ANNUAL REPORT 2014 IMPROVING CAPITAL EFFICIENCIES. SOLID BALANCE SHEET. MULTI-YEAR INVENTORY.

Transcription

1 ANNUAL REPORT IMPROVING CAPITAL EFFICIENCIES. SOLID BALANCE SHEET. MULTI-YEAR INVENTORY.

2 STRONG FUTURE. DeeThree s improved capital and operating efficiencies, strong balance sheet and massive inventory of multi-zone drilling opportunities solidly position the Company to navigate through the current commodity price weakness. DeeThree s $160 million 2015 capital program will increase average production to approximately 13,300 boe per day while conserving the balance sheet and maintaining financial flexibility. HIGHLIGHTS 04 LETTER TO SHAREHOLDERS 08 RESERVES SUMMARY 12 MANAGEMENT S DISCUSSION AND ANALYSIS 19 INDEPENDENT AUDITORS REPORT 47 FINANCIAL STATEMENTS 48 NOTES TO THE FINANCIAL STATEMENTS 52 CORPORATE INFORMATION 76

3 13 Consecutive quarters of production growth through Q MILLION BOE Proved + probable reserves at year-end 2013 MILLION BOE Proved + probable reserves at year-end IMPROVING CAPITAL EFFICIENCIES Focused horizontal drilling in DeeThree Exploration Ltd. s two core areas drove 58 percent year-over-year growth in average daily production, to 11,325 boe per day (80 percent oil and natural gas liquids) in. Reducing technical risks and further refining our well drilling and completions processes improved per-well results and lifted operating netbacks. In, DeeThree again recorded some of the best on-stream results for new oil wells drilled in western Canada. The average netback increased by over 12 percent, from $40.50 per boe in 2013 to $45.16 per boe in, despite softening commodity prices toward year-end.

4 FERGUSON Gas injection EOR scheme mitigates declines and increases oil recoveries ALBERTA BAKKEN GAS INJECTION EOR SCHEME MODEL AREA 5, , , , ,000 2,500 2, Well Count 1, , Q Q Q Q1 Q2 Q3 Q4 Q Oil Production (bbls/d) Gas Injection (mcf/d)

5 DTX.TO 1 BRAZEAU Significant pool extensions in the prolific Belly River C and D zones at Brazeau New 12,000 bbl/d central oil battery improves operating efficiency $ 50,000 BRAZEAU BELLY RIVER IMPROVING CAPITAL EFFICIENCIES ,000 40, ,000 30, ,000 20, ,000 10, , Target 0 Drilling & Completion Costs ($ per boe/d of new production added*) * Excludes tie-in costs Average per well IP365 (boe/d)

6 2 DTX.TO BRAZEAU day IP day IP AVERAGE WELL DRILLED AT BRAZEAU IN (BOE/D) day IP 1, day IP BEST WELL AT BRAZEAU IN (BOE/D) 1, day IP day IP HOW WE HAVE IMPROVED CAPITAL EFFICIENCIES Improved Per-Well Results: the Key to Capital and Operating Efficiencies DEETHREE MADE CAPITAL EFFICIENCIES A HIGH PRIORITY LONG BEFORE COMMODITY PRICES SOFTENED. Seeking to build shareholder value for the long term, we worked hard to increase the reserves and production impact of each dollar of capital invested at both core areas. Many separate measures contributed. Longer-leg horizontal wells with more fracturing stages and heavier tonnage. Lowering geological risk as pool areas became delineated. Stateof-the-art drilling tools to stay in the target reservoir and maximize the length of horizontal reservoir pay. Drilling multiple wells per pad to exploit common infrastructure. THE RESULTS ARE CLEAR: HIGHER AVERAGE INITIAL PRODUCTIVITY PER WELL AND LOWER COST PER BOE OF DAILY PRODUCTION ADDED. Brazeau Belly River Sands At Brazeau, we completed numerous two-mile-long (or >10,000-foot) horizontal well legs in, placing up to 950 tonnes of sand over 30 fracturing stages. We focused on increasing vertical fracture development to access geological sub-units within the reservoir. To improve operating efficiency, we enlarged the central oil battery to 12,000 bbls per day capacity and completed a network of 8 gathering lines across the play. We also found success through exploration by development, a low-risk tactic of pushing pool boundaries outward in small increments by drilling a long-leg horizontal well through a length of known pool area, then outward into an area without well control. DeeThree will pursue further capital and operating efficiencies in 2015, such as testing down-space drilling to eight wells per section of pool area, plus potentially drilling up to eight wells from a common pad. Ferguson Upper Bakken Siltstone In Ferguson, a discovery well in extended the Upper Bakken pool by 7 miles to the southwest, setting up a new 30-section exploration area with minimal reserves booked at year-end. Our primary focus at Ferguson in was to maximize the pool s profitability and long-term resource recovery. The gas injection pressure maintenance scheme initiated in 2013 showed with very promising initial results, so in we expanded the program to three gas injection wells, high-pressure injection compression and flow lines.

