CALGARY, Alberta, May 10, 2018 (GLOBE NEWSWIRE) — Tamarack Valley Energy Ltd. (“Tamarack” or the “Company”) (TSX:TVE) is pleased to announce its financial and operating results for the three months ended March 31, 2018. Selected financial and operational information is outlined below and should be read in conjunction with Tamarack’s unaudited condensed consolidated interim financial statements (“Financial Statements”) for the three months ended March 31, 2018 and related management’s discussion and analysis (“MD&A”) which are available on SEDAR at www.sedar.com and on Tamarack’s website at www.tamarackvalley.ca.
Q1 2018 Financial and Operating Highlights
- Achieved record corporate production in Q1/18 of 23,532 boe/d, up 3% over Q4/17 of 22,807 boe/d and up 32% over Q1/17 volumes of 17,796 boe/d.
- Oil and natural gas liquids (“NGL”) weighting was 63% in Q1/18 compared to 57% in the same period of 2017, representing an increase of 11%, which positively contributed to the Company’s stronger netbacks year-over-year.
- Total adjusted operating field netbacks (previously referred to as “adjusted funds flow”; see Non-IFRS Measures) increased 81% to $58.5 million in Q1/18 ($0.26/share basic and $0.25/share diluted), from $32.4 million in Q1/17 ($0.15/share basic and diluted).
- Maintained healthy net debt to annualized Q1/18 adjusted operating field netback ratio of 0.8 times at the end of Q1/18, compared to 1.3 times at the end of Q1/17.
- Operating netbacks of $30.11/boe in Q1/18 increased by 31% over Q1/17 primarily due to the 11% increase in oil and NGL weighting, and the 18% increase in the combined average realized prices for oil and NGL.
- Net production and transportation expenses in Q1/18 were 6% lower at $10.76/boe compared to $11.42/boe in Q1/17.
- Invested $69.6 million on drilling, completing and equipping nine (9.0 net) Cardium oil wells, 29 (28.0 net) Viking oil wells and five (4.7 net) Redwater oil wells. The Company also completed and brought on production 15 (14.4 net) Viking oil wells that were drilled in late Q4/17 and drilled eight (8.0 net) Viking oil wells that will be brought on production in the second quarter of 2018.
- Executing on the Company’s strategy of continuing to add high quality drilling inventory, closed one tuck-in acquisition totaling $2.5 million in the Wilson Creek area of Alberta, adding 18 boe/d and 3.3 (2.1 net) sections of undeveloped land. The Company drilled two Cardium wells on these lands in Q1/18.
- Tamarack maintained the $290 million borrowing base on its revolving credit facility (the “Facility”). The Company’s syndicate of lenders provided an option to increase the borrowing base during the formal annual review period, which is expected to be completed by the end of May 2018.
Financial & Operating Results
|Three months ended
|($ thousands, except per share)|
|Adjusted operating field netback 1||58,545||32,356||81|
|Per share – basic 1||$||0.26||$||0.15||73|
|Per share – diluted 1||$||0.25||$||0.15||67|
|Net income (loss)||3,294||2,290||44|
|Per share – basic||$||0.01||$||0.01||–|
|Per share – diluted||$||0.01||$||0.01||–|
|Net debt 1||(186,732||)||(165,561||)||13|
|Capital Expenditures 2||69,630||63,721||9|
|Weighted average shares outstanding (thousands)|
|Share Trading (thousands, except share price)|
|Trading volume (thousands)||30,945||80,868||(62||)|
|Average daily production|
|Light oil (bbls/d)||13,239||7,891||68|
|Heavy oil (bbls/d)||299||484||(38||)|
|Natural gas (mcf/d)||51,879||45,852||13|
|Average sale prices|
|Light oil ($/bbl)||67.92||63.02||8|
|Heavy oil ($/bbl)||45.23||44.64||1|
|Natural gas ($/mcf)||2.25||2.89||(22||)|
|Operating netback ($/Boe) 1|
|Average realized sales||46.62||39.25||19|
|Operating field netback ($/Boe) 1||30.70||23.68||30|
|Realized commodity hedging gain (loss)||(0.59||)||(0.77||)||23|
|Operating netback 1||30.11||22.91||31|
|Adjusted operating field netback ($/Boe) 1||27.64||20.20||37|
|(1)||Adjusted operating field netback, net debt 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.|
First Quarter Review
Tamarack demonstrated another strong quarter with positive momentum and results coming from each of its core areas: the Cardium light oil play at Wilson Creek/Alder Flats; the Viking oil play across Alberta and Saskatchewan; and the Barons Sand oil play at Penny. The first quarter is typically one of Tamarack’s most active operational periods which attracts a higher proportion of capital expenditures, and 2018 proved consistent with historical trends.
