Calgary, Alberta--(Newsfile Corp. - August 8, 2019) - 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, 2019. Selected financial and operational information is outlined below and should be read in conjunction with Tamarack's unaudited condensed consolidated interim financial statements for the three and six months ended June 30, 2019 and related management's discussion and analysis ("MD&A") which are available on SEDAR at and on Tamarack's website at .
Q2 2019 Financial and Operating Highlights
Production averaged 24,090 boe/d (63% oil and NGL weighting), 4% higher than the previous quarter, and reflected the Company's compliance with the production curtailment order imposed by the Government of Alberta that came into effect on January 1, 2019 (the "Curtailment Order"). Tamarack adjusted the timing of its capital investment and activity in order to comply with the Curtailment Order.
Total adjusted operating field netback (see "Non-IFRS Measures") in Q2/19 was $57.9 million ($0.26/share basic and $0.25/share diluted), 1% higher than the $57.5 million generated in Q1/19 ($0.25/share basic and diluted).
Operating netback (see "Non-IFRS Measures") of $29.14/boe in Q2/19 was 3% lower than the Q1/19 netback of $30.11/boe primarily due to a higher realized commodity hedging loss in the second quarter compared to the previous quarter.
Net production and transportation expenses in Q2/19 were 3% lower at $10.12/boe compared to $10.48/boe in Q2/18 primarily due to increased production from the lower-cost Veteran area and a reduction in transportation expenses for oil produced at Veteran as a result of the recently commissioned pipeline in the Provost area of Alberta (the "Provost Pipeline").
Invested $25.9 million in the quarter, with 61% directed to drill, complete and equip five (5.0 net) Viking oil wells, as well as complete and bring on production 18 (17.7 net) Viking oil wells and two (2.0 net) Cardium oil wells that were drilled in late Q1/19. The Company drilled five (5.0 net) Viking oil wells and four (3.5 net) Cardium oil wells that will be brought on production in Q3/19, as well as two (2.0 net) wells at Veteran that will be used for injection and water sourcing to further contribute to the Company's waterflood program in the area.
Completed a $4.8 million Viking oil acquisition in the Veteran/Consort area of Alberta, adding 130 bbls/d and 9.4 net sections of undeveloped Viking land.
The Company increased its syndicated revolving credit facility by 20% to $350 million from $290 million during the second quarter.
Financial & Operating Results
| Three months ended | Six months ended | |||||||||||||||||
| June 30, | June 30, | |||||||||||||||||
| 2019 | 2018 3 | % change | 2019 | 2018 3 | % change | |||||||||||||
| ($ thousands, except per share) | ||||||||||||||||||
| Total revenue | 98,741 | 107,859 | (8 | ) | 193,788 | 206,595 | (6 | ) | ||||||||||
| Adjusted operating field netback 1 | 57,906 | 61,005 | (5 | ) | 115,409 | 119,550 | (3 | ) | ||||||||||
| Per share - basic 1 | $ | 0.26 | $ | 0.27 | (4 | ) | $ | 0.51 | $ | 0.52 | (2 | ) | ||||||
| Per share - diluted 1 | $ | 0.25 | $ | 0.26 | (4 | ) | $ | 0.50 | $ | 0.51 | (2 | ) | ||||||
| Net income | 16,471 | 3,060 | 438 | 11,646 | 6,354 | 83 | ||||||||||||
| Per share - basic | $ | 0.07 | $ | 0.01 | 600 | $ | 0.05 | $ | 0.03 | 67 | ||||||||
| Per share - diluted | $ | 0.07 | $ | 0.01 | 600 | $ | 0.05 | $ | 0.03 | 67 | ||||||||
| Net debt 1 | (195,892 | ) | (181,341 | ) | 8 | (195,892 | ) | (181,341 | ) | 8 | ||||||||
| Capital expenditures 2 | 25,902 | 52,674 | (51 | ) | 97,145 | 122,304 | (21 | ) | ||||||||||
| Weighted average shares outstanding (thousands) | ||||||||||||||||||
