Tamarack Valley Energy Ltd. Announces 78% Increase to Reserves and Record Fourth Quarter Production

CALGARY, ALBERTA–(Marketwired – March 12, 2015) – Tamarack Valley Energy Ltd. (TSX VENTURE:TVE) (“Tamarack” or the “Company“) is pleased to announce the results of its independent reserves evaluation as of December 31, 2014, which includes a 78% increase in proved plus probable (“2P”) reserves to 33.236 mmboe, a three year proved plus probable finding, development and acquisition cost average of $25.74/boe and a recycle ratio of 1.5 using 2014 netbacks of $38.92/boe. The Company is also pleased to announce record average production of 7,681 boe/d for the fourth quarter of 2014, which was an increase of 33% from the previous quarter and 77% higher than the same period in 2013.

As previously disclosed, Tamarack is on target to average approximately 8,000 boe/d in the first quarter of 2015 while limiting capital expenditures to less than funds from operations. The Company has prudently elected to preserve capital during the first half of 2015 to reduce debt and maintain financial flexibility. Tamarack is on target to reduce net debt to less than $118 million by the end of the second quarter of 2015. The Company estimates it has approximately 1,205 boe/d behind pipe in the Wilson Creek / Alder Flats area that will remain shut-in until there is some improvement in commodity prices or service costs.

Subsequent to year-end, the Company disposed of a 49 boe/d producing asset for $2.3 million, before adjustments and continued to add hedges to protect future funds from operations through an active risk management program. Tamarack currently has 1,000 bbls/d of crude oil hedged in 2015 at an average Canadian dollar fixed price of $90.26/bbl. The Company will continue to opportunistically enter into fixed price contracts to protect its future funds from operations and continue to preserve financial flexibility.


Reserve Report

  • Increased 2P reserves by 78% to 33.236 million boe, weighted 59% to oil and natural gas liquids (“NGLs”) and proved (“1P”) reserves by 71% to 17.135 million boe weighted 58% to oil and NGLs.
  • 1P reserves included only 90 (71 net) proved undeveloped drilling locations and 2P reserves included 204 (162.1 net) proved plus probable undeveloped drilling locations. The Company currently has identified over 375 additional low risk development locations, offering a sizeable inventory that can be developed as commodity prices and project economics warrant.
  • Including acquisitions, the Company replaced 799% of production on a 2P basis and 444% on a 1P basis, calculated by dividing total reserves additions by total 2014 production of 2.087 mmboe (5,717 boe/d average).
  • Excluding acquisitions, organic 2P reserves additions replaced 331% of production, and 190% on a 1P basis.
  • Increased 2P reserves by 5.3% and proved reserves by 1.6% on a fully diluted per share basis.
  • Achieved three year average 2P finding and development (“F&D”) costs of $25.58/boe and 2P finding, development and acquisition (“FD&A”) costs of $25.74/boe (including the change in future development capital or “FDC”).
  • Achieved 2P F&D costs of $27.25/boe for the year ended December 31, 2014 including the change in FDC. The Company also achieved 2P FD&A costs of $27.50/boe during the same period, including the change in FDC.
  • Achieved a recycle ratio of 1.5 with the three average FD&A costs of $25.74/boe, including the change in FDC, using field operating netback of $38.92/boe for the year ended December 31, 2014.
  • Tamarack’s 2P reserve value is estimated at $4.66/share based on the net present value at a 10% discount before taxes (“NPV10BT”) as at December 31, 2014, divided by issued and outstanding shares at the same date. On a 1P basis, the NPV10BT value is estimated at $2.57/share.
  • Maintained a proved plus probable reserve life index of 11.9 years based on the fourth quarter 2014 average production of 7,681 boe/d.

