CALGARY, Alberta, Nov. 08, 2017 (GLOBE NEWSWIRE) -- Tamarack Valley Energy Ltd. (TSX:TVE) (“Tamarack” or the “Company”) is pleased to announce its financial and operating results for the three and nine months ended September 30, 2017. Selected financial and operational information is set out below and should be read in conjunction with Tamarack’s unaudited condensed consolidated interim financial statements for the three and nine months ended September 30, 2017 and related management’s discussion and analysis (“MD&A”), which are available for review on SEDAR at www.sedar.com or on Tamarack’s website at www.tamarackvalley.ca.
Q3 2017 Financial and Operating Highlights
- Achieved record corporate production in Q3/17 of 20,541 boe/d, up 6% over Q2/17 and more than 90% over Q3/16.
- Based on field estimates, exited October at 22,000 boe/d achieving its guided 2017 exit rate and remaining on target to average toward the higher end of annual production guidance of 19,000-20,000 boe/d, with Q4/17 exit net debt to annualized funds from operations ratio expected at approximately 1.0 times, assuming current strip prices.
- Oil weighting increased to 52% compared to 45% in Q3/16, driving improved netbacks, while light oil production grew 7% over Q2/17. Liquids weighting also increased to 59% in Q3/17 compared to 55% in the same period of 2016.
- Total funds from operations increased 103% to $34.8 million in Q3/17 ($0.15/share basic and diluted), from $17.2 million in Q3/16 ($0.13/share basic and diluted), and increased 3% compared to Q2/17 despite significantly lower quarter-over-quarter natural gas prices.
- Aided by continual access to service providers and dry summer conditions, Tamarack executed the majority of its planned second half capital program during the third quarter of 2017, investing $74.1 million to drill 50 (48.6 net) Viking oil wells, eight (8.0 net) Cardium oil wells, one (0.8 net) Ellerslie oil well, one (1.0 net) Mannville gas well, and two (2.0 net) heavy oil wells.
- Continued to execute on various tuck-in land acquisitions within core areas to bolster Tamarack’s footprint, including four separate purchases totaling 145 net sections of land for an aggregate purchase price of $3.4 million during Q3/17. Subsequent to the end of the quarter, completed a minor tuck-in acquisition within the Company’s core Viking area for $5.5 million comprised of 9.75 net sections of land, 42 boe/d of associated production and 54 low-risk, quick-payback drilling locations.
- Tamarack intends to accelerate $10-15 million of Q1/18 capital into the Company’s Q4/17 program, which when combined with Tamarack’s tuck-in acquisitions, will result in an increased full year 2017 capital program of $195-198 million. The Company forecasts that capital spending over the next two quarters (Q4/17 and Q1/18) will approximate funds flow from operations generated through that period, based on current strip prices.
- Realized a 5% reduction in production expenses in Q3/17 over Q2/17 driven by the elimination of higher third party processing fees with the partial restart of the TransGas Coleville Gas Plant (“Coleville Plant”), as well as reduced trucking and disposal costs following completion of the Veteran oil battery expansion and installation of water handling in the latter half of Q3/17.
- General and administrative (“G&A”) expenses declined a further 7% in Q3/17 to $1.62/boe over Q2/17 and were 14% lower than Q3/16, reflecting significant production growth without commensurate increases in overhead.