| Basic | 225,989 | 228,040 | (1 | ) | 226,166 | 228,329 | (1 | ) | ||||||||||
| Diluted | 231,152 | 232,310 | - | 231,287 | 232,255 | - | ||||||||||||
| Share Trading (thousands, except share price) | ||||||||||||||||||
| High | $ | 3.09 | $ | 4.66 | (34 | ) | $ | 3.09 | $ | 4.66 | (34 | ) | ||||||
| Low | $ | 1.85 | $ | 2.61 | (29 | ) | $ | 1.85 | $ | 2.31 | (20 | ) | ||||||
| Trading volume (thousands) | 52,198 | 88,082 | (41 | ) | 117,062 | 119,027 | (2 | ) | ||||||||||
| Average daily production | ||||||||||||||||||
| Light oil (bbls/d) | 13,237 | 13,242 | - | 12,965 | 13,240 | (2 | ) | |||||||||||
| Heavy oil (bbls/d) | 521 | 527 | (1 | ) | 502 | 414 | 21 | |||||||||||
| NGL (bbls/d) | 1,423 | 1,355 | 5 | 1,485 | 1,351 | 10 | ||||||||||||
| Natural gas (mcf/d) | 53,451 | 52,376 | 2 | 52,022 | 52,129 | - | ||||||||||||
| Total (boe/d) | 24,090 | 23,853 | 1 | 23,622 | 23,693 | - | ||||||||||||
| Average sale prices | ||||||||||||||||||
| Light oil ($/bbl) | 70.17 | 75.29 | (7 | ) | 67.88 | 71.98 | (6 | ) | ||||||||||
| Heavy oil ($/bbl) | 65.14 | 70.17 | (7 | ) | 53.43 | 61.20 | (13 | ) | ||||||||||
| NGL ($/bbl) | 21.81 | 45.90 | (52 | ) | 31.68 | 45.53 | (30 | ) | ||||||||||
| Natural gas ($/mcf) | 1.71 | 1.65 | 4 | 2.24 | 1.95 | 15 | ||||||||||||
| Total ($/boe) | 45.04 | 49.69 | (9 | ) | 45.32 | 48.17 | (6 | ) | ||||||||||
| Operating netback ($/Boe) 1 | ||||||||||||||||||
| Average realized sales | 45.04 | 49.69 | (9 | ) | 45.32 | 48.17 | (6 | ) | ||||||||||
| Royalty expenses | (4.20 | ) | (5.06 | ) | (17 | ) | (4.52 | ) | (5.11 | ) | (12 | ) | ||||||
| Net production and transportation expenses | (10.12 | ) | (10.48 | ) | (3 | ) | (10.16 | ) | (10.61 | ) | (4 | ) | ||||||
| Operating field netback ($/Boe) 1 | 30.72 | 34.15 | (10 | ) | 30.64 | 32.45 | (6 | ) | ||||||||||
| Realized commodity hedging loss | (1.58 | ) | (3.36 | ) | (53 | ) | (1.03 | ) | (1.99 | ) | (48 | ) | ||||||
| Operating netback | 29.14 | 30.79 | (5 | ) | 29.61 | 30.46 | (3 | ) | ||||||||||
| Adjusted operating field netback ($/Boe) 1 | 26.41 | 28.10 | (6 | ) | 26.99 | 27.88 | (3 | ) | ||||||||||
Notes:
(1) Adjusted operating field netback, net debt, operating field netback and operating netback do not have any standardized meaning prescribed by IFRS and therefore may not be comparable with the calculation of similar measures for other issuers. See "Oil and Gas Metrics" and "Non-IFRS Measures".
(2) Capital expenditures include exploration and development expenditures, but exclude asset acquisitions and dispositions.
(3) IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated.
Second Quarter Review
Through Q2/19, Tamarack remained focused on efficient and responsible development of its high-quality light oil weighted asset base, successfully navigated prevailing volatile commodity price and operating conditions, while continuing to protect the balance sheet and enhance per share metrics. The Company's Q2/19 production averaged 24,090 boe/d (63% oil and NGL weighting), a 4% increase over the previous quarter, due to the positive impact of 18 Viking oil wells and two Cardium oil wells coming on-stream through the period which were drilled and awaiting completion at the end of the first quarter. Tamarack's first half average production of 23,622 boe/d (63% oil and NGL weighting) was within the guidance range of 23,500 boe/d to 23,750 boe/d despite the ongoing Curtailment Order and uncertain market conditions. By adjusting the timing of its drilling and completions activity, the Company was able to rely on expected base production declines rather than shut-in wells to remain below the production limits imposed by the Curtailment Order.