Successful Operational Execution
During the first quarter of 2018, the Company drilled, completed and equipped nine (9.0 net) Cardium oil wells, 29 (28.0 net) Viking oil wells, five (4.7 net) Redwater oil wells and completed and brought on production 15 (14.4 net) Viking oil wells that were drilled in late Q4/17. Due to the prolonged winter, Tamarack elected to drill two additional Cardium wells, the first of which spud on March 28, 2018, that are expected to be completed later in Q2/18. In addition to the two wells drilled late in Q1/18, the Company has numerous wells expected to come on production in Q2/18 after spring breakup which will positively impact volumes in that period, including two Cardium wells drilled and completed during Q1, along with eight (8.0 net) Viking oil wells that were drilled late in Q1/18. In addition, Tamarack expects to spud the first of three wells at Penny later in Q2/18.
First quarter production of 23,532 boe/d was slightly above the upper end of Tamarack’s first half guidance range of 22,750 to 23,250 boe/d with an oil and NGL weighting of 63%. During the first quarter, new wells in Veteran came on stream at higher rates than expected causing higher operating pressures in the gathering system and production from older legacy wells being backed out. The Company completed the second phase of the Veteran oil battery expansion on March 21, 2018, slightly ahead of schedule and on budget, which brought capacity up to 10,000 bbls of oil per day. With completion of the Veteran gas plant recommissioning expected in late Q2/18, volume constraints are expected to be addressed and operating costs will be reduced as solution gas can be processed by Tamarack rather than third parties. During the first quarter, the Company invested $72.4 million in capital expenditures and property acquisitions (net of dispositions), funded approximately 81% by Tamarack’s $58.5 million adjusted operating field netback (previously referred to as “adjusted funds flow”; see Non-IFRS Measures) generated in the period.
Revenue for the quarter increased 57% over Q1/17 primarily due to increased production volumes and realized oil and NGL prices, while revenue increased 3% over Q4/17. Increased production volumes, a higher oil and NGL weighting and a reduction in operating costs positively contributed to Tamarack’s operating netback which averaged $30.11/boe in Q1/18, representing a 31% increase compared to Q1/17. As a result of increased production volumes from the Veteran area, where operating costs are lower than the corporate average, overall production and transportation expenses per boe were lower in the quarter compared to Q1/17. Tamarack has further allocated capital to incremental projects designed to support the ongoing management of increased production at facilities controlled by the Company and to further reduce the associated operating costs. The first of the two phases of the battery expansion at Veteran in Q3/17 positively contributed to the overall reduction in operating costs while the second phase, which was finalized in Q1/18, will increase emulsion processing capacity that will also reduce operating costs. Tamarack has allocated initial costs to reactivate the Veteran gas plant which will address current curtailment issues and accommodate the Company’s expected production growth through 2018.
Strengthening Commodity Environment
WTI crude oil markets remained strong during the first quarter of 2018 and into May showed continued growth, reaching two-year highs that surpassed US$70.00/bbl. The average first quarter WTI price of US$62.91/bbl was 14% higher than the average fourth quarter price of US$55.39/bbl. With significant improvements in the WTI markets, despite widening Edmonton Par / WTI differentials, Tamarack’s realized Q1/18 light oil price increased 4% to $67.92/bbl from $65.08/bbl in Q4/17.