Financial & Operating Results
| ($ thousands, except per boe) | Three months ended | Nine months ended |
| September 30, | September 30, |
| | | 2017 | | | 2016 | | % change | | 2017 | | | 2016 | | % change |
| ($, except per share) | | | | | | |
| Total Revenue | | 63,927 | | | 31,588 | | 102 | | | 193,512 | | | 75,724 | | 156 | |
| Funds flow from operations 1 | | 34,774 | | | 17,172 | | 103 | | | 100,800 | | | 43,711 | | 131 | |
| Per share – basic 1 | $ | 0.15 | | $ | 0.13 | | 15 | | $ | 0.45 | | $ | 0.37 | | 22 | |
| Per share – diluted 1 | $ | 0.15 | | $ | 0.13 | | 15 | | $ | 0.45 | | $ | 0.37 | | 22 | |
| Net income (loss) | | (6,742 | ) | | (3,196 | ) | (111 | ) | | (1,399 | ) | | (19,398 | ) | 93 | |
| Per share – basic | $ | (0.03 | ) | $ | (0.02 | ) | (50 | ) | $ | (0.01 | ) | $ | (0.17 | ) | 94 | |
| Per share – diluted | $ | (0.03 | ) | $ | (0.02 | ) | (50 | ) | $ | (0.01 | ) | $ | (0.17 | ) | 94 | |
| Net debt 1 | | (194,917 | ) | | (62,817 | ) | (210 | ) | | (194,917 | ) | | (62,817 | ) | (210 | ) |
| Capital Expenditures 2 | | 74,063 | | | 14,497 | | 411 | | | 156,786 | | | 41,956 | | 274 | |
| Weighted average shares outstanding(thousands) | | | | | | |
| Basic | | 227,691 | | | 134,382 | | 69 | | | 224,376 | | | 117,263 | | 91 | |
| Diluted | | 227,691 | | | 134,382 | | 69 | | | 224,376 | | | 117,263 | | 91 | |
| Share Trading (thousands, except share price) | | | | | | |
| High | $ | 2.88 | | $ | 3.74 | | (23 | ) | $ | 3.59 | | $ | 4.28 | | (16 | ) |
| Low | $ | 1.98 | | $ | 3.15 | | (37 | ) | $ | 1.96 | | $ | 2.16 | | (9 | ) |
| Trading volume | | 25,281 | | | 21,529 | | 17 | | | 161,588 | | | 82,732 | | 95 | |
| Average daily production | | | | | | |
| Light oil (bbls/d) | | 10,108 | | | 4,534 | | 123 | | | 9,168 | | | 3,999 | | 129 | |
| Heavy oil (bbls/d) | | 603 | | | 343 | | 76 | | | 514 | | | 379 | | 36 | |
| NGLs (bbls/d) | | 1,499 | | | 1,078 | | 39 | | | 1,576 | | | 1,021 | | 54 | |
| Natural gas (mcf/d) | | 49,987 | | | 29,007 | | 72 | | | 47,860 | | | 27,435 | | 74 | |
| Total (boe/d) | | 20,541 | | | 10,790 | | 90 | | | 19,235 | | | 9,972 | | 93 | |
| Average sale prices | | | | | | |
| Light oil ($/bbl) | | 53.43 | | | 51.83 | | 3 | | | 56.89 | | | 47.19 | | 21 | |
| Heavy oil ($/bbl) | | 46.26 | | | 39.29 | | 18 | | | 45.03 | | | 32.89 | | 37 | |
| NGLs ($/bbl) | | 30.76 | | | 19.68 | | 56 | | | 28.74 | | | 17.83 | | 61 | |
| Natural gas ($/mcf) | | 1.62 | | | 2.54 | | (36 | ) | | 2.48 | | | 2.08 | | 19 | |
| Total ($/boe) | | 33.83 | | | 31.82 | | 6 | | | 36.85 | | | 27.72 | | 33 | |
| Operating netback ($/Boe) 1 | | | | | | |
| Average realized sales | | 33.83 | | | 31.82 | | 6 | | | 36.85 | | | 27.72 | | 33 | |
| Royalty expenses | | (3.73 | ) | | (2.24 | ) | 67 | | | (3.94 | ) | | (1.85 | ) | 113 | |
| Production expenses | | (11.26 | ) | | (11.58 | ) | (3 | ) | | (11.51 | ) | | (11.43 | ) | 1 | |
| Operating field netback ($/Boe) 1 | | 18.84 | | | 18.00 | | 5 | | | 21.40 | | | 14.44 | | 48 | |
| Realized commodity hedging gain (loss) | | 2.11 | | | 2.10 | | 0 | | | 0.46 | | | 4.56 | | (90 | ) |
| Operating netback | | 20.95 | | | 20.10 | | 4 | | | 21.86 | | | 19.00 | | 15 | |
| Funds flow from operations netback ($/Boe) 1 | | 18.39 | | | 17.29 | | 6 | | | 19.19 | | | 16.00 | | 20 | |
Notes:
(1) Net debt, operating netback, operating field netback, funds flow from operations and funds flow from operations netback do not have any standardized meaning prescribed by International Financial Reporting Standards (“IFRS”) and therefore may not be comparable with the calculation of similar measures for other entities. See “Non-IFRS Measures”.
