Creating a Sustainable Business

Transcription

1 Creating a Sustainable Business January 2016 T V E : T S X 1

2 Forward Looking Information Certain information included in this presentation constitutes forward-looking information under applicable securities legislation. Forward-looking information typically contains statements with words such as anticipate, believe, expect, plan, intend, estimate, propose, project or similar words suggesting future outcomes or statements regarding an outlook. Forward-looking information in this presentation may include, but is not limited to, (i) potential development opportunities and drilling locations, expectations and assumptions concerning the success of future drilling and development activities, the performance of existing wells, the performance of new wells, decline rates, recovery factors, the successful application of technology and the geological characteristics of properties, (ii) cash flow, (iii) oil & natural gas production growth, (iv) debt and bank facilities, (v) primary and secondary recovery potentials and implementation thereof, (vi) potential acquisitions, (vii) drilling, completion andoperating costs, and (viii) realization of anticipated benefits of acquisitions. Forward-looking information is based on a number of factors and assumptions which have been used to develop such information but which may prove to be incorrect. Although the proposed management believes that the expectations reflected in its forward-looking information are reasonable, undue reliance should not be placed on forward-looking information because there can be no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified in this presentation, assumptions have been made regarding and are implicit in, among other things, expectations and assumptions concerning the performance of existing wells and success obtained in drilling new wells, anticipated expenses, cash flow and capital expenditures and the application of regulatory and royalty regimes. Readers are cautioned that the foregoing list is not exhaustive of all factors and assumptions which have been used. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These 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; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to production, costs and expenses, and health, safety and environmental risks), commodity price and exchange rate fluctuations and uncertainties resulting from potential delays or changes in plans with respect to exploration or development projects or capital expenditures. Forward-looking information is based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by the proposed management and described in the forward-looking information. The forward-looking information contained in this presentation is made as of the date hereof and the proposed management undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, unless required by applicable securities laws. The forward looking information contained in this presentation is expressly qualified by this cautionary statement. This presentation contains the term net backs which is not a term recognized under IFRS. This measure is used by the proposed management to help evaluate corporate performance as well as to evaluate acquisitions. Management considers net backs as a key measure as it demonstrates its profitability relative to current commodity prices. Operating net backs are calculated by taking total revenues and subtracting royalties, operating expenses and transportations costs on a per BOE basis. BOE Disclosure The term barrels of oil equivalent ( BOE ) may be misleading, particularly if used in isolation. A BOE conversion ratio of six thousand cubic feet per barrel (6Mcf/bbl) of natural gas to barrels of oil equivalence is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. All BOE conversions in the report are derived from converting gas to oil in the ratio mix of six thousand cubic feet of gas to one barrel of oil. In this presentation: (i) mcf means thousand cubic feet; (ii) mcf/d means thousand cubic feet per day (iii) mmcf means million cubic feet; (iv) mmcf/d means million cubic feet per day; (v) bbls means barrels; (vi) mbbls means thousand barrels; (vii) mmbbls means million barrels; (viii) bbls/d means barrels per day; (ix) bcf means billion cubic feet; (x) mboe means thousand barrels of oil equivalent; (xi) mmboe means million barrels of oil equivalent and (xii) boe/d means barrels of oil equivalent per day. This presentation is not an offer of the securities for sale in the United States. The securities have not been registered under the U.S. Securities Act of 1933, as amended, and may not be offered or sold in the United States absent registration or an exemption from registration. This presentation shall not constitute an offer to sell or the solicitation of an offer to buy nor shall there be any sale of the securities in anystate in which such offer, solicitation or sale would be unlawful. 2

3 What Sets TVE Apart Culture: Focus on delivering results CUT COSTS! low cost producer Manage the down cycle (experience) Hard targets for compensation (ROR, costs, per share metrics) Find the highest quality plays Protect the downside Hedging Balance sheet strength High net back with operated infrastructure Sustainable business Well results in the top 10 th percentile in basin 5 years inventory of quick payout wells Credibility 16 quarters of meeting or beating guidance Results: 2015 exceeded expectations Bankline held at $165 mm Only $100-$105 million drawn vs. guidance of $ million Production beat 250 boe/d above consensus Spent less capital but achieved more production Debt to cash flow approximately <1.6 times Q4/15 annualized A robust 2016 plan Generates free cash flow and pays down debt by $8 million at $40/bbl WTI Build modest production/share 2% to 5% Protected with oil hedges H1 56% / H2 30% Performance that stacks up to the best Valuation upside in stock price 3... TVE is one of the few companies in this environment able to pay down debt and build production per share.