Tamarack invested approximately $25.9 million in capital expenditures during Q2/19, which was more than fully funded by the $57.9 million of adjusted operating field netback generated during the period. Similarly, in the first half of 2019, capital expenditures totaled $97.1 million and were below the $115.4 million of adjusted operating field netback, continuing the Company's trend to date in 2019 of underspending funds being generated. The intentional allocation of the Company's Q2/19 capital expenditures ensured compliance with the Curtailment Order and resulted in Tamarack's oil and NGL weighting averaging 63% compared to 64% in the previous quarter.
During the second quarter, the Company drilled, completed and equipped 5.0 net Viking oil wells and also completed and brought on production 18 (17.7 net) Viking oil wells and 2.0 net Cardium oil wells that were drilled in late Q1/19. Tamarack also drilled 5.0 net Viking oil wells and four (3.5 net) Cardium oil wells that will be brought on production in Q3/19 and continued to advance the Company's waterflood program in the Veteran area, drilling one net water source and one net water injection well. Encouraging results from the Veteran waterflood to date support Tamarack's intention to continue directing capital to this project.
Tamarack's Q2/19 operating netback averaged $29.14/boe, only 5% lower than Q2/18 despite a 9% reduction in average realized sales prices due to weaker benchmark liquids prices. The Company's operating netback was supported by a 3% reduction in net production and transportation expenses from $10.48/boe in Q2/18 to $10.12/boe in Q2/19. This reduction was related to increased production from the lower-cost Veteran area and lower transportation expenses for oil produced at Veteran associated with the recently commissioned Provost Pipeline. Tamarack's operating netback also reflects a 17% reduction in royalty expense per boe and a 53% reduction in realized commodity hedging loss per boe year-over-year. As a result, the Company recorded Q2/19 total adjusted operating field netbacks of $57.9 million ($0.26/share basic and $0.25/share diluted), 1% higher than Q2/18.
During the second quarter bank renewal process, the Company increased its revolving credit facility in the amount of $320 million and a $30 million operating facility (collectively, the "Facility") with a syndicate of lenders. The Facility, totaling $350 million, lasts for a 365-day period and will be subject to its next 365-day extension by May 31, 2020. If not extended on May 31, 2020, the Facility will cease to revolve and all outstanding balances will become repayable one year from that date. At June 30, 2019, $186.9 million was drawn on the Facility. There are no financial covenants governing this Facility. The accordion feature that was added to the lending agreement in the fourth quarter of 2018 allows Tamarack to increase the revolving credit facility portion to $370 million, for a total Facility of $400 million, upon exercise and syndicate approval. The accordion feature bears no fees, including standby, until exercised. As at June 30, 2019, the accordion feature had not been exercised.
Operational Execution Supports Long-Term Fundamentals
As a result of its second quarter capital activities, Tamarack successfully added 1,672 boe/d in Veteran (77% oil and NGL), 1,367 boe/d in Wilson Creek/Alder Flats (67% oil and NGL) and 77 boe/d in Penny (97% oil and NGL). A $4.8 million Viking oil acquisition in the Veteran/Consort area of Alberta that was completed in the second quarter further enhanced Tamarack's acreage position while adding 130 boe/d and 9.4 net sections of undeveloped lands adjacent to the Company's existing acreage.
In addition, the Company directed capital to the continued development of its waterflood program in Veteran, Alberta. The waterflood project is designed to improve oil recoveries, reduce corporate decline rates and increase production rates while utilizing Tamarack's existing and owned infrastructure. During the quarter, the Company had nine active water injector wells which contributed to waterflood injection volumes of 11,000 bbls/d during the second quarter. Tamarack remains committed to enhancing its sustainability and anticipates positive impacts on decline rates and reserve bookings will be realized commencing in 2020. Given the compelling initial results realized to date, coupled with the expectation that the Curtailment Order will remain in place through the balance of 2019, Tamarack intends to reallocate a portion of its 2019 drilling capital to the waterflood, as outlined below.
During the second quarter, Tamarack received approval from the Toronto Stock Exchange to renew its normal course issuer bid ("NCIB") under the same terms. In the first half of the year, Tamarack invested $2.2 million to purchase and cancel 926,900 of its common shares ("Common Shares") under the NCIB program. Over and above the NCIB program, during Q2/19 the Company directed $1.25 million to purchase 498,700 Common Shares in the open market which are held in trust by Tamarack's trustee and used to settle restricted share units ("RSUs") upon future exercises. The NCIB program and open market purchases support the Company's commitment to generating per share value and provide management with an instrument that can be employed when there is a perceived misalignment between the Company's prevailing share price and the underlying current and future potential value of its assets. In addition, these programs help to offset the dilutive impact that may be associated with the exercise and settlement of options, RSUs and performance share units issued under Tamarack's stock-based compensation programs. As at June 30, 2019, Tamarack's trustee held a total of 1,027,694 Common Shares in trust.
