share buybacks, prospective results of operations and production, weightings, operating costs, 2023 capital budget and expenditures, decline rates, balance sheet strength, realized pricing, adjusted funds flow and free funds flow, net debt, material debt reduction, total returns, the GORR and components thereof, all of which are subject to the same assumptions, risk factors, limitations and qualifications as set forth in the above paragraphs. FOFI contained in this document was approved by management as of the date of this document and was provided for the purpose of providing further information about Tamarack's future business operations. Tamarack and its management believe that FOFI has been prepared on a reasonable basis, reflecting management's best estimates and judgments, and represent, to the best of management's knowledge and opinion, the Company's expected course of action. However, because this information is highly subjective, it should not be relied on as necessarily indicative of future results. Tamarack disclaims any intention or obligation to update or revise any FOFI contained in this document, whether as a result of new information, future events or otherwise, unless required pursuant to applicable law. Readers are cautioned that the FOFI contained in this document should not be used for purposes other than for which it is disclosed herein. Changes in forecast commodity prices, differences in the timing of capital expenditures, and variances in average production estimates can have a significant impact on the key performance measures included in Tamarack's guidance. The Company's actual results may differ materially from these estimates.
References in this press release to peak rates, IP30 and other short-term production 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 of ultimate recovery. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production of Tamarack.
Specified Financial Measures
This press release includes various specified financial measures, including non-IFRS financial measures, non-IFRS financial ratios, capital management measures and supplemental financial measures as further described herein. These measures do not have a standardized meaning prescribed by International Financial Reporting Standards ("IFRS") and, therefore, may not be comparable with the calculation of similar measures by other companies.
"Adjusted Funds Flow (Capital Management Measures)" is calculated by taking cash-flow from operating activities, on a periodic basis, deducting current income tax expense and interest expense (excluding fees) and adding back income tax paid, interest paid, changes in non-cash working capital, expenditures on decommissioning obligations and transaction costs settled during the applicable period. since Tamarack believes the timing of collection, payment or incurrence of these items is variable. Management believes adjusting for estimated current income taxes and interest in the period expensed is a better indication of the adjusted funds generated by the Company. Expenditures on decommissioning obligations may vary from period to period depending on capital programs and the maturity of the Company's operating areas. Expenditures on decommissioning obligations are managed through the capital budgeting process which considers available adjusted funds flow. Tamarack uses adjusted funds flow as a key measure to demonstrate the Company's ability to generate funds to repay debt, pay dividends and fund future capital investment. Adjusted funds flow per share is calculated using the same weighted average basic and diluted shares that are used in calculating income per share, which results in the measure being considered a supplemental financial measure. Adjusted funds flow can also be calculated on a per boe basis, which results in the measure being considered a supplemental financial measure.
"Free Funds Flow and Capital Expenditures (Capital Management Measures)" is calculated by taking adjusted funds flow and subtracting capital expenditures, excluding acquisitions and dispositions. Capital expenditures is calculated as property, plant and equipment additions (net of government assistance) plus exploration and evaluation additions. Management believes that free funds flow provides a useful measure to determine Tamarack's ability to improve returns and to manage the long-term value of the business.
Net Production Expenses, Revenue, net of blending expense, Operating Netback and Operating Field Netback (Non-IFRS Financial Measures, and Non-IFRS Financial Ratios if calculated on a per boe basis) - Management uses certain industry benchmarks, such as net production expenses, revenue, net of blending expense, operating netback and operating field netback, to analyze financial and operating performance. Net production expenses are determined by deducting processing income primarily generated by processing third party volumes at processing facilities where the Company has an ownership interest. Under IFRS this source of funds is required to be reported as income. Where the Company has excess capacity at one of its facilities, it will process third party volumes as a means to reduce the cost of operating/owning the facility, and as such third-party processing revenue is netted against production expenses in the MD&A. Blending expense includes the cost of blending diluent purchased to reduce the viscosity of our heavy oil transported through pipelines to meet pipeline specifications. The blending expense represents the difference between the cost of purchasing and transporting the diluent and the realized price of the blended product sold. In this MD&A, blending expense is recognized as a reduction to heavy oil revenues, whereas blending expense is reported as an expense in the financial statements. Operating netback equals total petroleum and natural gas sales (net of blending), including realized gains and losses on commodity and foreign exchange derivative contracts, less royalties, net production expenses and transportation expense. Operating field netback equals total petroleum and natural gas sales, less royalties, net production expenses and transportation expense. These metrics can also be calculated on a per boe basis, which results in them being considered a non-IFRS financial ratio. Management considers operating netback and operating field netback important measures to evaluate Tamarack's operational performance, as it demonstrates field level profitability relative to current commodity prices.
"Net Debt (Capital Management Measures)" is calculated as credit facilities plus senior unsecured notes, plus deferred acquisition payment notes, plus working capital surplus or deficiency, plus other liability, including the fair value of cross-currency swaps, plus government loans, plus facilities acquisition payments, less notes receivable and excluding the current portion of fair value of financial instruments, decommissioning obligations, lease liabilities and the cash award incentive plan liability.
SOURCE Tamarack Valley Energy Ltd.
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