4 Budget Principles Top priorities: First balance sheet and bank line liquidity Second modest per share growth Third build low cost inventory through land sales and tuck-ins in core areas; drill non-pud locations to allow for reserve growth Overall retain flexibility to react to commodity price volatility and bargain acquisition opportunities How is this accomplished? Capital allocated to projects with 1.5 or less payouts or better Target capex to high netback areas where owned infrastructure provides cost advantage Capital efficiency improved 10%-12% in Q4/15 (improved well performance & design changes) in addition to 20% improvement in H1/15 due to reduction in costs Build in milestone point in May/16 to reassess capital allocation with changes in commodity prices and/or redirect to acquisitions if more economic

5 Well Performance Based on Geology Tier 1 4 wells 9% Porosity (green = 2+ meters) Type curve Actual cum production Daily production tests Average daily production Tier 2 2 wells Type curve Actual cum production Daily production tests Average daily production Tier 1 wells Tier 2 wells 5... Tier 1 wells are performing 15% better than originally forecasted.

6 Tamarack Wells in the Top 10 th Percentile Top 10 th Percentile Top 25 th Percentile Note: The above IRR calculations assume CIBC s base commodity price forecast of US$45.00/Bbl WTI & C$2.78/Mcf AECO in 2016, and US$65.00Bbl WTI & C$3.40/Mcf AECO in Source: geoscout, company reports, and CIBC World Markets Inc These ROR s use corporate operating costs- using Wilson Creek operating costs (which are $4.80/boe lower than corporate average) ROR improves from 54% to 120%.

7 ROR Economic Sensitivity Type 1 well Wilson Creek 700% "1.0 mile well" 600% 500% 400% 300% 200% "1.5 mile well" "2.0 mile well" Current Oil Price NPV10BT: $1.3 mm PO: 1.2 yr TVE 2016 Hedging Average Economics suggest elimination of 1-mile wells Land consolidation has resulted in most go-forward drills will be 1.5-mile wells Now with cemented liners 2-mile wells are technically feasible and have the best economics 85% Chance of success ROR NPV Payout 100% 0% WTI USD/bbl 7 NPV10BT: $0.7 mm PO: 1.8 yr $30 $40 $50 $60 $70 $80 Edmonton Par $24.50 $31.50 $38.50 $45.50 $52.50 $59.50 Budget assumptions 1 mile well 1.5 mile well 2.0 mile well CAPEX ($m) 2,285 2,585 2,985 Net reserves (mboe) IP30 (boe/d) mile strip pricing 61% $1.2 mm 1.4 yr. 1.5 mile plan pricing 75% $1.4 mm 1.2 yr. 2.0 mile strip pricing 163% $2.6 mm 0.8 yr. 2.0 mile plan pricing 202% $2.9 mm 0.7 yr.

8 Quick Payback Drilling Inventory Payout 1.5 Years or Less TVE Drilling Inventory Other Cardium How many quick payback $38.50 WTI Opening inventory: 72 Drilled: 15 Added (deals): exit: Total $80/bbl, >25% ROR 303 Locations WTI USD/bbl Edmonton Par Oil Price (CDN $/bbl) $24.50 $31.50 $38.50 $45.50 $52.50 $59.50 $ TVE has 5 years of drilling inventory without any additional tuck-ins at $50/bbl ($38.50 USD/bbl WTI); able to keep production flat at 9,500boe/d.