The Company’s realized natural gas prices increased 19% to $2.25/mcf in the first quarter of 2018 compared to $1.89/mcf in the previous quarter. This was slightly less than the AECO daily benchmark price increase of 23% however, still a premium to the AECO daily index for the first quarter of 2018, reflecting Tamarack’s efforts to reduce exposure to the persistently weak local Alberta gas market. As previously announced, effective April 1, 2018, approximately 40% of Tamarack’s natural gas production receives pricing from various markets that have historically outperformed AECO, including Malin (16%), Chicago (8%), Dawn (8%) and Mich Con (8%). Tamarack has committed to continue to proactively take steps to mitigate gas price weakness by reducing exposure to the AECO pricing hub in concert with increasing its oil and NGL weighting.
Tamarack intends to continue building on the operational momentum realized in the first four months of 2018 with a robust Q2/Q3 2018 drilling program which anticipates the drilling, completing and equipping of 8.5 net Cardium oil wells, 39.4 net Alberta Viking oil wells, 7.6 net Saskatchewan Viking oil wells and 3 Penny oil wells.
In response to the current low natural gas price environment, the Company has shut-in approximately 400 boe/d of natural gas production. As Tamarack is currently ahead of production guidance, the Company anticipates the shut- in gas will not affect the original 2018 production forecast.
For the full year 2018, Tamarack is targeting 10-15% debt-adjusted production per share growth over 2017 with increased liquids weighting and higher netbacks, while maintaining net debt to annualized Q4/18 total adjusted field operating netback ratio of less than one times.
In the interest of preserving and enhancing shareholder value, the Company recently implemented a normal course issuer bid (“NCIB”) through the facilities of the Toronto Stock Exchange and alternate trading platforms. Tamarack believes that its share price is undervalued at times and accordingly, will make use of excess total adjusted operating field netbacks (see Non-IFRS Measures) to purchase shares through the NCIB program. As of May 9, 2018, the Company spent $836,827 to purchase and cancel 243,500 outstanding common shares under the NCIB. In addition to utilizing excess total adjusted operating field netbacks for the NCIB, Tamarack intends to continue supplementing its attractive asset base by completing tuck-in acquisitions within core areas where the Company has a low-cost operating advantage. These actions, along with increased production volumes and a higher weighting of oil and NGL in the production mix, demonstrate the value and benefit of the Company’s unique returns- based growth model.
The Company also announces the retirement of Mr. Dean Setoguchi from the Company’s board of directors. Mr. Setoguchi served on the Board of Tamarack since the business combination and reorganization was completed in June, 2010. Tamarack’s board and management team would like to thank Mr. Setoguchi for his numerous contributions to the Company as a Director and Chairman of the Audit Committee and wish him all the best in his future endeavors.
The Company’s 2018 guidance is reiterated below:
- Tamarack expects first half average production to be within the upper end of the original guidance range of 22,750 to 23,250 boe/d.
- The original $195-205 million capital budget for 2018 remains unchanged with approximately 50% expected to be spent during the first half of 2018. The Company may elect to accelerate capital into Q2/18 from Q3 if spring break-up ends early.
Tamarack’s key 2018 guidance is summarized in the following table:
|Average annual production (boe/d)||22,500 – 23,500|
|Liquids weighting (%)||~64 – 66|
|Exit production (boe/d)||24,000 – 24,500|
|Liquids weighting (%)||~65 – 67|
|Annual capital expenditure range ($millions)||$195 to $205|
|Year end 2018 net debt(1) to Q4 annualized adjusted operating field netback(2) ratio (including hedges)||<1.0 times|
|Liquidity on existing credit facilities ($millions)||~$100|
|2018 price assumptions:|
|Edmonton Par ($CDN/bbl)||$64.60|
|Canadian/US dollar exchange rate||$0.79|
|(1)||Refer to definition of net debt under “Non-IFRS Measures”|
|(2)||Refer to definition of adjusted operating field netback under “Non-IFRS Measures”|
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 – targeting repeatable and relatively predictable plays that provide long-life reserves, and 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.
