CALGARY, ALBERTA–(Marketwired – March 23, 2017) – Tamarack Valley Energy Ltd. (TSX:TVE) (“Tamarack” or the “Company“) is pleased to announce its financial and operating results for the three and twelve months ended December 31, 2016, along with the appointment of Mr. Ian Currie to Tamarack’s Board of Directors.
2016 Financial and Operating Highlights
- Achieved record Q4/16 average production of 11,453 boe/d, up 6% from Q3/16 and up 15% over Q4/15, and grew annual average production by 22% to average 10,344 boe/d in 2016 compared to 8,448 boe/d in 2015.
- Total funds from operations increased 23% to $20.5 million in Q4/16 from $16.7 million in Q3/16, and increased 10% compared to Q4/15.
- Enhanced financial flexibility by reducing net debt by 47% at year end 2016 compared to year end 2015, and reduced by 17% compared to the previous quarter, resulting in year end 2016 net debt to Q4 2016 annualized funds from operations of 0.6x, down from 1.3x at year end 2015.
- Improved field efficiencies combined with a continued focus on cost reductions resulted in production expense declining 9% to $11.64/boe in 2016 compared to $12.81/boe in 2015.
- General and administrative (“G&A”) costs per boe decreased by 17% in 2016 over 2015, declining to $1.95/boe from $2.35/boe, despite higher activity levels, closing two strategic acquisitions and achieving 22% growth in production.
- As announced on February 27, 2017, delivered 5% growth per fully diluted share in proved developed producing reserves (“PDP”), and increased reserves on an absolute basis by 43% for PDP, 34% for total proved (“1P”) and 26% for proved plus probable (“2P”) reserves.
- Achieved attractive capital efficiencies through the 2016 development program, generating a 2P finding and development cost (“F&D”) recycle ratio of 2.3 times and a 2P finding, development and acquisition cost (“FD&A”) recycle ratio of 1.5 times based on the 2016 field netback (excluding hedges) of $16.55/boe. Using the Q4 2016 field netback of $22.03/boe, generated a 2P F&D recycle ratio of 3.1 times and a 2P FD&A recycle ratio of 1.9 times.
- Announced the transformative transaction with Spur Resources, Ltd. (the “Viking Acquisition”) on November 2, 2016, positioning Tamarack as a Cardium and Viking-focused growth entity with forecast 2017 annual production between 19,000-20,000 boe/d (approximately 55-60% liquids), as well as control of key infrastructure across its core areas. Concurrent with closing, the borrowing base on the Company’s credit facilities was increased by over 80% to $220 million from $120 million, providing ample liquidity for ongoing development of Tamarack’s high-netback, light oil-weighted asset base.
Financial & Operating Results
| Three months ended | Years ended | ||||||
| December 31, | December 31, | ||||||
| 2016 | 2015 | % change | 2016 | 2015 | % change | ||
| ($, except share numbers) | |||||||
| Total Revenue | 39,793,215 | 27,725,228 | 44 | 115,516,949 | 106,145,723 | 9 | |
| Funds from operations | 20,453,183 | 18,614,626 | 10 | 63,567,478 | 60,161,226 | 6 | |
| Per share – basic | $ 0.15 | $ 0.19 | (21) | $ 0.52 | $ 0.66 | (21) | |
| Per share – diluted | $ 0.15 | $ 0.19 | (21) | $ 0.52 | $ 0.66 | (21) | |
| Net income (loss) | (8,424,255) | 5,118,919 | (265) | (27,822,948) | (17,328,368) | (61) | |
| Per share – basic | $ (0.06) | $ 0.05 | (220) | $ (0.23) | $ (0.19) | (21) | |
| Per share – diluted | $ (0.06) | $ 0.05 | (220) | $ (0.23) | $ (0.19) | (21) | |
| Net debt 1 | (52,316,066) | (97,940,880) | (47) | (52,316,066) | (97,940,880) | (47) | |
| Capital Expenditures 2 | 12,416,830 | 10,817,509 | (46) | 140,777,100 | 107,431,198 | 46 | |
| Weighted average shares outstanding | |||||||
| Basic | 137,043,779 | 99,945,577 | 37 | 122,235,231 | 90,661,207 | 35 | |
| Diluted | 137,043,779 | 99,945,577 | 37 | 122,235,231 | 90,661,207 | 35 | |
| Share Trading | |||||||
| High | $ 3.89 | $ 3.25 | 20 | $ 4.28 | $ 4.80 | (11) | |
| Low | $ 3.00 | $ 2.22 | 35 | $ 2.16 | $ 1.83 | 18 | |
| Trading volume | 39,341,999 | 26,929,737 | 46 | 122,074,351 | 94,324,264 | 29 | |
| Average daily production | |||||||
| Light oil (bbls/d) | 4,858 | 4,258 | 14 | 4,215 | 3,703 | 14 | |
