Tamarack Valley Energy Ltd. Announces a 46% Increase in Proved Reserves With 356% Production Replacement

February 24, 2016 4:50 AM

CALGARY, ALBERTA–(Marketwired – Feb. 24, 2016) – Tamarack Valley Energy Ltd. (“Tamarack” or the “Company“) is pleased to announce the results of its independent oil and gas reserves evaluation as of December 31, 2015, prepared by GLJ Petroleum Consultants Ltd. (“GLJ”), summarized below.

Tamarack’s stringent capital allocation complemented by a constant focus on cost reductions and improving capital efficiencies has resulted in another significant year of reserve growth in 2015, despite challenges associated with lower commodity prices. During 2015, Tamarack adopted a three pronged strategy in the Wilson Creek and Alder Flats areas of Alberta: 1) re-design the drilling and completion programs to permanently reduce capital costs per well and improve capital efficiencies; 2) reduce operating expenses to improve netbacks which translates into enhanced economics on future drilling; and 3) add drilling inventory through tuck-in acquisitions to take advantage of existing infrastructure and maintain a low cost, high netback structure. Tamarack executed all three elements of this strategy in 2015 and successfully delivered per share reserves growth while reducing net debt. The Company’s significant reserves growth includes a 32% increase in proved developed producing reserves, a 46% increase in proved (“1P”) reserves and a 35% increase in proved plus probable (“2P”) reserves.

2015 RESERVES REPORT HIGHLIGHTS

Increased 1P reserves per fully diluted share by 13.3% and 2P reserves per fully diluted share by 5.1%.
Increased 1P reserves by 46% to 25.0 million boe, and 2P reserves by 35% to 45.0 million boe, weighted 52% and 54% to oil and natural gas liquids (“NGLs”), respectively.
Including acquisitions, the Company replaced 356% of production on a 1P basis and 481% on a 2P basis.
Maintained a conservative approach to reserves booking, with 1P reserves including only 65 (53.3 net) proved undeveloped horizontal Cardium drilling locations and 2P reserves including only 111 (90.0 net) proved plus probable undeveloped horizontal Cardium drilling locations.
Achieved 1P finding and development (“F&D”) costs of approximately $11.01/boe including the change in future development capital (“FDC”), a 71% reduction from the prior year. The Company also achieved 1P finding, development and acquisition (“FD&A”) costs of approximately $13.26/boe, including the change in FDC, representing a 66% reduction over 2014.
Realized three year average 2P F&D costs of approximately $17.44/boe and 2P FD&A costs of $19.26/boe including the change in FDC.
Generated a 1P F&D recycle ratio of 1.58 times and a 1P FD&A recycle ratio of 1.31 times using the estimated 2015 funds from operations netback of $17.35/boe (unaudited), which represents an increase of 52% and 31% over 2014, respectively, despite commodity prices averaging more than 40% lower in 2015.
Maintained a 2P reserve life index of 12.5 years based on estimated fourth quarter 2015 average production of 9,870 boe/d.

2015 YEAR-END RESERVES & OPERATIONS UPDATE

Tamarack realized tremendous reserves and production growth through 2015, and was able to maintain a conservatively booked reserves report, while reducing net debt. In 2015 the Company drilled 15 (13.9 net) horizontal Cardium oil wells in the core Wilson Creek and Alder Flats areas and on June 15, 2015 closed a strategic acquisition of assets within these areas, further contributing to Tamarack’s growth. The operational success realized in 2015 coupled with ongoing cost reduction initiatives ensure Tamarack is well positioned for continued measured growth and long-term sustainability.

The following tables highlight Tamarack’s 2015 year-end independent reserves assessment and evaluation prepared by GLJ with an effective date of December 31, 2015 (the “GLJ Report”). The GLJ Report has been prepared in accordance with definitions, standards and procedures contained in National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) and the Canadian Oil and Gas Evaluation Handbook. All evaluations and summaries of future net revenue are stated prior to provision for interest, debt service charges or general administrative expenses and after deduction of royalties, operating costs, estimated well abandonment and reclamation costs and estimated future capital expenditures. It should not be assumed that the estimates of future net revenues presented in the tables below represent the fair market value of the reserves.