9 1.5 mile 1.5 mile 1.5 mile 1.5 mile 1.5 mile Capex ($000s) 9 Control What We Can Control - Costs Savings in 2016 Budget CAPEX: Shift to sleeve from ball drop Eliminate nitrogen Reduce flaring and conserve Shorten expensive test times Minimize frac water trucking by pumping in and flowline out Mud/bit/drill pipe optimization cuts drill times by 30% Service cost reductions Future savings to be considered: Cut expensive automation Domestic sand vs. high cost US supply High speed mud motor Alternate sleeve supplier More service cost reductions 4,500 4,000 3,500 3,000 2,500 2,000 1,500 1, ,300 1,680 Equip+Tie-in Completions Drilling 2, ,050 1,520 Capital Costs 3,373 38% 2,677 2, ,051 1,051 1,379 1,379 2, ,300 H2/ Budget New Design 2016 Budget Outlook

10 1 mile 1.5 mile 1.5 mile 1.5 mile 1.5 mile 2.0 mile Capital Cost Per Stage (thousands $ per stage) Dollars / Stage - Drilling, Completing & Tie In 160 Capital Costs $/ Stage The real cost benefit and economic benefit is realized by the DCT cost per stage $145/stage More stages = more production by proportion Therefore economics are enhanced by longer wells and higher density frac designs DCT $2,904k $105/stage DCT $3,373k $92/stage DCT $2,677k 60% $64/stage DCT $2,677k $58/stage DCT $2,450k $52/stage DCT 2,840k Outlook 2016 Target 10

11 Pembina Pipeline The Evolution of a Core Area 6-19 Gas Plant Alder Flats 9-24 Compressor expected to reduce opex Q2/16 TVE land 2014 Acquisition land 2015 Acquisition land Existing Cardium producers Existing vertical Cardium oil wells Gas plant Battery Pembina oil pipeline Nova gas pipeline Field gathering lines Proposed pipeline Entry in net sections (10 sec with Cardium pay) 16 locations December sections 170 locations 2 gas plants 4 oil batteries Over 400 km of pipeline infrastructure Gas Plant... TVE has increased drilling inventory by 10x since 2013.

12 Capital Efficiency ($/ BOE) Capital Efficiency Improvements 2016 vs ,000 25,000 Decreased facilities from 21% to 4% of budget Exit Capital Efficiency Longer wells at lower cost from $2.3 mm / well / mile to $2.0 mm / well / mile 2016 Program $52 million 4 Farm-in earning wells Average length 1.45 miles 20,000 15,000 10,000 5, Program 4 Farm-in earning wells Average length 1.3 miles Higher % of portfolio Taqa earning wells from 27% to 36% of program The 30% improvement in capital efficiency was achieved through well design improvements resulting in drilling longer wells, better well results and permanent cost reductions.

13 Wilson Creek Mannville Competes for Capital AECO Price ($2.45/GJ; 2016 avg.) Offset TVE 100% WI TVE 55% WI 13 Capital ($mm) 3,050 3,050 1,693 Risking 100% 90% 90% Rate IP30 (mmscf/d) Reserves (bcf) Liquids (%) 4% 4% 4% F/C ($/boe) ROR (%) 134% 77% 77% NAV PV10BT ($mm) Recycle ratio Pay out (years) Strategy to drill Mannville during this low oil price environment: Comparable economics Increasing throughput at TVE Wilson Creek facilities will reduce area operating costs further; increases utilization of infrastructure Mannville offsets have de-risked our locations Preserves Wilson Creek oil inventory for a higher price environment Pay thickness 12 m Average porosity 10% Gas in place Well density Inventory 12 bcf/section 2 wells/section 15 wells... Conservative forecasting drill H1/16, assess results, then possibly drill another in H2/16.

14 Tamarack Profile TVE : TSX Operational e 2016B Production (boe/d) 3,276 5,717 8,425 9,500 9,700 Exit Q4 avg. production (boe/d) 4,718 7,681 9,870 9,600 9,800 % Liquids Cash flow ($mm) n/a n/a Capital ($mm) * Exit debt to cash flow (12-month trailing) <1.9 <1.6 Corporate Shares outstanding* (mm) Fully diluted* (mm) Share price Jan 29/16 $3.08 Market cap ($mm) $308 * Excludes the property acquisition in Wilson Creek for $55 million that closed on June 15, 2015 Est. enterprise value ($mm) $413 Available bank line ($mm) $165 Debt at Sept 30, 2015 ($mm) $ EV/boepd less than $44,000 boe/d on 2016 average 2016 budget price assumptions: WTI $40/bbl $51.45/bbl Edm Par, $2.45/GJ AECO, $0.70 Cdn dollar Debt expected to remain quite flat from YE/15 levels in the $ million range Liquidity on bank lines never falls below $50 million and lines never drawn by more than 70-75% 2016 to 2015 average production per share growth is expected to be 2-5% using WASO fully diluted... Tamarack will adjust spending levels as commodity prices fluctuate.