| Heavy oil (bbls/d) | 316 | 620 | (49) | 363 | 602 | (40) | |
| NGLs (bbls/d) | 1,075 | 1,218 | (12) | 1,035 | 803 | 29 | |
| Natural gas (mcf/d) | 31,226 | 23,229 | 34 | 28,388 | 20,038 | 42 | |
| Total (boe/d) | 11,453 | 9,968 | 15 | 10,344 | 8,448 | 22 | |
| Average sale prices | |||||||
| Light oil ($/bbl) | 58.71 | 47.16 | 24 | 50.53 | 52.06 | (3) | |
| Heavy oil ($/bbl) | 44.60 | 26.79 | 66 | 35.45 | 41.98 | (16) | |
| NGLs ($/bbl) | 28.99 | 18.22 | 59 | 20.74 | 19.49 | 6 | |
| Natural gas ($/mcf) | 3.27 | 2.66 | 23 | 2.41 | 2.85 | (15) | |
| Total ($/boe) | 37.76 | 30.23 | 25 | 30.51 | 34.43 | (11) | |
| Operating netback ($/Boe) 3 | |||||||
| Average realized sales | 37.76 | 30.23 | 25 | 30.51 | 34.43 | (11) | |
| Royalty expenses | (3.56) | (2.80) | 27 | (2.32) | (3.43) | (32) | |
| Production expenses | (12.17) | (12.20) | (0) | (11.64) | (12.81) | (9) | |
| Operating field netback ($/Boe) 3 | 22.03 | 15.23 | 45 | 16.55 | 18.19 | (9) | |
| Realized commodity hedging gain (loss) | (0.15) | 8.16 | (102) | 3.25 | 5.67 | (43) | |
| Operating netback | 21.88 | 23.39 | (6) | 19.80 | 23.86 | (17) | |
| Funds flow from operations netback ($/Boe) 3 | 19.41 | 20.30 | (4) | 16.79 | 19.51 | (14) | |
Notes:
| (1) | Net debt does not have any standard meaning prescribed by International Financial Reporting Standards (“IFRS”) and therefore may not be comparable with the calculation of similar measures for other entities. 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. |
| (2) | Capital expenditures include property acquisitions and are presented net of disposals, but exclude corporate acquisitions. |
| (3) | Operating netback, operating field netback and funds flow from operations netback does not have any standardized meaning prescribed by IFRS and therefore may not be comparable with the calculation of similar measures for other entities. 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. 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 it demonstrates its field level profitability relative to current commodity prices. |
2016 In Review
This past year was one of true transformation and unprecedented growth for Tamarack, demonstrating continued success in the execution of its strategy while navigating through another challenging year for commodity markets. The Company increased annual production volumes by 22% to 10,344 boe/d (54% liquids), compared to 8,448 boe/d in 2015 as a direct result of higher production volumes from its successful 2016 drilling program, capital efficiencies that exceeded expectations, and the impact of the strategic Penny and Redwater / Wilson Creek acquisitions that closed in July. Tamarack achieved record production of 11,453 boe/d during the fourth quarter of 2016, a 6% increase over the 10,790 boe/d produced in the third quarter of 2016, and higher than the Company’s target 2016 exit rate of 11,000 boe/d.
Year-end 2016 net debt totaled $52 million, a reduction of $46 million from year-end 2015, resulting in a net debt to fourth quarter 2016 annualized funds from operations ratio of 0.6 times, a significant improvement over the 1.5 times ratio at December 31, 2015. Tamarack’s debt reduction focus during the first half of 2016 positioned the Company to close two key acquisitions in July of 2016, which added approximately 1,900 boe/d of predominantly light oil and natural gas liquids production. The first was comprised of a producing, light oil pool at Penny (the “Penny Acquisition”) in southern Alberta, and the second was the consolidation of assets with significant key infrastructure at Redwater/Wilson Creek (the “Redwater / Wilson Creek Acquisition”). The assets acquired through these transactions outperformed during 2016, producing 25% more to date than originally forecast with decline rates much shallower than expected. In addition, after investing approximately $90 million in 2016 on these assets ($84 million for the acquisition and approximately $6 million for capital), the independent year end 2016 reserves evaluation reflected $110 million of PDP before-tax net present value of future net revenue (discounted at 10%) (“NPV10BT”) and $247 million of 2P NPV10BT value, increases of 1.2 and 2.7 times, respectively.