Financial and Operating

  • Achieved record fourth quarter average production of 7,681 boe/d, up 33% from the previous quarter.
  • Production increased by 75% to average 5,717 boe/d in 2014 from 3,276 boe/d in 2013.
  • Funds from operations increased to $19.1 million for Q4/14 and $66.2 million for the year ended 2014, an increase of 81% and 82%, respectively, compared to $10.5 million and $36.6 for the same periods in 2013.
  • Achieved 2014 operating netbacks of $45.15/boe in Wilson Creek (Cardium oil), $58.64/boe in Redwater (Viking oil) and $21.39/boe in Hatton (heavy oil) where the Company focused the majority its capital expenditures in 2014. Tamarack spent approximately 74% of the 2014 capital expenditures, excluding the Wilson Creek acquisition, on these assets.
  • Disposed of $26.5 million of assets in 2014, including monetizing certain oil and gas infrastructure during Q4/14.


Tamarack had tremendous reserve and production growth in 2014, increasing 2P reserves by 78% to 33.236 million boe while maintaining a relatively conservatively booked reserve report with only 90 (71 net) proved undeveloped drilling locations. This growth was achieved primarily through Cardium oil and Viking oil development drilling, execution of the 3-year farm-in commitment with an industry major and by the strategic acquisition of assets in the Wilson Creek area of Alberta which closed on September 30, 2014.

During 2014, the Company drilled 36 (28.6 net) horizontal Cardium oil wells, 16 (14.4 net) horizontal Viking oil wells and 8 (8 net) heavy oil wells. Most of the 2014 Cardium drilling program focused in the Wilson Creek / Alder Flats areas of Alberta, where the Company drilled 27 (22.4 net) wells. These wells will benefit from the 3,800 bbl/d operated oil battery and 52% owned and operated 30 mmcf/d Wilson Creek gas plant. By mid-January 2015, Tamarack had approximately 1,205 boe/d of production behind pipe in the Wilson Creek / Alder Flats area. As previously disclosed, this production will be brought on-stream when economic conditions improve.

In addition, Tamarack spent $7.0 million on facility expenditures building out infrastructure in the Hatton area of Saskatchewan, where it constructed a heavy oil battery and water handling facilities and in Alder Flats where it began construction of a compressor station and gathering system. The facilities in Hatton reduced operating costs by $6/bbl in the fourth quarter and Tamarack expects to reduce costs by a further $3/bbl in Q1/15 with the facilities in operation for a full quarter. The Alder Flats infrastructure will bring production to existing Tamarack operated and controlled facilities.

The following tables highlight the 2014 year-end reserves based on the GLJ Petroleum Consultants Ltd. independent evaluation of the Company’s reserves dated effective December 31, 2014. The evaluation was conducted pursuant to National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) and the Canadian Oil and Gas Evaluation Handbook (“COGE Handbook”) reserves definitions.

Reserves Data (Forecast Prices and Costs)

Developed Producing 4,683 4,180 30,322 26,681 1,110 804 10,846 9,431
Developed Non-Producing 191 175 3,175 2,539 80 52 800 650
Undeveloped 3,628 3,244 9,488 8,558 279 223 5,489 4,894
TOTAL PROVED 8,502 7,599 42,985 37,778 1,468 1,079 17,135 14,974
PROBABLE 8,076 7,018 39,591 35,221 1,427 1,057 16,102 13,945
TOTAL PROVED PLUS PROBABLE 16,579 14,617 82,576 72,999 2,895 2,136 33,236 28,920
(1) Columns may not add due to rounding.

Net Present Values of Future Net Revenue Before Income Taxes Discounted at (%/yr)

Unit Value Before Income Tax Discounted at 10% Per Year(1)
Developed Producing 220,557 184,042 157,350 137,865 123,246 16.68
Developed Non-Producing 20,671 13,712 10,298 8,357 7,120 15.85
Undeveloped 99,483 57,666 32,313 16,214 5,617 6.60
TOTAL PROVED 340,711 255,420 199,961 162,437 135,983 13.35
PROBABLE 452,535 260,446 163,191 108,425 74,899 11.70
TOTAL PROVED PLUS PROBABLE 793,246 515,866 363,151 270,862 210,883 12.56
(1) Unit values based on Company net reserves
(2) Columns may not add due to rounding.