7 DTX.TO 3 FERGUSON 25% Reduction in average per well costs at Ferguson in ALBERTA BAKKEN EOR PROCESS 5.6 km R 16 R km Banff 1,250 m Alberta Bakken Bakken Siltstone Exshaw Shale 14 m Producer Gas Injector Water Injector

8 4 DTX.TO FINANCIAL AND OPERATING HIGHLIGHTS Years Ended December 31, 2013 Change Financial (000s, except per share amounts) ($) ($) (%) Oil and natural gas revenues 303, , Funds from operations (1) 173,196 93, Per share basic Per share diluted Cash flow from operating activities 184,239 97, Net income 76,233 18, Per share basic Per share diluted Capital expenditures (2) 296, , Working capital deficit (at year-end) (3) 171, , Bank debt (at year-end) 139,234 88, Shareholders equity (at year-end) 463, , Share Data (000s) (#) (#) (%) At period-end 88,974 81,560 9 Weighted average basic 86,088 76, Weighted average diluted 88,763 78, Operating (4) Production Natural gas (mcf/d) 13,823 9, Crude oil (bbls/d) 8,353 5, NGLs (bbls/d) Total (boe/d) 11,325 7, Average wellhead prices Natural gas ($/mcf) Crude oil and NGLs ($/bbl) Combined average ($/boe) Netbacks Operating netback ($/boe) Funds flow netback ($/boe) Reserves Proved (mboe) 35,354 26, Proved plus probable (mboe) 51,833 39, Total net present value proved plus probable (10% discount, before taxes) ($000s) 893, , Undeveloped land Gross (acres) 466, , Net (acres) 437, , Gross (net) wells drilled Gas (#) 1 (1.00) ( ) ( ) Oil (#) 43 (42.93) 32 (31.19) 34 (38) Dry and abandoned (#) 3 (3.00) 3 (2.97) (1) Total (#) 47 (46.93) 35 (34.15) 34 (37) Average working interest (%) (1) Funds from operations and funds from operations per share are not recognized measures under International Financial Reporting Standards (IFRS). Refer to the commentary in the Management s Discussion and Analysis under Non-GAAP Measurements for further discussion. (2) Total capital expenditures, including acquisitions and excluding non-cash transactions. Refer to commentary in the Management s Discussion and Analysis under Capital Expenditures and Acquisitions for further information. (3) Working capital deficit, which is calculated as current liabilities (excluding derivative financial instruments) and bank debt less current assets (excluding derivative financial instruments), is not a recognized measure under IFRS. Please refer to the commentary under Non-GAAP Measurements for further discussion. (4) For a description of the boe conversion ratio, refer to the commentary in the Management s Discussion and Analysis under Other Measurements.