The Company’s strong balance sheet and previous experience with Viking oil in Alberta, set the stage for the Viking Acquisition which closed on January 11, 2017, and elevated Tamarack to the position of an intermediate producer and one of the largest land bases within the Saskatchewan / Alberta light oil Viking fairway. The Viking Acquisition, similar to each of the Company’s transactions completed to date, incorporates Tamarack’s strategy of adding high-quality, oil-weighted assets which, on a half cycle basis, can achieve a capital cost payout of 1.3 years or less while maintaining balance sheet flexibility. The Company’s inventory of identified, high-quality drilling locations that pay out in 1.5 years or less at current strip prices now totals over 800 net locations, fueling longer-term organic growth with forecast production and cash flow per share growth anticipated in 2017 and beyond. The actions and strategic decisions Tamarack made during 2016 have contributed to securing the Company’s long-term future sustainability and financial flexibility, while clearly demonstrating the strength of Tamarack’s unique returns-based growth model.
Operational Update
To date in the first quarter of 2017, Tamarack is pleased to confirm that it has drilled 35 (32.1 net) horizontal Viking light oil wells, 8 (7.3 net) extended reach horizontal Cardium light oil wells, 3 (3.0 net) heavy oil wells in Hatton and one net Notikewin liquids-rich natural gas well. This is the most active quarter in the Company’s history for drilling and capital activity, and Tamarack is pleased with the operational and safety performance the team has achieved thus far. Of these wells, a total of 27 (25.1 net) new wells are currently on production, which includes 22 (20.5 net) horizontal Viking light oil wells, 3 (2.6 net) extended reach horizontal Cardium light oil wells, one net heavy oil well in Hatton and one net Notikewin liquids-rich natural gas well. Production additions from each of these new wells are contributing to the Company’s current production of approximately 19,750 boe/d and Tamarack remains on target to meet its average first half production guidance range of 18,500 to 19,000 boe/d.
Tamarack anticipates completing its first half drilling program early in the second quarter, pending surface access, by fracture stimulating and equipping for production the remaining 20 (18.3 net) wells, bolstering the Company’s positive production momentum through the first half of 2017.
New Board Member Appointment
Tamarack is pleased to announce the appointment of Mr. Ian Currie to its Board of Directors. Mr. Currie is a professional engineer with over 30 years of oil and gas experience, and is currently the President and CEO of Spur Petroleum Ltd., a privately-held oil and gas exploration and production company. Previously he served as President and CEO of Spur Resources, Ltd. from 2006 until its acquisition by Tamarack in January, 2017. Prior thereto, he was Vice President, Operations at Profico Energy Management from its inception in 2000 until its acquisition in 2006, and held senior operational roles with Renaissance Energy Ltd. since 2002.
Tamarack also confirmed it has filed its Annual Information Form (“AIF”) today on SEDAR, which includes information pursuant to the requirements of National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) of the Canadian Securities Administrators relating to reserves data and other oil and gas information. In addition, the AIF contains a pro-forma summary of the Viking Acquisition reserves evaluation with an effective date of January 31, 2017, combined with a modified look-ahead summary performed by GLJ Petroleum Consultants, Ltd (“GLJ”) on Tamarack’s year end 2016 reserves effective January 31, 2017. The AIF can be accessed either on Tamarack’s website at www.tamarackvalley.ca or under the Company’s profile on SEDAR at www.sedar.com.
The Company has also filed its audited consolidated financial statements for the year ended December 31, 2016 (“Financial Statements”) and management’s discussion and analysis (“MD&A”) on SEDAR. Selected financial and operational information is outlined above and should be read in conjunction with the Financial Statements, which were prepared in accordance with IFRS, and the related MD&A. These documents are also accessible on Tamarack’s website at www.tamarackvalley.ca or under the Company’s profile on SEDAR at www.sedar.com.
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 development oil locations in the Pembina, Wilson Creek, Garrington and Lochend Cardium fairway and the Redwater shallow Viking play in Alberta. With a balanced portfolio and an experienced and committed management team, Tamarack intends to continue to deliver on its promise to maximize shareholder return 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 | thousands barrels of oil equivalent |
| mcf | thousand cubic feet |
| MMcf | million cubic feet |
| Mbbls | million barrels |
| mcf/d | thousand cubic feet per day |
Unit Cost Calculation
For the purpose of calculating unit costs, natural gas volumes have been converted to a barrel of oil equivalent (“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 Regulators’ NI 51-101. Boe’s may be misleading, particularly if used in isolation.
Drilling Locations
In this Press Release, the 800 net drilling locations identified include 283 proved locations, 507 proved and probable locations and 293 un-booked locations. Proved locations and probable locations account for drilling locations that have associated proved and/or probable reserves, as applicable. Un-booked locations are internal estimates based on prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Un-booked locations do not have attributed reserves or resources. While certain of the un-booked drilling locations have been de-risked by drilling existing wells in relative close proximity to such un-booked drilling locations, the majority of un-booked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and, if drilled, there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production.
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 “target”, “plan”, “continue”, “intend”, “ongoing”, “estimate”, “expect”, “may”, “should”, or similar words suggesting future outcomes. More particularly, this press release contains statements concerning forecast 2017 annual production range and liquid weighting percentage, first half 2017 production guidance and timing of completion of first half 2017 drilling program. 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 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.
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