Tamarack Valley Energy Ltd. Announces 2019 First Quarter Results

TSX: TVE

CALGARY, May 9, 2019 /CNW/ - Tamarack Valley Energy Ltd. ("Tamarack" or the "Company") is pleased to announce its financial and operating results for the three months ended March 31, 2019. Selected financial and operational information is outlined below and should be read in conjunction with Tamarack's unaudited condensed consolidated interim financial statements for the three months ended March 31, 2019 and related management's discussion and analysis ("MD&A") which are available on SEDAR at www.sedar.com and on Tamarack's website at www.tamarackvalley.ca.

Q1 2019 Financial and Operating Highlights

• Production averaged 23,149 boe/d (64% oil and NGL weighting), reflecting the Company's compliance with the production curtailment order imposed by the Government of Alberta that came into effect on January 1, 2019 ("Curtailment Order"). Tamarack adjusted the timing of its capital investment and activity in order to comply with the Curtailment Order and as a result, five wells were brought on production late in the period and had minimal contribution to average volumes in the quarter. The Company also exited Q1/19 with 18 Viking oil wells and two Cardium oil wells that were drilled awaiting completion. Based on field estimates, current production is 24,000 boe/d in line with estimated annual average production between 23,500 boe/d and 24,500 boe/d.
  
  
• Total adjusted operating field netback (see "Non-IFRS Measures") of $57.5 million ($0.25/share basic and diluted) in Q1/19 was 50% higher than the $38.3 million generated in Q4/18 ($0.17/share basic and diluted).
  
  
• Operating netback (see "Non-IFRS Measures") of $30.11/boe in Q1/19 was 58% higher than the Q4/18 netback of $19.03/boe and was equal to Q1/18 primarily due to the continuation of strong realized pricing supported by the Company's 64% oil and NGL weighting and a reduction of operating and transportation expenses.
  
  
• Net production and transportation expenses in Q1/19 were 5% lower at $10.20/boe compared to $10.76/boe in Q1/18 primarily due to increased production from the lower-cost Veteran area and a reduction in transportation expenses as a result of the recently commissioned pipeline in the Provost area of Alberta (the "Provost Pipeline").
  
  
• Invested $71.2 million in the quarter, with 76% directed to drill, complete and equip 31 (30.2 net) Viking oil wells, 7 (6.1 net) Cardium oil wells and 2.0 net Penny oil wells. In addition, 19 (18.5 net) Viking oil wells that were drilled in late Q4/18 were completed and brought on production. The Company also drilled 18 (17.7 net) Viking oil wells and 2.0 net Cardium oil wells that will be brought on production in Q2/19, resulting in the Company being able to increase production in Q2/19.
  
  
• Completed four minor tuck-in acquisitions of assets in Q1/19 totaling $1.1 million and subsequent to quarter end closed a Viking oil acquisition for $4.7 million in the Veteran/Consort area of Alberta, adding 130 boe/d and 9.4 net sections of undeveloped Viking land. These lands are adjacent to existing Tamarack lands.

Financial & Operating Results

	Three months ended
	March 31,
	2019	2018 ^3	% change
($ thousands, except per share)
Total Revenue	95,047	98,736	(4)
Adjusted operating field netback ^1	57,503	58,545	(2)
Per share – basic ^1	$ 0.25	$ 0.26	(4)
Per share – diluted ^1	$ 0.25	$ 0.25	–
Net income (loss)	(4,826)	3,294	(247)
Per share – basic	$ (0.02)	$ 0.01	(300)
Per share – diluted	$ (0.02)	$ 0.01	(300)
Net debt ^1	(219,348)	(186,732)	17
Capital Expenditures ^2	71,243	69,630	2
Weighted average shares outstanding (thousands)
Basic	226,341	228,621	(1)
Diluted	226,341	231,713	(2)
Share Trading (thousands, except share price)
High	$ 2.96	$ 3.09	(4)
Low	$ 2.03	$ 2.31	(12)
Trading volume (thousands)	64,864	30,945	110
Average daily production
Light oil (bbls/d)	12,689	13,239	(4)
Heavy oil (bbls/d)	483	299	62
NGL (bbls/d)	1,548	1,347	15
Natural gas (mcf/d)	50,576	51,879	(3)
Total (boe/d)	23,149	23,532	(2)
Average sale prices
Light oil ($/bbl)	65.47	67.92	(4)
Heavy oil ($/bbl)	40.65	45.23	(10)
NGL ($/bbl)	40.85	45.14	(10)
Natural gas ($/mcf)	2.82	2.25	25
Total ($/boe)	45.62	46.62	(2)
Operating netback ($/Boe) ^1
Average realized sales	45.62	46.62	(2)
Royalty expenses	(4.86)	(5.16)	(6)
Production expenses	(10.20)	(10.76)	(5)
Operating field netback ($/Boe) ^1	30.56	30.70	-
Realized commodity hedging loss	(0.45)	(0.59)	(24)
Operating netback	30.11	30.11	-
Adjusted operating field netback ($/Boe) ^1	27.60	27.64	-