Reconciliation of Company Gross Reserves Based on Forecast Prices and Costs

FACTORS Proved Probable Proved +
December 31, 2013 9,992 8,693 18,684
Discoveries 0 0 0
Extensions and Improved Recovery 4,052 3,695 7,747
Technical Revisions 437 (620 ) (184 )
Acquisitions(1) 5,554 4,778 10,332
Dispositions (254 ) (307 ) (561 )
Economic Factors (560 ) (136 ) (696 )
Production (2,087 ) 0 (2,087 )
December 31, 2014 17,135 16,102 33,236
(1) Includes reserve additions from earning wells that were drilled on the Company’s Cardium farm-in

Future Development Capital Costs

The following is a summary of GLJ’s estimated future development capital required to bring proved and probable undeveloped reserves on production.

(amounts in $000s) Total Proved Total Proved + Probable
2015 19,781 41,162
2016 60,672 102,636
2017 52,918 122,653
2018 and Subsequent 24,211 100,425
Total Undiscounted FDC 157,582 366,876
Total Discounted FDC at 10% per year 129,936 294,842
FD&A Costs
2014 Three Year Average
(amounts in $000s except as noted) Proved Proved +
Proved Proved +
FD&A costs, including FDC
Exploration and development capital expenditures (2) 144,736 144,736 70,069 70,069
Acquisitions, net of dispositions 150,274 150,274 99,606 99,606
Total change in FDC 65,800 163,641 43,210 102,627
Total FD&A capital, including change in FDC 360,810 458,651 212,885 272,302
Reserve additions, including revisions – Mboe 3,956 6,908 2,425 3,708
Acquisitions, net of dispositions – Mboe 5,300 9,771 3,745 6,872
Total FD&A Reserves 9,256 16,679 6,170 10,580
F&D costs, including FDC – $/boe 37.66 27.25 33.70 25.58
Acquisition costs, net of dispositions – $/boe 39.96 27.68 35.06 25.82
FD&A costs, including FDC – $/boe 38.98 27.50 34.53 25.74
(1) While Nl 51-101 requires that the effects of acquisitions and dispositions be excluded from the calculation of finding and development costs, FD&A costs have been presented because acquisitions and dispositions can have a significant impact on the Company’s ongoing reserve replacement costs and excluding these amounts could result in an inaccurate portrayal of the Company’s cost structure. Finding and development costs both including and excluding acquisitions and dispositions have been presented above.
(2) The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.
(3) The capital expenditures also exclude capitalized administration costs.


During the fourth quarter of 2014, Tamarack recorded record production of 7,681 boe/d, which was 33% higher than the third quarter average of 5,765 boe/d. The record production rate resulted in a record quarter of funds from operations of $19.2 million despite a 30% decrease in realized oil and natural gas liquids prices during the quarter. For the year ended December 31, 2014 funds from operations was $66.2 million which was an 81% increase from 2013.