(2) Capital expenditures include exploration and development expenditures, but exclude asset acquisitions and dispositions.
Operations Update
Tamarack continued to realize operational efficiencies and strong momentum through the third quarter of 2017, driving meaningful growth from the assets acquired in the transaction with Spur Resources Ltd., while continuing to advance the strategy of adding debt adjusted production per share growth. The Company posted record Q3 production volumes that averaged 20,541 boe/d (59% liquids), an increase of 6% quarter-over-quarter and 90% year-over-year, offset by expected declines from legacy Tamarack assets and 408 boe/d related to the Coleville Plant shut-in. While the Coleville Plant commenced partial operations in mid-July, the Company continues to have approximately 1.0 MMcf/d of natural gas and 15 bbls/d of NGLs curtailed. Tamarack’s oil weighting continued to increase in Q3/17, rising to 52% compared to 42% in Q3/16 and 51% in the previous quarter.
Volume additions in Q3/17 reflect production related to the Q3/17 drilling program which contributed an incremental 674 boe/d from Wilson Creek as a result of a Mannville gas well which came on-stream during the quarter (31% oil and NGLs) and 1,514 boe/d from the Viking development program (87% oil and natural gas liquids). However, all of the Viking wells that Tamarack drilled and brought on production in Q3/17 were facility or pipeline constrained and producing at restricted rates due to better-than-expected oil rates from the Viking wells.
Tamarack continued to lower per boe costs by reducing production expenses by 5% to $11.26/boe and G&A costs by 7% to $1.62/boe in Q3/17 over Q2/17. Production expenses were positively impacted by the partial restart of the Coleville Plant which lowered production costs by significantly reducing the redirection of production to third party facilities that have higher associated fees. In addition, completion of the Veteran oil battery expansion and installation of water handling facilities that were completed in the latter half of the third quarter reduced water trucking and disposal costs. In the fourth quarter, the Company expects a further reduction in operating costs, as the full quarter impact of the battery expansion and water handling facilities at Veteran is realized.
With steady access to service providers, particularly pressure pumpers, and dry conditions that prevailed through most of the summer, Tamarack was able to successfully execute the majority of its planned second half capital program during the third quarter of 2017. The Company spent a total of $74.1 million in the period, close to its second half 2017 guidance range of $80 to $90 million, which is a significant increase over its second quarter program of $19.0 million that reflected spring break-up conditions. During the third quarter of 2017, the Company drilled 50 (48.6 net) Viking oil wells, eight (8.0 net) Cardium oil wells, one (0.8 net) Ellerslie oil well, one (1.0 net) Mannville gas well and two (2.0 net) heavy oil wells. Several wells from the third quarter drilling program were completed and brought on production subsequent to quarter end, including 14 (14.0 net) Viking oil wells, three (3.0 net) Cardium oil wells and two (2.0 net) heavy oil wells. In addition, the Company spudded one (1.0 net) Baron Sands horizontal oil well in Penny, which is expected to come on stream in November, 2017.
To accommodate its Q1/18 drilling program, which includes plans to drill 20-28 net oil wells at Veteran, Tamarack decided to accelerate work on its second Veteran oil battery expansion project into 2017 which will result in 25,000 bbls/d of emulsion capacity and water handling. The Company anticipates investing $2-3 million in Q4/17 and $5-6 million in Q1/18 for this expansion which, when complete, will accommodate the current, higher oil rate production at Veteran as well as forecast additions from the 2018 drilling program.
