TVE Tamarack Valley Energy Ltd

Tamarack Valley Energy Ltd. (“Tamarack” or the “Company”) is pleased to announce its financial and operating results for the three and six months ended June 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 six months ended June 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.

Q2 2017 Financial and Operating Highlights 

• Achieved record corporate production in Q2/17 of 19,336 boe/d, up 9% over Q1/17 and more than doubled Q2/16, exceeding previously announced guidance despite 1,070 boe/d being curtailed through the second quarter due to the TransGas Coleville Gas Plant (the “Coleville Plant”) being shut-in.
• Increasing exit production guidance to approximately 22,000 boe/d, from a range of 20,000-21,000 boe/d due to strong operational results in the first half of 2017, which will result in 15% absolute production per share growth or 9% on a debt adjusted per share basis.
• Oil weighting increased to 51% compared to 42% in Q2/16, driving improved netbacks, while light oil production grew 20% over Q1/17.
• Liquids weighting also increased to 59% in Q2/17 compared to 52% in the same period of 2016, which positively contributed to the Company’s stronger netbacks year-over-year.
• Total funds from operations increased 119% to $33.7 million in Q2/17 ($0.15/share basic and diluted), excluding transaction costs, from $15.4 million in Q2/16 ($0.13/share basic and diluted), and increased 4% compared to Q1/17 despite lower quarter-over-quarter commodity prices. 
• Invested $19.0 million in capital in Q2/17, reflecting mild spring break-up conditions, directed to the drilling, completion, and equipping of five (4.9 net) Viking oil wells and one (1.0 net) Mannville gas well, the completion and equipping of five (4.3 net) Viking oil wells and three (3.0 net) Cardium oil wells drilled in Q1/17, and investments in longer-term projects designed to improve operational efficiencies in Veteran. 
• General and administrative (“G&A”) expenses declined 5% to $1.74/boe in Q2/17 over Q1/17 and were 14% lower than Q2/16, reflecting significant production growth without commensurate increases in overhead.
• Earnings of $3.1 million ($0.01 per share basic and diluted) in Q2/17, compared to a net loss of $10.4 million in Q2/16. 
• Reduced net debt at June 30, 2017 by 8% quarter-over-quarter, resulting in net debt to annualized Q2/17 funds from operations falling to 1.1 times, compared to 1.3 times at the end of Q1/17.

Financial & Operating Results

($ thousands, except per boe)	Three months ended								Six months ended
	June 30,								June 30,
		2017			2016		% change			2017			2016		% change
($, except per share)
Total Revenue		66,715			24,517		172			129,585			44,136		194
Funds from operations 1		33,670			15,364		119			66,026			26,539		149
Per share – basic 1	$	0.15		$	0.13		15		$	0.30		$	0.24		25
Per share – diluted 1	$	0.15		$	0.13		15		$	0.29		$	0.24		21
Net income (loss)		3,053			(10,368	)	129			5,343			(16,202	)	133
Per share – basic	$	0.01		$	(0.09	)	111		$	0.02		$	(0.15	)	113
Per share – diluted	$	0.01		$	(0.09	)	111		$	0.02		$	(0.15	)	113
Net debt 2		(152,354	)		(57,791	)	164			(152,354	)		(57,791	)	164
Capital Expenditures 3		19,947			10,309		93			84,440			27,458		208
Weighted average shares outstanding (thousands)
Basic		227,672			114,945		98			222,691			108,610		105
Diluted		229,066			114,945		99			224,419			108,610		107
Share Trading (thousands, except share price)
High	$	3.16		$	4.28		(26	)	$	3.59		$	4.28		(16	)
Low	$	1.96		$	3.36		(42	)	$	1.96		$	2.16		(9	)
Trading volume		55,440			32,394		71			136,308			61,203		123
Average daily production
Light oil (bbls/d)		9,481			3,656		159			8,691			3,729		133
Heavy oil (bbls/d)		453			384		18			469			397		18
NGLs (bbls/d)		1,453			919		58			1,615			993		63
Natural gas (mcf/d)		47,696			27,462		74			46,779			26,640		76
Total (boe/d)		19,336			9,536		103			18,572			9,559		94
Average sale prices
Light oil ($/bbl)		55.58			52.16		7			58.94			44.34		33
Heavy oil ($/bbl)		43.80			37.31		17			44.23			30.09		47
NGLs ($/bbl)		29.39			21.57		36			27.79			16.81		65
Natural gas ($/mcf)		3.01			1.62		86			2.95			1.82		62
Total ($/boe)		37.91			28.25		34			38.55			25.37		52
Operating netback ($/Boe) 4
Average realized sales		37.91			28.25		34			38.55			25.37		52
Royalty expenses		(3.97	)		(1.21	)	228			(4.05	)		(1.63	)	148
Production expenses		(11.85	)		(11.05	)	7			(11.65	)		(11.35	)	3
Operating field netback ($/Boe) 4		22.09			15.99		38			22.85			12.39		84
Realized commodity hedging gain (loss)		(0.19	)		4.69		(104	)		(0.47	)		5.96		(108	)
Operating netback		21.90			20.68		6			22.38			18.35		22
Funds flow from operations netback ($/Boe) 4		19.14			17.70		8			19.64			15.25		29