Tamarack's net debt (see "Non-IFRS Measures"), including working capital deficiency but excluding the fair value of financial instruments and lease liabilities, totaled $195.9 million as at June 30, 2019, a reduction of approximately 11% relative to the end of the previous quarter. Tamarack's Q2/19 net debt to annualized adjusted operating field netback ratio (see "Non-IFRS Measures") was 0.8 times.
2019 Outlook Assuming Curtailment Order Remains Intact
In light of ongoing uncertainty with respect to the general operating environment in Western Canada, Tamarack is constantly assessing capital allocation decisions with the view to optimizing balance sheet strength and per share metrics while complying with the Curtailment Order. Based on the assumption that the Curtailment Order will be extended to the end of 2019, Tamarack will continue to adjust the timing and allocation of its capital expenditure program to ensure ongoing compliance. The Company's original 2019 capital expenditure budget of $170 to $180 million (excluding tuck-in acquisitions) forecast the drilling of 125 net wells, including Viking wells in Alberta and Saskatchewan, Cardium oil wells in Wilson Creek and oil wells in Penny. The Company continues to expect that 2019 capital will be fully funded by total adjusted operating field netback based on current strip WTI prices.
Although total capital levels for 2019 remain unchanged, Tamarack has adjusted its planned capital activities, including reducing its forecast drilling count to approximately 117 net wells. In addition, the Company intends to redirect drilling capital from its Alberta Viking area to the Saskatchewan Viking play, where associated natural gas rates are slightly higher. As a result, exit production will reflect a modestly lower oil and NGL weighting (62% to 65%). Despite this meaningful capital reallocation, Tamarack continues to forecast average annual production within the original guidance range, with exit production anticipated to be at the lower end of the guidance range of 25,500 boe/d, and the upper end slightly tightened to 25,750 boe/d assuming the Curtailment Order is sustained through the second half of 2019 and legacy production performance continues.
In light of the Veteran waterflood results to date, the Company has shifted a portion of its second half 2019 drilling capital to the waterflood program. Approximately $5 to $7 million of capital that was earmarked for Viking drills under the original budget will be directed to the Veteran waterflood adding an additional six Veteran injector wells. This shift will increase the total number of injector wells at Veteran from 21 to 27 and add three incremental new water source wells by year end. The decision to reallocate capital in the second half of 2019 supports the Company's long-term sustainability and demonstrates the outperformance of its legacy production volumes given reduced drilling with no change to production guidance ranges.
Due to Tamarack's success in accumulating an inventory of Viking and Cardium locations that payout in 1.5 years or less at current commodity prices, the Company expects to be fully self-funding in 2019 and estimates it will achieve a 3% to 5% increase in debt-adjusted production per share in Q4/19 compared to Q4/18. Based on current strip prices, Tamarack's 2019 capital program is forecast to generate approximately $40 million to $50 million of adjusted operating field netback over and above budgeted capital expenditures (excluding tuck-in acquisitions), which can be directed to further asset enhancements through acquisition or incremental share buy-backs under its active NCIB program. Without the shift in capital to the waterflood, the excess adjusted operating field netback would have been even higher.
The Company's capital allocation strategy over the past several years has remained consistent with the objective of achieving sustainability at low oil prices, while generating debt-adjusted production per share growth. With approximately 30% of its 2019 production protected with hedges including a US$60.00/bbl WTI put option and another approximately 3% protected by fixed price contracts at US$64.60/bbl, Tamarack remains well positioned to withstand further crude oil price volatility.
Assuming the Curtailment Order remains in effect through the second half of 2019, Tamarack's 2019 guidance and assumptions are reaffirmed below.
Annual average production between 23,500 boe/d and 24,500 boe/d (64% to 66% oil and NGL), with 2019 exit production estimated between 25,500 boe/d and 25,750 boe/d (62% and 65% oil and NGL).
Capital expenditures between $170 million and $180 million.