Notes:
(1)	Adjusted operating field netback, net debt, operating field netback and operating netback do not have any standardized meaning prescribed by IFRS and therefore may not be comparable with the calculation of similar measures for other issuers. See "Oil and Gas Metrics" and "Non-IFRS Measures".
(2)	Capital expenditures include exploration and development expenditures, but exclude asset acquisitions and dispositions.
(3)	IFRS 16 was adopted January 1, 2019 using the modified retrospective approach; therefore, comparative information has not been restated.

First Quarter Review

Tamarack's Q1/19 production of 23,149 boe/d (64% oil and NGL weighting) was impacted by its required compliance with the Curtailment Order, which muted the Company's previous growth trajectory as the timing of capital spending and activity were adjusted. As a result, three Cardium and two Viking wells were drilled in the first quarter and subsequently brought on production late in the quarter resulting in minimal contribution to average Q1/19 volumes. Based on field estimates, current production is 24,000 boe/d in line with estimated annual average production between 23,500 boe/d and 24,500 boe/d.

The Company was ahead of internal forecasts for production during January, but extreme cold weather in February impacted volumes such that they could not be sufficiently offset by new wells coming on in late March.  The prolonged winter conditions allowed the Company to accelerate the drilling of second quarter wells into the first quarter. The Company exited Q1/19 with 18 Viking oil and two Cardium oil wells drilled and awaiting completion. All 20 wells drilled in the period were subsequently brought on production in the second quarter, which are expected to contribute to a ramp up in average production volumes assisting the Company in achieving its first half average production rate forecast of between 23,500 boe/d and 23,750 boe/d. This activity and spending will be assessed regularly in light of the Curtailment Order and prevailing commodity prices.

Tamarack's oil and NGL weighting remained strong at 64% compared to 63% in Q1/18 and contributed to an average realized sales price of $45.62/boe in Q1/19. The 5% reduction in net production and transportation expenses in Q1/19 which averaged $10.20/boe from $10.76/boe in Q1/18, was attributable to higher volumes from Tamarack's lower-cost Veteran area combined with lower transportation expenses associated with the December start-up of the Provost Pipeline and the effect of the new lease accounting standard, IFRS 16, "Leases". These cost reductions drove an operating netback of $30.11/boe in Q1/19, on par with Q1/18. Even with the production impacts, Tamarack recorded strong Q1/19 total adjusted operating field netbacks (see "Non-IFRS Measures") of $57.5 million ($0.25/share basic and diluted), which was 50% higher than the previous quarter due to improved oil prices and narrower differentials coupled with continued cost reductions.

Successful Execution of Strategy

The Company continued to invest in its long-term future with ongoing expansion of the Veteran waterflood. In 2018, reserves bookings attributable to waterflood only accounted for 4.9 million bbls of total proved plus probable reserves, which Tamarack estimates represents only 5% of the potential risked total waterflood upside in the area. During the quarter, the Company had ten active injector wells which increased waterflood injection volumes from 2,000 bbls/d to 12,000 bbls/d. Another water source well is expected to be drilled in Q2/19 along with completion of the remainder of the planned well conversions to injectors. Tamarack remains committed to enhancing its sustainability and anticipates positive impacts on decline rates and reserve bookings will be realized commencing in 2020.