9 DTX.TO 5 DEETHREE S FOCUS ON HIGH PERFORMANCE AT THE FIELD LEVEL plus a disciplined financial approach have given the Company financial strength and flexibility. We are not sugar-coating the commodity price situation in 2015: DeeThree s financial strength will be put to the test. Reduced capital spending only slightly exceeding cash flow in the first half will enable us to continue growing production while carefully managing our debt levels and ratios. SOLID BALANCE SHEET Funds from Operations ($ millions, $/share) Operating Netback ($/boe) Operating Costs ($/boe) Net Debt ($ millions) $ Millions $/Share $23.41 $32.66 $40.50 $ $14.32 $10.53 $9.91 $9.44 Net Debt ($ Millions) Debt to Funds Flow Ratio Growing production from the successful exploration and development of our liquids-producing plays at Brazeau and Ferguson, along with greater operating efficiencies, have delivered successive years of cash flow growth. The high quality of these two plays will support DeeThree in getting the most production and cash flow out of each dollar invested in Much of what DeeThree talks about on the technical side better results per well, higher IPs, improved type curves, more efficient infrastructure is crystallized in this metric. We re proud of our multiyear growth record, to some of the highest companywide netbacks in western Canada s producing sector. Last year s Companyrecord netback provides a substantial cushion for this year s more difficult conditions. Operating costs are typically higher for oil-focused producers than for gas-weighted companies, especially as oil pools move into secondary or enhanced recovery. DeeThree has worked hard to maximize operating efficiencies building centralized oil batteries and connecting wells via flow lines rather than trucking fluids. The results are clear in our record of declining operating costs per boe. This creates another strong advantage for navigating through lower commodity prices. DeeThree s bank lines provided overall borrowing capacity of $310 million at year-end, of which $170.8 million remained available. Our reduced 2015 capital program will be over 90 percent directed to drilling and completing wells, focused on adding production to maximize the year s cash flow. DeeThree expects to exit 2015 with a debt to funds from operations ratio of 1.1:1.

10 6 DTX.TO 338 Number of confirmed, de-risked horizontal drilling locations at Brazeau at year-end Number of confirmed, de-risked horizontal drilling locations at Brazeau at year-end Long-leg horizontal drilling locations in delineated Upper Bakken pool area at Ferguson Sections of new development lands at Ferguson 2 % Estimated overall resource base booked as 2P reserves at both core areas, year-end MULTI-YEAR INVENTORY DeeThree has a Strong Future Our focus on getting the most oil out with each well i.e., maximizing our capital efficiencies while operating more efficiently through greater scale and dedicated new infrastructure will help DeeThree weather the current market weakness. Quite simply, moving up the performance ladder has pushed down our break-even commodity price. That gives us the confidence to continue investing this year, at a conservative rate tailored to today s financial constraints. High-Quality, Multi-Zone Opportunities The quality of DeeThree s resource base reflected in the 44 API light oil produced from multiple stacked zones at Brazeau, the lower-decline production at Ferguson, and the high average IP we re achieving at both plays is enabling DeeThree to continue drilling this year. We are aiming for modest production growth in 2015, while remaining financially and operationally strong and flexible.

11 DTX.TO 7 Brazeau Operations Land (net) 95,485 acres Average working interest (earned lands) 97% Geology Belly River Cretaceous stacked sands 10 productive zones and sub-zones established Horizontal wells drilled in 28 Production at year-end 9,086 boe per day Land held at year-end DTX oil battery Keyera West Pembina gas plant Hz well Gas pipeline Oil pipeline Ferguson Operations Land (net) 407,183 acres Average working interest (earned lands) 99% Geology Upper Bakken Siltstone Horizontal wells drilled in 18 Production at year-end 3,540 boe per day ALBERTA Brazeau STRONG FUTURE With modern, high-capacity infrastructure in place at both plays, thanks to concerted investments over the previous two years, DeeThree is now able to focus almost entirely on adding production by drilling and completing wells. With two rigs running in 2015, we are drilling 13 net horizontal wells in the first half of 2015 and plan a further 16 net wells in the second half. Levering our years spent de-risking both plays, we are aiming to set new records in per-well results and capital efficiencies. This will maximize the production impact and cash flow impact of each dollar of capital invested. The majority of our new wells drilled in 2015 will be in the highly productive, light-oil-producing Belly River sands at Brazeau. At Ferguson, substantially all of the solution gas produced will be reinjected and DeeThree expects this Ferguson program to materially reduce the asset s overall production decline. With an estimated 500 million barrels of oil-inplace in the Upper Bakken, every 1 percent increase in the recovery factor represents 5 million barrels of oil, approximately 10 percent of DeeThree s current booked reserves. With limited drilling required in 2015, Ferguson is expected to generate free cash flow even at current commodity prices. DeeThree s large inventory of high-working-interest wells at our two well-understood, largely de-risked core areas of Brazeau and Ferguson will support many years of more robust activity and faster production growth under appropriate commodity prices.