Notes:

(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, operating netback, operating field netback 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”.(3)  Capital expenditures include exploration and development expenditures, but exclude corporate acquisitions.(4)  Operating netback, operating field netback and funds flow from operations netback do 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.  

Operations Update

The second quarter of 2017 represents the first complete quarter with full integration of the assets acquired through the business combination with Spur Resources Ltd. (the “Viking Acquisition”), and clearly demonstrates the strength of Tamarack’s strategy.  Despite production curtailments and challenges resulting from the unexpected Coleville Plant shut-down that continued through the quarter, Tamarack posted record Q2 production volumes that were 9% higher than the previous quarter and more than double the same period in 2016.  Production averaged 19,336 boe/d (59% liquids), an increase of 9% quarter-over-quarter and 103% year-over-year, with a meaningful increase in Q2/17 oil weighting to 51% compared to 42% in Q2/16 and 47% in Q1/17.  Volume additions in Q2/17 reflect a full quarter of production related to the Q1/17 drilling program which contributed 2,361 boe/d from Wilson Creek / Alder Flats (68% oil and natural gas liquids), 2,044 boe/d from the Viking development program (72% oil and natural gas liquids) and 394 boe/d from the heavy oil development program.  The production additions were partially offset by lost production due to the unexpected shut-in of the Coleville Plant of 1,070 boe/d and expected declines from legacy Tamarack volumes.  Tamarack’s previous Q2/17 guidance of 18,000 to 18,500 boe/d factored in the Coleville Plant shut-down but due to continued strong operational results, the Company exceeded guidance by 5-7%. 

In response to mild spring break up conditions, the Company accelerated its second half development program in June.  This included the drilling of five (4.9 net) Viking oil wells at Veteran as well as one (1.0 net) Mannville gas well. During the quarter, the Company also provided for investment in projects designed to improve operational efficiencies near-term and future development opportunities that offer longer-term impact.  These projects include the completion of a water disposal well and expansion of the oil battery in Veteran; completion of additional tuck-in land acquisitions in Tamarack’s core areas in order to supplement the existing land base and expand the inventory of future potential drilling locations; and the purchase of seismic in one of Tamarack’s core areas which is expected to enhance the Company’s knowledge of area geology and support further development of similar assets where Tamarack controls the infrastructure. 

Positive drilling results at Veteran during the first quarter exceeded the Company’s expectations and drove the decision to accelerate the Veteran oil facility expansion to over 10,000 bbls/d of emulsion treating capacity (5,000 bbls/d oil capacity) and implement additional water handling capabilities which will eliminate water trucking and disposal costs.  As a result of these initiatives, Tamarack expects that corporate production expenses will be $0.40-0.50/boe lower by the end of 2017 compared to the average per unit production expense during the first half of 2017. 

The first quarter Veteran drilling program has continued to outperform expectations.  The majority of Veteran wells that were drilled in Q1/17 were fitted with pumping equipment sized to handle expected volumes based on area type curves, but the wells outperformed the Company’s expected type curves by up to 25%. During the second quarter, Tamarack tested the impact of increasing the size of pumping equipment on four wells. This eliminated rate restrictions experienced previously, which were caused by limitations on pump capacity.  The upgraded pumps are expected to improve 120-day average production rates by an average of 10-20 bbls/d while enhancing single well economics.  Given this improvement, Tamarack intends to install larger pumping equipment on all wells drilled in the second half of 2017.  In addition, the Company has increased its type curve for the Veteran area and as a result of shallower decline rates on wells drilled during the first quarter, also expects average reserves per well to increase, although it is too early to estimate the extent of the impact. 