15 2016 Realistic Budgets on Realistic Prices $4.00 AECO - Gas $/GJ $70 Edmonton Par - Oil $/bbl $3.50 $60 $3.00 $50 $2.50 $40 $2.00 $1.50 $1.00 $0.50 $0.00 Assumptions: AECO Basis- $1.06/GJ Exchange Rate- $0.70 CAD TVE Plan AECO $/GJ GLJ 2016 AECO strip $/GJ (Jan 28) Q1/16 Q2/16 Q3/16 Q4/16 Q1/17 Q2/17 $30 $20 $10 $0 Assumptions: WTI / Edm Par Diff - $4.00 USD/bbl Exchange Rate- $0.70 CAD TVE Plan Edm Par GLJ 2016 WTI ($USD/bbl) Edm Par strip (Jan 28) Q1/16 Q2/16 Q3/16 Q4/16 Q1/17 Q2/17 Other Commodity Budget Assumptions % of crude 2016 ($/bbl) 2017 ($/bbl) C3 10% C4 54% C5+ 90%

16 Debt to CF (trailing year) Debt to CF Sensitivity at 9,500 boe/d & 55% Liquids year end trailing WTI Prices ($US/bbl) Even at $30/bbl WTI 2016 yearend debt to cash flow is <2.4 times and at $40/bbl WTI is <1.6 times.

17 Free Cash Flow ($ millions) Free Cash Flow Sensitivity At 9,000 boe/d At 9,500 boe/d At 10,000 boe/d Assumes: - $2.45/GJ AECO - $0.70 Cdn dollar - $4.00/bbl WTI / Edm par differential WTI Prices ($US/bbl)... Tamarack s resilient assets generate free cash flow at $40/bbl WTI and over $25 million free cash flow at $50/bbl WTI at current production.

18 2016 Sensitivities to Lower Oil Prices Downside Scenario Strip Jan 28/16 Budget Oil (US$ WTI) $30/bbl WTI $38/bbl WTI $40/bbl WTI Edmonton par (C$/bbl) $26/bbl $47.80/bbl $51.45/bbl AECO (C$/GJ) $2.25/GJ $2.25/GJ $2.45/GJ Operating netback ($/boe) $8.25/boe $13.00/boe $ $15.75/boe Capital ($millions) Average production (90% liquids) 9,500 (52%) 9,500 (55%) 9,500 9,700 (52-57%) Year over year production growth per share 2.3% 2.3% 2% 5% 2016 exit net debt ($millions) exit trailing debt to cash flow < Tamarack is well protected against lower for longer commodity prices due to resilient assets and a strong hedge book.

19 Budget Financial Stats per BOE 2014 Actuals 2015 Est 2016 Budget Average pricing $48.80/bbl WTI $40.00/bbl WTI Edm Par $94.09/bbl $57.10/bbl $51.45/bbl AECO (monthly index) $4.40/GJ $2.56/GJ $2.45/GJ $/boe Revenue Royalties 7.78 (12.9%) (10.0%) (10.8%) Operating costs Operating lease n/a Operating income G&A Interest Hedge (gains) / losses 1.06 ( ) (6.00) (6.40) Cash flow Despite forecasting an 18% decrease in WTI (to $40/bbl), Tamarack s cash flow per boe is forecasted to range between $15.50-$18.35/boe.