Estimated year end 2019 net debt to Q4 annualized adjusted operating field netback ratio of approximately 1.0 times with an estimated $100 million of liquidity on existing credit facilities.
Average 2019 commodity price assumptions of WTI US$50.00/bbl, Edmonton Par C$52.33/bbl, WTI / Edmonton Par differential of US$10.75/bbl, AECO $1.31/GJ and a Canadian/US dollar exchange rate of $0.75.
Tamarack's strategy remains focused on preserving balance sheet strength and remaining flexible with capital spending in the face of continued commodity price and crude oil price differential volatility.
Promotion of New VP of Corporate Planning and Business Development
Tamarack is pleased to announce the promotion of Martin Malek to the position of Vice President, Corporate Planning and Business Development. Mr. Malek has been with Tamarack since 2014 as the Manager of Business Development. He graduated from the University of Calgary with a BSc in Chemical Engineering and spent the first nine years of his career with Apache in both the Calgary and Midland, Texas offices as a reservoir engineer. Mr. Malek is a member of the Association of Professional Engineers and Geoscientists (APEGA).
About Tamarack Valley Energy Ltd.
Tamarack is an oil and gas exploration and production company committed to long-term growth and the identification, evaluation and operation of resource plays in the Western Canadian Sedimentary Basin. Tamarack's strategic direction is focused on two key principles: (i) targeting repeatable and relatively predictable plays that provide long-life reserves; and (ii) using a rigorous, proven modeling process to carefully manage risk and identify opportunities. The Company has an extensive inventory of low-risk, oil development drilling locations focused primarily in the Cardium and Viking fairways in Alberta that are economic over a range of oil and natural gas prices. With this type of portfolio and an experienced and committed management team, Tamarack intends to continue delivering on its strategy to maximize shareholder returns while managing its balance sheet.
Abbreviations
bbls | barrels |
bbls/d | barrels per day |
boe | barrels of oil equivalent |
boe/d | barrels of oil equivalent per day |
Mboe | thousand barrels of oil equivalent |
mcf | thousand cubic feet |
GJ | gigajoule |
MMcf | million cubic feet |
Mbbls | thousand barrels |
mcf/d | thousand cubic feet per day |
WTI | West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma for the crude oil standard grade |
AECO | the natural gas storage facility located at Suffield, Alberta connected to TransCanada's Alberta System |
IFRS | International Financial Reporting Standards as issued by the International Accounting Standards Board |
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 National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities. Boe may be misleading, particularly if used in isolation.
Reserves Disclosure. All reserve references in this press release are "Company interest reserves". Company interest reserves are the Company's total working interest reserves before the deduction of any royalties and including any royalty interests payable the Company. It should not be assumed that the present worth of estimated future cash flow presented herein represents the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. The recovery and reserve estimates of Tamarack's crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquids reserves may be greater than or less than the estimates provided herein.
Oil and Gas Metrics. This press release contains metrics commonly used in the oil and natural gas industry, such as operating field netback and operating netback.
"Operating field netback" is calculated as total petroleum and natural gas sales, less royalties and net production and transportation costs.
"Operating netback" is calculated as total petroleum and natural gas sales, including realized gains and losses on commodity, foreign exchange and interest rate derivative contracts, less royalties and net production and transportation costs.
These terms have been calculated by management and do not have a standardized meaning and may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons. Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare Tamarack'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 press release, should not be relied upon for investment or other purposes.
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; operational execution and the ability of the Company to achieve drilling success consistent with management's expectations; commodity prices; market conditions impacting realized prices; the Company's ability to withstand commodity price volatility; drilling plans including the timing of drilling; 2019 waterflood projects and the impact thereon on oil recoveries, corporate decline rates and production rates; the payout of wells and the timing thereof; expectations regarding timing of development of current inventory; oil and natural gas production levels, including annual average production and exit production in 2019; changes in decline rates and reserve bookings and the timing realization thereof; oil and liquids weighting and changes thereto; the 2019 drilling program, capital budget and guidance, including the Company's expectations to be self-sustaining in 2019; Tamarack's intent to use excess total adjusted operating field netback to purchase Common Shares under the NCIB program; future settlements of RSUs; liquidity on existing credit facilities; shareholder returns; enhanced per share metrics; the duration and impact of the Curtailment Order; the Company's compliance with the Curtailment Order; the Company's expectation that Viking and Cardium oil wells will be brought on production in Q3/19 and its impact on production in 2019; future use of the additional wells in Veteran; estimate of adjusted operating field netback generated from Tamarack's 2019 capital program; estimates for debt-adjusted production per share in 2019; and the re-evaluation of Tamarack's capital allocation strategy. Statements relating to "reserves" are also deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future.