12 8 DTX.TO LETTER TO SHAREHOLDERS DeeThree had another highly successful year in, increasing average daily production by 58 percent and funds from operations by 86 percent year-over-year, and adding over 12 million boe in proved plus probable reserves at year-end. All of our growth was achieved through successful drilling, complemented by minimal working interest acquisitions, with lower overall risks than in With the severe reduction in oil and natural gas prices towards the end of, we are fully cognizant that investors are concerned about the ongoing effects of commodity price weakness and volatility on exploration and production companies. Balance sheet health, production profiles, decline rates under reduced drilling programs and overall sustainability are key areas of focus. Last year at this time, we talked about moving our drilling program into manufacturing mode, with a focus on improving per-well results and capital efficiencies and we did so, as the graphics on the previous pages illustrate. We are generating greater production from each dollar of capital invested, a critical advantage in capital-constrained times. Additionally, we have reduced operating and G&A expenses per unit of production and are generating greater operating netbacks and funds from operations at a given commodity price, making the most of each boe produced. By remaining conservative with our balance sheet as we grew production, we entered 2015 with manageable debt and substantial unutilized borrowing capacity. In sum, we are sustainable at current commodity prices and prepared on multiple levels to weather low commodity prices. We have reduced 2015 s capital spending in order to maintain our balance sheet. We are drilling fewer wells in 2015, all at high-graded locations, in order to achieve the greatest capital efficiency. We are confident that DeeThree has a strong future despite this down phase in the commodity price cycle. The high quality of our resource base, the large size of our drilling inventory now at 520 horizontal locations, enough to keep five drilling rigs busy for at least 10 years and our record of drilling success over multiple years position DeeThree to resume its fast rate of growth to exploit a recovery in commodity prices. Highlights Significant achievements in included: Increased annual average production to 11,325 boe per day, a gain of 58 percent over Fourth quarter average production rose to a new three-month high of 12,842 boe per day, up by 49 percent from the same period in DeeThree s crude oil and liquids weighting was 80 percent in compared to 77 percent in 2013; Increased oil and gas revenues by 70 percent from $178 million in 2013 to $303 million in ; Grew funds from operations from $93 million ($1.23 per basic share) in 2013 to $173 million ($2.01 per basic share) in, an 86 percent increase; Reduced year-over-year net G&A costs per unit of production by 19 percent, from $2.48 per boe in 2013 to $2.01 per boe in ;