20 Current Hedges as at January 15, 2016 Term Hedge Type Volume Cdn Pricing January 1, 2016 to March 31, 2016 WTI fixed price 2,000 bbls/d Cdn $76.58/bbl April 1, 2016 to June 30, 2016 WTI fixed price 2,400 bbls/d Cdn $76.21/bbl July 1, 2016 to September 30, 2016 WTI fixed price 1,600 bbls/d Cdn $71.56/bbl October 1, 2015 to December 31, 2016 WTI fixed price 1,200 bbls/d Cdn $70.72/bbl January 1, 2017 to March 31, 2017 WTI fixed price 700 bbls/d Cdn $56.56/bbl April 1, 2017 to June 30, 2017 WTI fixed price 700 bbls/d Cdn $57.64/bbl 2016 average Cdn $74.36/bbl Term Hedge Type Volume Cdn Pricing January 1, 2016 to March 31, 2016 AECO fixed price swap 5,000 GJ/d Cdn $3.06/GJ April 1, 2016 to June 30, 2016 AECO fixed price swap 5,000 GJ/d Cdn $2.48/GJ July 1, 2016 to September 30, 2016 AECO fixed price swap 5,000 GJ/d Cdn $2.49/GJ Q1-Q average Cdn $2.67/GJ Assumptions: US dollar hedges were converted to Cdn dollars using strip exchange rates as of January 15,

21 Production (boe/d) Production per share (boe/d per million shares) and Debt to production ($000 s of debt per boe/d) Achieving Production Per Share Growth, While De-Levering 12,000 10,000 Oil & liquids Natural gas Production per share Debt to prod'n Debt per boe/d prod n decreased by 42% Completed Completed Wilson Sure $60 mm Energy Creek equity acquisition & acquisition financing $125 mm equity financing ,000 6,000 Completed $60 mm equity financing Completed Echoex Ltd. acquisition ,000 2,000 Prod n per share growth 19.8% Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q * 0.0 * 2016 estimates based on achieving production guidance TVE expects to keep production per share flat for 2016 while continuing to reduce debt on a boe/d basis.

22 Key 6 Month Objectives and Look-back What we said we would do What we did in Q / Q Objectives for Q / Q Cautiously proceed with drilling program to 9,200 to 9,500 boe/d while protecting balance sheet to keep optionality for M&A. Continue cost focus for an addition 5% cut in capital costs and reduce op costs/boe in Hatton further. Integrate the new assets and optimize infrastructure. Cut costs on new operations. Create a hedging program to protect the drilling economics going above previously adapted limits. Become active to influence the AB royalty review to protect the company s valuation. Deliver drilling commitments to major and build good will to expand opportunities. Continue to look for M&A respecting TVE s M&A criteria. Install a new information retinal system to integrate software, keep TVE staff count low (G&A), gain CSOX compliance for TSX graduation. 22 Production approx. 9,870 boe/d (up 5.5%), exit debt $100 to $105 million vs. guidance of $115 to $120 million. Cut $300K (10%) capex per well in 2016 budget vs Divert gas to owned facilities and drill Mannville well to spread fixed costs Q2/16. Hedging program in place is providing security. Value approx. $23 million at budget pricing. Key role on CAPP committee and Alberta chair. Waterflood & recompletes highlighted. Renegotiated to enhance economics. Completed 8 minor tuck-ins in 2015 added 63 1-mile equivalent drilling locations. Able to hold staff to 20 thru 2 major acquisitions. Achieved TSX graduation. CSOX audit 90% complete. Spend approx. $33.5 million on capex in H1/16 and achieve average production of 9,500 9,600 boe/d. Complete cost cutting projects to achieve budget. Expected Wilson Creek opex to decrease by $ /boe from Q4/15. Initiate a cost cutting process for smaller contractors, execute trials on cost reducing items for Frac s and determine timing of locking in services for longer term. Manage to hedge policy. Layer in a position for Finish input on Royalty Review. Now is a critical time when input will be key. Focus on depth targets, waterflood and recompletions. Drill 3 out of 4 remaining Farm-in commitments in H1/16. Renegotiate or drop remaining term with major. M&A similar to last years criteria. Divert drilling capex if better economics to buy production and inventory. Complete and integrate new internal reporting system. Integrate in performance processes to drive accountability and decisions.

23 Why Buy/Continue to Own Tamarack? Resilient assets in low commodity price environment Preserves a solid balance sheet As commodity prices improve, TVE high quality inventory will be economic earlier than most inventory TVE has a plan to deal with lower commodity prices that was implemented in early Nov/14 A junior company with an intermediate like land base Solid balance sheet that supports positioning for strong growth when prices recover Experienced and committed management team that reacted quickly to changing times to protect shareholder downside and at the right time can grow this company several times larger Current price of entry represents good value 23