With Q1/19 development capital spending of $71.2 million, the Company drilled, completed and equipped a total of 31 (30.2 net) Viking oil wells, 7 (6.1 net) Cardium oil wells and 2.0 net Penny oil wells. A further 19 (18.5 net) Viking oil wells that were drilled in late Q4/18 were completed and brought on production. The Company also drilled 18 (17.7 net) Viking oil wells and 2.0 net Cardium oil wells that will be brought on production in Q2/19, bringing the total drilling for the quarter to 49 (47.9 net) Viking oil wells, 9 (8.1 net) net Cardium oil wells and 2.0 net Penny oil wells. Tamarack continued to focus on improvements in capital program efficiencies and drilled the first of its two 3-mile long lateral wells in the Cardium. In moving to a 3-mile lateral, the Company expects to capture rate of return increases that are comparable to those realized when Tamarack increased lateral lengths from 1-mile to 2-miles. In addition to the positive impact of longer laterals, recently implemented modified well designs in the Cardium are also expected to improve capital efficiencies.

Further enhancing its existing asset base, Tamarack completed four minor tuck-in acquisitions in Q1/19 for $1.1 million, and subsequent to quarter end, closed an additional Viking oil tuck-in acquisition in the Veteran/Consort area for $4.7 million, adding 130 boe/d and 9.4 net sections of undeveloped Viking land. These lands are adjacent to existing Tamarack lands. 

During the first four months of 2019, the Company purchased and cancelled 434,900 outstanding common shares under its normal course issuer bid (the "NCIB") program, for a total investment of $1.1 million. The NCIB provides management a tool that can be employed when there is a perceived misalignment between the Company's prevailing share price and the underlying current and future potential value of its assets. In addition, it helps to offset the dilutive impact that may be associated with the exercise and settlement of options, restricted share units and performance share units issued under Tamarack's stock-based compensation programs. In April 2019, Tamarack received approval from the Toronto Stock Exchange to renew its NCIB under the same terms.

2019 Outlook

Tamarack's first quarter production and modification to the timing of bringing wells on production reflects the Company's compliance with the Curtailment Order. Based on the timing and allocation of capital through the first half of 2019, Tamarack anticipates that approximately 65% of its drilling program will occur in the second half of 2019 with a meaningful ramp-up in production volumes anticipated during the fourth quarter, subject to the Curtailment Order being lifted.

Based on current strip prices, the 2019 capital program is forecast to generate approximately $40 million to $50 million of adjusted operating field netback (see "Non-IFRS Measures") over and above budgeted capital expenditures, which can be directed to further asset enhancements through acquisition or incremental share buy-backs under its active NCIB program. The Company will re-evaluate its capital allocation strategy in the second half of 2019 to determine whether changes are required to its original capital budget of $170 to $180 million based on the status of the Curtailment Order and the commodity price outlook. Supported by success in accumulating an inventory of Viking and Cardium locations that payout in 1.5 years or less at current commodity prices, the Company estimates it will achieve a 3% to 5% increase in debt-adjusted production per share⁽¹⁾ growth (see "Non-IFRS Measures") in Q4/19 compared to Q4/18.

Tamarack's 2019 budget anticipates drilling 125 net wells, including Viking wells in Alberta and Saskatchewan, Cardium oil wells in Wilson Creek and oil wells in Penny. In addition, the Company intends to continue directing capital to activities related to the Veteran waterflood with $20 million budgeted for 15 well conversions in the first half of 2019 and the drilling and conversion of six additional injection wells in Veteran. While the impact of the waterflood on overall corporate decline rates is expected to be realized in 2020, programs such as the Veteran waterflood are key initiatives that serve to enhance Tamarack's long-term sustainability.

The Company's capital allocation strategy over the past several years has remained consistent with the objective of achieving sustainability at low oil prices, while generating debt-adjusted per share growth. With approximately 30% of its 2019 production protected with hedges including a US$60.00/bbl WTI put option and another approximately 3% protected by fixed price contracts at US$64.60/bbl, Tamarack remains well positioned to withstand further crude oil price volatility.

Subject to the Curtailment Order being lifted by the end of Q3 2019, the Company's 2019 guidance and assumptions are reaffirmed below.