|bbls/d||barrels per day|
|boe||barrels of oil equivalent|
|boe/d||barrels of oil equivalent per day|
|Mboe||thousands barrels of oil equivalent|
|mcf||thousand cubic feet|
|MMcf||million cubic feet|
|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|
Oil and Gas Advisories
Unit Cost Calculation. For the purpose of calculating unit costs, natural gas volumes have been converted to a barrel of oil equivalent 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. Boe may be misleading, particularly if used in isolation.
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” equals total petroleum and natural gas sales less royalties and operating costs calculated on a boe basis.
“Operating netback” is the operating field netback with realized gains and losses on commodity derivative contracts on a boe basis.
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.
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 “target”, “plan”, “continue”, “intend”, “ongoing”, “estimate”, “expect”, “may”, “should”, or similar words suggesting future outcomes. More particularly, this press release contains statements concerning: Tamarack’s business strategy, objectives, strength and focus; an increase in netbacks; the ability of the Company to achieve drilling success consistent with management’s expectations; strategies to minimize exposure to Alberta gas market fluctuations, including hedging and diversifying gas sales; drilling plans including the timing of drilling; the reactivation of the Veteran gas plant; the NCIB; the payout of wells and the timing thereof; tuck-in acquisitions in Tamarack’s core areas: oil and natural gas production levels, including the impact of shut-in gas thereon; the availability, terms, use and renewal of the Facility; timing and level of 2018 capital expenditures; 2018 exit debt; forecast 2018 annual production range and liquid weighting percentage; 2018 production guidance; 2018 drilling program; and shareholder returns. The forward-looking statements contained in this document are based on certain key expectations and assumptions made by Tamarack relating to prevailing commodity prices, the availability of drilling rigs and other oilfield services, the cost of such 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, 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. Although management considers these assumptions to be reasonable based on information currently available to it, 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 (e.g. operational risks in development, exploration and production; 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 Tamarack’s annual information form for the year ended December 31, 2017 (the “AIF”) for additional risk factors relating to Tamarack. The AIF can be accessed either on Tamarack’s website at www.tamarackvalley.ca or under the Company’s profile on www.sedar.com.
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, net debt to adjusted operating field netback ratio, adjusted operating field netback, operating netbacks, operating costs, capital expenditures and components thereof, all of which are subject to the same assumptions, risk factors, limitations and qualifications as set forth in the above paragraphs and the assumption outlined in the Non-IFRS Measures section below. FOFI 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 Tamarack’s anticipated future business operations. Tamarack disclaims any intention or obligation to update or revise any FOFI contained in this press release, 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 press release should not be used for purposes other than for which it is disclosed herein.
Certain financial measures referred to in this press release, such as net debt, adjusted funds flow, net debt to annualized adjusted operating field netback, cash flow, adjusted operating field netbacks and net debt to 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 adjusted for risk management contracts.
“Total adjusted operating field netback” is calculated as net income or loss before taxes and adding back items including: transaction costs; and deducting non-cash items including: stock-based compensation; accretion expense on decommissioning obligations; depletion, depreciation and amortization; and impairment; unrealized gain or loss on financial instruments; and gain or loss on dispositions.
“Adjusted funds flow” is calculated based on cash flows from operating activities before changes in non- cash working capital, transaction costs and abandonment expenditures are incurred.
“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.
“Debt-adjusted production per share” represents the Tamarack’s production per share after adjusting for debt.
“Cash flow” is determined as gross oil, natural gas and natural gas liquids revenues including realized gains on commodity risk management contracts, less the following: royalties, operating costs, transportation costs, general and administrative costs and finance expenses.
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 www.tamarackvalley.ca or under the Company’s profile on www.sedar.com.
For additional information, please contact:
President & CEO
Tamarack Valley Energy Ltd.
VP Finance & CFO
Tamarack Valley Energy Ltd.