Tamarack further enhanced its land base during the third quarter, completing four separate acquisitions which added 10 boe/d and 145 net sections of land in several of the Company’s core areas for aggregate consideration of $3.4 million. The Company added nine sections of land in Wilson Creek, two sections in Consort and 134 sections in Southern Alberta. Subsequent to the end of the quarter, the Company closed a $5.5 million Viking acquisition which added an incremental 42 boe/d, 9.75 net sections of land, and 54 additional high-quality, quick payout locations to the drilling inventory, with the potential to double pending further delineation.
Capital has been advanced into the Company’s fourth quarter 2017 program to position Tamarack for a strong start to 2018, continue capitalizing on the operational momentum realized during the third quarter, and avoid any potential challenges accessing services in the first quarter of 2018. The Company will accelerate $10-15 million of first quarter 2018 capital into December, 2017, and expects wells drilled to come on production in early 2018. As a result of both the acceleration and recent successful tuck-in acquisitions, Tamarack’s full year 2017 capital budget has been increased to $195-198 million, including the infrastructure investment at Veteran as well as the additional drilling capital in Q4/17. The Company forecasts that capital spending over the next two quarters (Q4/17 and Q1/18) will approximate funds flow from operations generated through that period, based on current strip prices. With this acceleration, Tamarack plans to drill 13 wells in Veteran and one Cardium well in Wilson Creek, in addition to one well in Penny and three wells in Redwater which were originally planned for the fourth quarter of 2017. Consistent with its corporate strategy, all of the Company’s capital allocation decisions in 2017 and 2018 are being directed to locations that pay out in 1.5 years or less at current strip prices.
Outlook
While recent strengthening of crude oil prices supports the underlying business, Tamarack’s priority is to maintain financial flexibility which will enable the Company to capitalize on attractive opportunities for asset base enhancement while continuing to generate organic per share growth. With strong drilling results achieved thus far in 2017, the Company believes its robust drilling inventory supports a multi-year, debt-adjusted per share growth strategy and positions Tamarack for further success. In assessing the success of its 2017 capital program, Tamarack has performed an initial internal estimate of its 2017 year end reserves, which on a proved plus probable basis, are anticipated to range between 87 to 92 million boe, an increase of 52% to 65% compared to the 56.5 million boe recorded at December 31, 2016.
Tamarack’s accelerated capital program coupled with the Company’s active and successful operations during the third quarter contributed to an increase in net debt at the end of the period. As such, Tamarack’s quarter annualized funds flow ratio was 1.4 times at September 30, 2017 compared to 1.1 times at June 30, 2017. However, this is expected to return to approximately 1.0 times by the end of 2017 based on current strip prices, as well as the incremental, higher oil-weighted production additions and continued focus on controlling costs. The Company has commenced its mid-year lending review and management expects a bank line increase to $290 million from $265 million by December 31, 2017.
By closely monitoring the forward curve, the Company has been able to opportunistically layer in additional downside risk mitigation to support its strong balance sheet, resulting in approximately 23% of forecast Q4/17 oil production hedged at $71.62/bbl Canadian and approximately 60% of natural gas hedged at $2.91/GJ AECO. Tamarack also has approximately 25% of its first half oil production hedged at between US$52.60 to 53.40/bbl WTI on average, and approximately 60% of its first quarter 2018 natural gas production hedged at $3.16/GJ AECO.
In addition to hedging for downside protection, Tamarack has also taken steps to increase the diversification of its natural gas sales exposure. As gas takeaway capacity is limited and oversupply in Alberta continues, the summer volatility experienced in the AECO daily index is expected to persist through 2018 and beyond. Subsequent to the end of the quarter, Tamarack entered into a gas sales contract with a third party to diversify its natural gas price exposure. Commencing November 1, 2017, approximately 20% of Tamarack’s natural gas production will receive pricing from various sales hubs that have historically outperformed AECO pricing, including Malin, Chicago, Michigan Consolidated and Dawn daily index pricing less transportation tolls. Tamarack continues to explore opportunities to minimize its exposure to Alberta gas market price fluctuations. Hedging and sales diversification provide important downside protection as the Company seeks to deliver strong debt-adjusted returns amidst an uncertain commodity price environment.