Tamarack remains committed to enhancing its sustainability and anticipates positive impacts on decline rates and reserve booking will be realized commencing in 2020.
The forward-looking statements contained in this document are based on certain key expectations and assumptions made by Tamarack, including relating to: prevailing commodity prices, price volatility, price differentials and the actual prices received for the Company's products; 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 lifting of the Curtailment Order and the timing thereof; accumulating an inventory of Viking and Cardium locations that payout in 1.5 years or less at current commodity prices; 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; the application of regulatory and licensing requirements; the continued availability of capital and skilled personnel; the ability to maintain or grow the banking facilities; and the accuracy of Tamarack's geological interpretation of its drilling and land opportunities, including the ability of seismic activity to enhance such interpretation.
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 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; health, safety, litigation and environmental risks; and access to capital. Due to the nature of the oil and natural gas industry, drilling plans and operational activities may be delayed or modified to react to market conditions, results of past operations, regulatory approvals or availability of services causing results to be delayed. Please refer to the MD&A for additional risk factors relating to Tamarack, which can be accessed either on Tamarack's website at or under the Company's profile on and the Company's annual information form for the year ended December 31, 2018.
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 Tamarack's prospective results of operations, production, net debt, debt-adjusted production per share, estimated year end 2019 net debt to Q4 annualized adjusted operating field netback ratio 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 made as of the date of this document and was provided for the purpose of providing further information about Tamarack's future business operations. 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.
Non-IFRS Measures
Certain financial measures referred to in this press release, such as net debt, debt-adjusted production per share, adjusted operating field netbacks and net debt to annualized adjusted operating field netback ratio, are not prescribed by IFRS. Tamarack uses these measures to help evaluate its financial and operating performance as well as its liquidity and leverage. These non-IFRS financial measures do not have any standardized meaning prescribed by IFRS and therefore may not be comparable to similar measures presented by other issuers.
"Net debt" is calculated as long-term debt plus working capital surplus or deficit excluding the fair value of financial instruments and lease liabilities.
"Debt-adjusted production per share" is a measure of changes in production on a per share basis, with the number of shares adjusted based on changes to net debt outstanding for the periods being compared. Debt-adjusted share count is calculated as total shares outstanding plus incremental shares issued at a current market price, being $2.30 per Common Share, to eliminate the change in net debt or in the case where debt decreases the reduction in shares using the same $2.30 per Common Share. Management of Tamarack believes that debt adjusted production per share is useful in determining the production growth on a per share basis as if changes to debt was extinguished by the issuance or redemption of shares. The presentation of production growth on a per share basis is skewed for oil and gas companies that have more debt on their balance sheet and in their capital structure. Such companies will show better results because more of their growth is financed through debt than equity (as opposed to generating growth through realizing a rate of return on capital employed). The debt-adjusted production per share measure provides a means of putting oil and gas companies on an equal, enterprise-based footing with respect to debt when calculating per share numbers. This measure is relevant to investors to appreciate the impact the debt on a company's balance sheet has on per share growth disclosure and the strength of one company's balance sheet relative to an over-leveraged peer, particularly in volatile commodity price environments where a company's indebtedness may increase as a result of lower cash flows and higher debt financing costs.
"Adjusted operating field netback" is calculated by taking net income or loss before taxes and adding back items, including transaction costs, and certain non-cash items including stock-based compensation; accretion expense on decommissioning obligations; depletion, depreciation and amortization; impairment; unrealized gain or loss on financial instruments; and gain or loss on dispositions.
"Net debt to annualized adjusted operating field netback ratio" is calculated as net debt divided by annualized adjusted operating field netback for the most recent quarter.
Please refer to the MD&A for additional information relating to Non-IFRS measures. The MD&A can be accessed either on Tamarack's website at or under the Company's profile on .
For additional information, please contact:
Brian Schmidt Ron Hozjan
President & CEO VP Finance & CFO
Tamarack Valley Energy Ltd. Tamarack Valley Energy Ltd.
Phone: 403.263.4440 Phone: 403.263.4440
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