• Annual average production between 23,500 boe/d and 24,500 boe/d (64% to 66% oil and NGL), with 2019 exit production estimated between 25,500 boe/d and 26,500 boe/d (64% and 66% oil and NGL).
  
  
• Capital expenditures between $170 million and $180 million to comply with the Curtailment Order.
  
  
• Estimated year end 2019 net debt to Q4 annualized adjusted operating field netback ratio (see "Non-IFRS Measures") of approximately 1.0 times with an estimated $100 million of liquidity on existing credit facilities.
  
  
• Average 2019 commodity price assumptions of WTI US$50.00/bbl, Edmonton Par C$52.33/bbl, WTI / Edmonton Par differential of US$10.75/bbl, AECO $1.31/GJ and a Canadian/US dollar exchange rate of $0.75.

__________________________________

^(1)

Debt-adjusted production per share is a measure of changes in production on a per share basis, with the number of shares adjusted based on changes to net debt outstanding for the periods being compared. Debt adjusted share count is calculated as total shares outstanding plus incremental shares issued using $2.30 per share to eliminate the change in net debt or in the case where net debt decreases the reduction in shares using the same $2.30 per share.

Tamarack's strategy remains focused on preserving balance sheet strength and remaining flexible with capital spending in the face of continued commodity price and crude oil price differential volatility.

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: (i) targeting repeatable and relatively predictable plays that provide long-life reserves; and (ii) 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
Mboe	thousands barrels of oil equivalent
mcf	thousand cubic feet
GJ	gigajoule
MMcf	million cubic feet
Mbbls	thousand barrels
mcf/d	thousand cubic feet per day
WTI	West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma for the crude oil standard grade
AECO	the natural gas storage facility located at Suffield, Alberta connected to TransCanada's Alberta System
IFRS	International Financial Reporting Standards as issued by the International Accounting Standards Board

Disclosure of Oil and Gas Information

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 with National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities. Boe may be misleading, particularly if used in isolation.

Reserves Disclosure. All reserve references in this press release are "Company interest reserves". Company interest reserves are the Company's total working interest reserves before the deduction of any royalties and including any royalty interests payable the Company. It should not be assumed that the present worth of estimated future cash flow presented herein represents the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. The recovery and reserve estimates of Tamarack's crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquids reserves may be greater than or less than the estimates provided herein.

Oil and Gas Metrics. This press release contains metrics commonly used in the oil and natural gas industry, such as operating field netback, operating netback, development capital, F&D costs, FD&A costs, recycle ratio, reserve life index and net asset value.

"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 and foreign exchange derivative contracts.

"Development capital" means the aggregate exploration and development costs incurred in the financial year on reserves that are categorized as development. Development capital presented herein excludes land and capitalized administration costs and also includes the cost of acquisitions and capital associated with acquisitions where reserve additions are attributed to the acquisitions.

These terms have been calculated by management and do not have a standardized meaning and may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons. Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare Tamarack's operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this press release, should not be relied upon for investment or other purposes.

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 "guidance", "outlook", "anticipate", "target", "plan", "continue", "intend", "consider", "estimate", "expect", "may", "will", "should", "could" or similar words suggesting future outcomes. More particularly, this press release contains statements concerning: Tamarack's business strategy, objectives, strength and focus; operational execution and the ability of the Company to achieve drilling success consistent with management's expectations; commodity prices; market conditions impacting realized prices; the Company's ability to withstand commodity price volatility; drilling plans including the timing of drilling; 2019 waterflood projects and the impact thereon on oil recoveries, corporate decline rates and production rates; the payout of wells and the timing thereof; expectations regarding timing of development of current inventory; oil and natural gas production levels, including annual average production and exit production in 2019; changes in decline rates and reserve bookings and the timing realization thereof; oil and liquids weighting and changes thereto; the 2019 drilling program, capital budget and guidance, including the Company's expectations to be self-sustaining in 2019; Tamarack's intent to use excess total adjusted operating field netback to purchase and cancel shares under the NCIB or to close additional accretive tuck-in acquisitions; liquidity on existing credit facilities; shareholder returns; enhanced per share metrics; the duration and impact of the Curtailment Order; the Company's compliance with the Curtailment Order; the Company's expectation that Viking and Cardium oil wells will be brought on production in Q2/19 and its impact on production in 2019; estimate of adjusted operating field netback generated from Tamarack's 2019 capital program; estimates for debt adjusted production per share in 2019; and the re-evaluation of Tamarack's capital allocation strategy. Statements relating to "reserves" are also deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future.