Tamarack exited the month of October with production of approximately 22,000 boe/d based on field estimates, thereby realizing its 2017 exit rate guidance rate earlier than anticipated. With this production level and the Company’s continued drilling activity through the fourth quarter, Tamarack anticipates full year 2017 production will average near the upper end of its annual guidance range of 19,000 to 20,000 boe/d. The Company’s strong balance sheet entering 2018, supported by a robust hedging position and natural gas sales diversification, is expected to enable Tamarack to continue to achieve per share growth. While its full 2018 capital budget is expected to be released near the end of January 2018, Tamarack’s initial forecasts anticipate an active Q1/18 drilling program with spending of $65-75 million in the quarter. This includes the drilling of 20-28 Viking wells in Veteran and 5-8 wells in Milton; 4-6 Cardium wells and 3-6 oil wells at Redwater. Based on a 2017 exit rate of 22,000 boe/d, Tamarack’s absolute production per share growth is forecast to exceed 15% while its debt-adjusted production per share growth is estimated at 8-9% over Q4/16.
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.
Abbreviations
| bbls | barrels |
| bbls/d | barrels per day |
| boe | barrels of oil equivalent |
| boe/d | barrels of oil equivalent per day |
| mcf | thousand cubic feet |
| MMcf | million cubic feet |
| mcf/d | thousand cubic feet per day |
| MMcf/d | million cubic feet per day |
| NGLs | natural gas liquids |
| GJ | gigajoule |
| WTI | West Texas Intermediate |
| AECO | Alberta Energy Company |
Disclosure of Oil and Gas Information
The reserves estimate in this press release has been prepared by an internal qualified reserves evaluator as defined in National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) in accordance with the Canadian Oil and Gas Evaluation Handbook and has an effective date of October 10, 2017.
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 to NI 51101. Boe may be misleading, particularly if used in isolation.
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 “anticipate”, “target”, “plan”, “take steps”, “continue”, “intend”, “consider”, “design”, “estimate”, “expect”, “may”, “will”, “should”, “could”, “believe” 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 capital and operating efficiencies and netbacks; an increase to the Company’s bank line; the ability of the Company to achieve drilling success consistent with management’s expectations; drilling plans including the timing of drilling; the timeframe for resumption of full-scale operations at the Coleville Plant; tuck-in land acquisitions in Tamarack’s core areas; expected levels of operating costs, G&A costs, costs of services and other costs and expenses; cost cutting initiatives; the payout of wells and the timing thereof; oil and natural gas production levels; strategies to minimize exposure to Alberta gas market fluctuations, acceleration of the 2017 capital expenditure program and expected production in the remainder of 2017; the 2018 drilling program and capital budget; and shareholder returns.
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 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 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 Tamarack’s Annual Information Form (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.
Non-IFRS Measures
Certain financial measures referred to in this press release, such as net debt, operating netback, operating field netback, funds flow from operations and funds flow from operations netback are not prescribed by IFRS. The Company uses these measures to help evaluate its performance. 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. The Company uses net debt as an alternative measure of outstanding debt. Net debt includes accounts receivable, prepaid expenses and deposits, bank debt and accounts payable and accrued liabilities, but excludes the fair value of financial instruments. 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. The Company calculates funds flow from operations as cash flow from operating activities, as determined under IFRS, before the changes in non-cash working capital related to operating activities and abandonment expenditures and before transaction costs related to acquisitions or dispositions that are not part of regular ongoing operations. Funds flow from operations netback equals funds flow from operations divided by the total sales volume and reported on a per boe basis. Tamarack considers operating netback and funds flow from operations netback as important measures to evaluate its operational performance as they demonstrate the Company’s field level profitability relative to current commodity prices. 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:
Brian Schmidt
President & CEO
Tamarack Valley Energy Ltd.
Phone: 403.263.4440
www.tamarackvalley.ca
Ron Hozjan
VP Finance & CFO
Tamarack Valley Energy Ltd.
Phone: 403.263.4440
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