Reserves Data (Forecast Prices and Costs)

RESERVES CATEGORY		CRUDE OIL ⁽¹⁾		CONVENTIONAL NATURAL GAS		NATURAL GAS LIQUIDS		TOTAL OIL EQUIVALENT
RESERVES CATEGORY		Gross (Mbbls)	Net (Mbbls)	Gross (Mmcf)	Net (Mmcf)	Gross (Mbbls)	Net (Mbbls)	Gross (Mboe)	Net (Mboe)
PROVED:
	Developed Producing	5,496	5,037	43,121	39,459	1,645	1,174	14,328	12,620
	Developed Non-Producing	41	37	3,391	2,726	74	47	680	538
	Undeveloped	4,885	4,423	24,968	23,127	938	767	9,985	9,045
TOTAL PROVED		10,422	9,497	71,480	64,312	2,657	1,988	24,992	22,203
PROBABLE		9,168	8,048	52,590	47,342	2,028	1,495	19,960	17,433
TOTAL PROVED PLUS PROBABLE		19,589	17,545	124,069	111,655	4,685	3,483	44,953	39,637

Note:
	(1)	Heavy oil included in the Crude Oil product type represents less than 8% of any reserves category and as such is immaterial.
	(2)	Columns may not add due to rounding.

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

RESERVES CATEGORY		0% ($000s)	5% ($000s)	10% ($000s)	15% ($000s)	20% ($000s)	Unit Value Before Income Tax Discounted at 10% Per Year⁽¹⁾($/Boe)
PROVED:
	Developed Producing	212,690	182,858	158,541	139,623	124,886	12.56
	Developed Non-Producing	8,426	4,424	2,729	1,875	1,379	5.07
	Undeveloped	146,544	94,662	60,381	37,761	22,540	6.68
TOTAL PROVED		367,660	281,944	221,651	179,259	148,805	9.98
PROBABLE		493,485	297,344	193,592	134,389	97,961	11.10
TOTAL PROVED PLUS PROBABLE		861,145	579,289	415,243	313,648	246,766	10.48

Note:
	(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

		MBOE
FACTORS		Proved	Probable	Proved + Probable
December 31, 2014		17,135	16,101	33,236
	Discoveries	0	0	0
	Extensions and Improved Recovery	3,873	(525)	3,348
	Technical Revisions	1,483	305	1,788
	Acquisitions⁽¹⁾	6,184	4,551	10,735
	Dispositions	(5)	(5)	(10)
	Economic Factors	(605)	(467)	(1,072)
	Production	(3,074)	0	(3,074)
December 31, 2015		24,992	19,960	44,953

Note:
	(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
2016	18,903	32,319
2017	65,160	84,869
2018	55,113	95,618
2019 and Subsequent	55,916	153,069
Total Undiscounted FDC	195,091	365,874
Total Discounted FDC at 10% per year	156,450	284,604

FD&A Costs	2015		Three Year Average
(amounts in $000s except as noted)	Proved	Proved + Probable	Proved	Proved + Probable
FD&A costs, including FDC
Exploration and development capital expenditures ⁽²⁾	60,344	60,344	80,700	80,700
Acquisitions, net of dispositions	47,086	47,086	92,724	92,724
Total change in FDC	37,509	(1,002)	42,860	84,361
Total FD&A capital, including change in FDC	144,940	106,428	216,285	257,786
Reserve additions, including revisions – Mboe	4,414	3,436	3,211	3,945
Acquisitions, net of dispositions – Mboe	6,516	11,349	5,046	9,441
Total FD&A Reserves	10,930	14,786	8,257	13,386
F&D costs, including FDC – $/boe	11.01	(6.33)	24.86	17.44
Acquisition costs, net of dispositions – $/boe	14.79	11.29	27.04	20.02
FD&A costs, including FDC – $/boe	13.26	7.20	26.19	19.26

Notes:
	(1)	While NI 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.