At Wilson Creek, Tamarack drilled two 2-mile horizontal wells during the first quarter of 2017, testing varying frac densities and number of stages, with the results exceeding internal expectations.  The first 2-mile horizontal well drilled in Wilson Creek, at 13-3-45-6 W5M, was completed with 85 stages using 15-tonnes per stage.  During its first 115 days on production, this well produced 334 bbls/d of oil (402 boe/d) and is expected to payout in less than eight months based on strip prices.  Comparatively, the second well at Wilson Creek, 12-3-45-6 W5M, was completed with 115 stages using 15-tonnes per stage and demonstrated an average 393 bbls/d of oil (445 boe/d) during its first 115 days on production and is expected to also payout in less than eight months. 

Based on these positive results and the anticipated associated cost efficiencies, Tamarack plans to increase frac density and move to a higher tonnage per stage for future 2-mile well completions relative to levels that were deployed through 2016.  The total on-stream cost of the 85-stage well was $3.44 million and was $3.84 million for the 115-stage well. Early results indicate that increasing frac density and tonnage will generate incremental production volumes, improve paybacks and net present values.  Based on the first 115 days of production, the Company realized a 36% improvement in capital efficiencies on these higher frac density wells compared to the previous 2-mile wells drilled in 2016.  During the third quarter, the Company intends to drill additional 2-mile wells in the area testing an even tighter frac density and higher tonnage per stage than what was used in 2016.  The next 2-mile well at Wilson Creek 8-29-44-5 W5M has been drilled, and by mid-August, will be completed with 117 stages using 20-tonnes per stage. 

The Company is currently running four active drilling rigs, two in Wilson Creek and two in Veteran, and expects to invest $80-90 million in capital through the balance of 2017.  In the second half of the year, Tamarack plans to drill seven 2-mile Cardium wells at Wilson Creek (including the 2-mile 8-29 well above) as well as two 1.5-mile wells; 35-40 Viking wells at Veteran; up to six wells at Milton; two wells at Penny; one to three wells at Redwater; and one Mannville natural gas well. 

Outlook

Tamarack’s priority is to maintain financial flexibility which will position the Company for organic per share growth, and allow Tamarack to capitalize on attractive opportunities to enhance its asset base which may arise in a weaker and more volatile commodity price environment.  With strong drilling results achieved thus far in 2017, the Company believes its robust drilling inventory supports a multi-year, per share growth strategy and positions Tamarack for further success.  The Company has continued to reduce its net debt, which was 8% lower at the end of Q2/17 versus Q1/17, while improving its net debt to quarter annualized funds flow ratio which declined to 1.1 times at June 30, 2017 compared to 1.3 times at March 31, 2017.  By the end of 2017, at current strip prices Tamarack anticipates net debt to fourth quarter annualized funds flow (including hedges) to be below 1.0 times, with between $95 to $105 million of available liquidity estimated on its credit facilities.  The Company has also continued to seek downside risk mitigation and support its strong balance sheet by layering in additional hedges, resulting in approximately 28-30% of forecast second half 2017 oil production hedged at $70.36/bbl Canadian and 57-60% of natural gas hedged at $2.78/GJ AECO. Tamarack also has approximately 50% of its first quarter 2018 natural gas production hedged at $3.16/GJ AECO.  All of these steps are important factors in providing shareholders with strong debt-adjusted returns amidst an uncertain commodity price environment. 

On July 16, 2017, the Coleville Plant recommenced partial operations, with full-scale operations expected later in the year.  Tamarack continues to have production of approximately 2.0 MMcf/d and 30 bbls/d of NGLs curtailed, but the Company’s strong drilling results to date have enabled Tamarack to meet and exceed guidance despite this restriction.  Since the resumption of the Coleville Plant’s partial operations, Tamarack’s production based on field estimates has averaged approximately 20,000 boe/d (56% liquids weighting), setting the stage to meet or exceed the Company’s full year 2017 production average guidance of 19,000 to 20,000 boe/d.  In addition, based on the strength of the first half 2017 drilling results, Tamarack has increased its exit production guidance to approximately 22,000 boe/d (57-62% oil and NGLs), up from 20,000 to 21,000 boe/d.  By exiting 2017 at 22,000 boe/d, Tamarack will have achieved absolute production per share growth of over 15% and debt-adjusted production per share growth of approximately 9% compared to 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

Unit Cost Calculation

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 National Instrument 51‑101 – Standards of Disclosure for Oil and Gas Activities. 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”, “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; the ability of the Company to achieve drilling success consistent with management’s expectations; drilling plans including increases to frac density and intensity, and timing of drilling; the timeframe for resumption of full operations at the Coleville Plant; the completion of the water disposal well and expansion of the oil battery in Veteran; tuck-in land acquisitions in Tamarack’s core areas; the purchase of seismic in one of 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 including changes resulting from upgraded pumps; adjustments to the 2017 capital expenditure program and expected production in the second half of 2017; 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 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. 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