Financial & Operating Results

Three months ended December 31 Years ended December 31
2014 2013 % change 2014 2013 % change
($, except share numbers)
Total Revenue 33,838,539 22,224,185 52 125,992,315 70,059,021 80
Funds from operations 1 19,127,813 10,505,372 82 66,171,480 36,594,096 81
Per share – basic 1 $ 0.25 $ 0.24 4 $ 1.05 $ 1.09 (4 )
Per share – diluted 1 $ 0.25 $ 0.23 9 $ 1.05 $ 1.09 (4 )
Net income (loss) (38,991,202 ) 10,854,769 (459 ) (25,167,361 ) 14,813,126 (270 )
Per share – basic $ (0.50 ) $ 0.24 (308 ) $ (0.40 ) $ 0.44 (191 )
Per share – diluted $ (0.50 ) $ 0.24 (308 ) $ (0.40 ) $ 0.44 (191 )
Net debt 2 (129,798,673 ) (81,764,155 ) 59 (129,798,673 ) (81,764,155 ) 59
Capital Expenditures 3 26,774,395 22,009,901 22 288,903,460 57,541,055 402
Weighted average shares outstanding
Basic 77,914,336 44,558,308 75 63,124,738 33,450,158 89
Diluted 77,914,336 45,109,305 73 63,124,738 33,568,017 88
Share Trading
High $ 6.82 $ 3.97 72 $ 7.85 $ 3.97 98
Low $ 2.57 $ 2.80 (8 ) $ 2.57 $ 1.74 48
Trading volume 41,998,435 27,734,011 51 148,788,382 40,778,592 265
Average daily production
Crude oil and NGLs (bbls/d) 4,348 2,495 74 3,245 1,852 75
Heavy oil (bbls/d) 413 116 256 257 59 336
Natural gas (mcf/d) 17,518 10,349 69 13,292 8,191 62
Total (boe/d) 7,681 4,336 77 5,717 3,276 75
Average sale prices
Crude oil and NGLs ($/bbl) 62.87 77.78 (19 ) 82.34 85.80 (4 )
Natural gas ($/mcf) 3.91 3.72 5 4.28 3.42 25
Total ($/boe) 47.89 55.72 (14 ) 60.38 58.59 3
Operating netbacks ($/boe) 4
Average realized sales 47.89 55.72 (14 ) 60.38 58.59 3
Royalty expenses (6.20 ) (4.30 ) 44 (7.78 ) (6.00 ) 30
Production expenses (12.59 ) (13.65 ) (8 ) (13.68 ) (13.14 ) 4
Operating field netback 29.10 37.77 (23 ) 38.92 39.45 (1 )
Realized commodity hedging gain (loss) 2.64 (2.15 ) 223 (1.06 ) (2.11 ) (50 )
Operating netback 31.74 35.62 (11 ) 37.86 37.34 1
Funds flow from operations netback ($/Boe) 1 27.07 26.34 3 42.40 40.91 4
(1) Funds from operations is calculated as cash flow from operating activities before the change in non-cash working capital and abandonment.
(2) Net debt does not have any standard meaning prescribed by 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.
(3) Capital expenditures include property acquisitions and are presented net of disposals, but exclude corporate acquisitions.
(4) 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 less 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.

Tamarack filed its Annual Information Form (“AIF”) today, which included information pursuant to the requirements of NI 51-101 of the Canadian Securities Administrators relating to reserves data and other oil and gas information on SEDAR. The AIF can be accessed either on Tamarack’s website at www.tamarackvalley.ca or on SEDAR at www.sedar.com.

The Company has also filed its audited consolidated financial statements for the year ended December 31, 2014 (“Financial Statements”) and management’s discussion and analysis (“MD&A”) on SEDAR. Selected financial and operational information is outlined below and should be read in conjunction with the Financial Statements, which were prepared in accordance with International Financial Reporting Standards (“IFRS”), and the related MD&A. These documents are also accessible on Tamarack’s website at www.tamarackvalley.ca or 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 increased identification, evaluation and operation of resource plays in the Western Canadian sedimentary basin. Tamarack’s strategic direction is focused on two key principles – targeting resource 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. 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.


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.

F&D cost calculations have been conducted in compliance with the requirements of NI 51-101. Specifically, F&D costs relating to Proved reserves were calculated by adding the cost of exploration, the cost of development and the annual change in estimated future reserves development costs and dividing that sum by annual additions to Proved reserves. Finding and development costs for Proved plus Probable reserves were similarly calculated, but used the Proved plus Probable reserves figure rather than the Proved reserves figure. The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year. Tamarack also calculates FD&A costs using the same method, but without eliminating the effects of acquisitions and dispositions. Operating netbacks are calculated in compliance with the requirements of NI 51-101 by subtracting royalties and operating costs from revenue.

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”, “believe”, “plan”, “potential”, “intend”, “objective”, “continuous”, “ongoing”, “encouraging”, “estimate”, “expect”, “may”, “will”, “project”, “should”, or similar words suggesting future outcomes. More particularly, this press release contains statements concerning Tamarack’s planned future drilling plans, operations and strategy, estimated average first quarter 2015 production rate and anticipated reductions in net debt in 2015. 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 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 is available for viewing under the Company’s profile onwww.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.

Neither TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this release.

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