Tamarack remains committed to enhancing its sustainability and anticipates positive impacts on decline rates and reserve booking will be realized commencing in 2020.

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, price volatility, price differentials 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 lifting of the Curtailment Order and the timing thereof; accumulating an inventory of Viking and Cardium locations that payout in 1.5 years or less at current commodity prices; 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 the MD&A for additional risk factors relating to Tamarack, which can be accessed either on Tamarack's website at www.tamarackvalley.ca or under the Company's profile on www.sedar.com and the Company's annual information form ("AIF") for the year ended December 31, 2018.

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.

This press release contains future-oriented financial information and financial outlook information (collectively, "FOFI") about Tamarack's prospective results of operations, production, net debt, debt-adjusted production per share, estimated year end 2019 net debt to Q4 annualized adjusted operating field netback ratio and components thereof, all of which are subject to the same assumptions, risk factors, limitations, and qualifications as set forth in the above paragraphs. FOFI contained in this document was made as of the date of this document and was provided for the purpose of providing further information about Tamarack's future business operations. Tamarack disclaims any intention or obligation to update or revise any FOFI contained in this document, whether as a result of new information, future events or otherwise, unless required pursuant to applicable law. Readers are cautioned that the FOFI contained in this document should not be used for purposes other than for which it is disclosed herein.

Non-IFRS Measures

Certain financial measures referred to in this press release, such as net debt, debt-adjusted production per share, adjusted operating field netbacks and net debt to annualized adjusted operating field netback ratio, are not prescribed by IFRS. Tamarack uses these measures to help evaluate its financial and operating performance as well as its liquidity and leverage. 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.

"Net debt" is calculated as long-term debt plus working capital surplus or deficit excluding the fair value of financial instruments.

"Debt adjusted production per share" is a measure of changes in production on a per share basis, with the number of shares adjusted based on changes to net debt outstanding for the periods being compared. Debt-adjusted share count is calculated as total shares outstanding plus incremental shares issued at a current market price to eliminate the change in net debt or in the case where debt decreases the reduction in shares. Management of Tamarack believes that debt adjusted production per share is useful in determining the production growth on a per share basis as if changes to debt was extinguished by the issuance or redemption of shares. The presentation of production growth on a per share basis is skewed for oil and gas companies that have more debt on their balance sheet and in their capital structure. Such companies will show better results because more of their growth is financed through debt than equity (as opposed to generating growth through realizing a rate of return on capital employed). The debt adjusted production per share measure provides a means of putting oil and gas companies on an equal, enterprise-based footing with respect to debt when calculating per share numbers. This measure is relevant to investors to appreciate the impact the debt on a company's balance sheet has on per share growth disclosure and the strength of one company's balance sheet relative to an over-leveraged peer, particularly in volatile commodity price environments where a company's indebtedness may increase as a result of lower cash flows and higher debt financing costs.

"Adjusted operating field netback" is calculated by taking net income or loss before taxes and adding back items, including transaction costs, and certain non-cash items including stock-based compensation; accretion expense on decommissioning obligations; depletion, depreciation and amortization; impairment; unrealized gain or loss on financial instruments; and gain or loss on dispositions.

"Net debt to annualized adjusted operating field netback ratio" is calculated as net debt divided by annualized adjusted operating field netback for the most recent quarter.

"Operating field netback" is calculated as total petroleum and natural gas sales, less royalties and net production and transportation costs.

"Operating netback" is calculated as total petroleum and natural gas sales, including realized gains and losses on commodity and foreign exchange derivative contracts, less royalties and net production and transportation costs.

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.

SOURCE Tamarack Valley Energy

Brian Schmidt, President & CEO, Tamarack Valley Energy Ltd., Phone: [phone], www.tamarackvalley.ca; Ron Hozjan, VP Finance & CFO, Tamarack Valley Energy Ltd., Phone: [phone]

Related Links

www.tamarackvalley.ca