2016 CAPITAL PROGRAM AND GUIDANCE UPDATE

Tamarack’s 2016 capital program and associated guidance was designed with the top priority of protecting its top tier balance sheet. The capital program and guidance released on January 19, 2016, was based on a 2016 WTI average of $40.00/bbl USD and an AECO average of $2.45/GJ with a plan to adjust capital spending as commodity prices changed. Despite having high quality drilling inventory that achieves 1.5 year payout or less at current strip prices, the Company has begun to adjust capital spending as a result of the recent drop in prices. The Company’s top priority is to maintain a strong balance sheet in order to continue its success of pursuing tuck-in acquisitions within its core areas and continuing to add drilling inventory. This includes deferring approximately $6 to $8 million of capital into the second half of 2016. Tamarack will continue to closely monitor the broader commodity price environment and has the flexibility to further reduce capital expenditures by an additional $12 to $17 million from original levels, if commodity prices do not improve from current levels.

Updated 2016 Guidance Ranges:

Capital expenditures of $40-57 million (original guidance of $52 – 57 million).
Average production of 8,700-9,700 boe/d (approximately 51-57% oil & NGLs) (original guidance of 9,500-9,700 boe/d).
Exit production of 8,600-9,800 boe/d (approximately 50-55% oil & NGLs) (original guidance of 9,600-9,800 boe/d).
Estimated 2016 year end 12-month trailing debt to cash flow (including hedges) ratio between 1.6 and 2.3 times (original guidance of 1.6 times).
At least $50 million of liquidity maintained on bank lines (unchanged).

Updated 2016 Assumptions:

WTI average $33.00/bbl to 40.00/bbl USD.
Edmonton par price average $41.00/bbl to 51.45/bbl.
AECO average $2.00/GJ to 2.45/GJ.
Canadian/US dollar exchange rate range of $0.70 to $0.72.

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 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 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	thousand barrels
mcf/d	thousand cubic feet per day

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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 may be misleading, particularly if used in isolation.

Information Regarding Disclosure on Oil and Gas Reserves

This press release contains metrics commonly used in the oil and natural gas industry, such as “finding and development costs”, “finding, development and acquisition costs”, “funds from operations netbacks”, “reserves replacement”, and “reserve life index”. These terms do not have standardized meanings or standardized methods of calculation and therefore may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons. Such metrics have been included herein to provide readers with additional information to evaluate the Company’s performance, however such metrics should not be unduly relied upon.

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 estimated 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. Funds flow from operations netback are calculated in compliance with the requirements of NI 51-101 by subtracting royalties, operating costs, general and administrative costs, realized gains or losses on financial instruments and interest from revenue.

Recycle ratio is defined as operating netback per boe divided by F&D costs on a per boe basis. Reserves replacement ratio is calculated as total reserve additions (including acquisitions net of dispositions) divided by annual production. Reserve life index is calculated as Company gross reserves divided by average fourth quarter production annualized.

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 “plan”, “intend”, “ongoing”, “future”, “guidance”, “position”, “focus”, “monitor”, “target”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “should”, “could” or similar words suggesting future outcomes. More particularly, this press release contains statements concerning Tamarack’s planned future drilling plans, operations and strategy, projections contained in Tamarack’s 2016 capital program and guidance, anticipated reductions to capital expenditures in the event of continued low commodity prices, forecast commodity prices and deployment of Tamarack’s 2016 capital 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 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 (AIF) for additional risk factors relating to Tamarack. The AIF is available for viewing 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.

Tamarack Valley Energy Ltd.
Brian Schmidt
President & CEO
403.263.4440

Tamarack Valley Energy Ltd.
Ron Hozjan
VP Finance & CFO
403.263.4440
www.tamarackvalley.ca

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Tamarack Valley Energy Ltd. Announces a 46% Increase in Proved Reserves With 356% Production Replacement

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