13 DTX.TO 9 Reduced operating costs year-over-year, showing particular improvement in the fourth quarter, with operating costs declining by 26 percent from $10.03 per boe in the fourth quarter of 2013 to $7.45 per boe in the fourth quarter of ; Improved the average operating netback by 12 percent to $45.16 per boe in from $40.50 per boe in 2013; Increased total proved plus probable reserves by 31 percent to 51.8 million boe as at December 31, from 39.4 million boe at year-end 2013; FOURTH QUARTER AVERAGE PRODUCTION ROSE TO A NEW THREE-MONTH HIGH OF 12,842 BOE PER DAY, UP BY 49 PERCENT FROM THE SAME PERIOD IN Increased the Company s estimated net asset value, on a net present value, before tax, 10 percent discounted basis, to $8.75 per fully diluted share at December 31, ; Achieved all-in finding, development and acquisition costs, including the change in future development capital, of $21.51 per boe on proved plus probable reserve additions and $27.89 per boe on total proved reserve additions; and Increased the Company s availability under its credit facility by 88 percent during the year to $310 million, exiting with net debt of $171 million. Operations In, we executed the largest exploration and development capital program in our history. The Company invested $297 million to drill a total of 47 gross (46.93 net) wells with a 94 percent success rate. Drilling activity was concentrated in our two core areas, with 18 gross wells drilled in the Upper Bakken at Ferguson, 28 gross wells drilled in the multi-zone Belly River stacked sands at Brazeau and one gross well drilled on our non-core property in the Peace River Arch. The Company achieved material improvements in operating and capital costs. On the operating cost side, previous investments in infrastructure, plus an additional $18 million invested in to enlarge the Brazeau oil battery to 12,000 bbls per day capacity, add gas compression and lay additional 8 flow lines, resulted in meaningfully lower operating costs. On the capital spending side, a combination of lower service costs, improved processes and careful execution of our program enabled DeeThree to materially improve capital efficiencies. FERGUSON UPPER BAKKEN SILTSTONE DeeThree s primary focus at its 100 percent working interest Ferguson property last year was further testing and development of the gas reinjection enhanced oil recovery (EOR) scheme. This program s success was a major highlight for. We initiated a pressure maintenance and resource conservation program in July 2013, reinjecting some of the solution gas produced along with the Bakken oil, using one converted producing well. Last year we invested $7 million and enlarged the EOR scheme, adding two further injector wells and a built-for-purpose gas compressor plus highpressure injection lines. This enabled the Company to reinject 100 percent of its produced gas into an EOR area covering 14 sections in the heart of the Ferguson pool. Production from the field averaged 4,284 boe per day in, with producing wells experiencing an average decline rate of 40 percent. We previously stated that sound reservoir management aimed at maximizing the long-term recovery of this reservoir s large volume of oil-inplace should be our highest priority. DeeThree s EOR scheme demonstrates this commitment, and the initial results suggest we are on the right path. The Upper Bakken reservoir is oil-saturated but shallow, naturally under-pressured and lacking in natural water drive. The reservoir pressure and production results demonstrate that the gas flood mitigates decline rates on offsetting producing wells, as the graph and illustration on the previous pages indicate.

14 10 DTX.TO Recent well results in the EOR injection area show very strong production results, with one well testing at up to 1,800 bbls per day and as of early March producing 370 bbls per day plus 450 mscf of gas per day. The results have encouraged us to accelerate the transition to full implementation of the EOR scheme. The scheme s first water injection well and two more gas injection wells are planned in Initial results from a third-party computer simulation of the Ferguson pool suggest that the EOR scheme could triple the recovery factor (or percentage of the reservoir s oil-in-place that can be ultimately produced) relative to primary production alone. CAPITAL EFFICIENCIES IN BRAZEAU HAVE IMPROVED FROM $41,000 PER BOE PER DAY ADDED IN 2012 TO $29,000 IN 2013 AND $24,000 IN. Going forward, we plan to increase production at Ferguson at a pace matching the growth of our EOR scheme. Lower decline rates along with improved drilling techniques, such as monobore drilling, which have reduced per-well capital costs by percent in initial tests, should each help to further improve capital efficiencies at Ferguson. Another significant event in was a discovery well confirming a 7-mile, 30-section western extension of our Upper Bakken play. This year we will drill one delineation well to follow-up on last year s well, which could add materially to the current inventory of 80 long-leg horizontal drilling locations, giving DeeThree a 30-mile-long Upper Bakken fairway, all held at 100 percent working interest. BRAZEAU BELLY RIVER MULTI-ZONE STACKED SANDS Last year, DeeThree drilled 28 of its 47 wells at Brazeau, where results continue to demonstrate the quality and scale of the multi-zone play. Drilling activity last year at Brazeau was generally on lower-risk locations than in 2013, focusing less on pool extensions and testing new zones, and more on improving per-well results. Capital efficiencies in Brazeau have improved from $41,000 per boe per day added in 2012 to $29,000 in 2013 and $24,000 in, while average first-year per-well productivity improved from 114 boe per day in 2012 to 172 boe per day in 2013 and to 220 boe per day last year. Our best well in was better than the best well in 2013, and the average well was better than the average 2013 well. These results came about through a number of technical refinements, including drilling two-milelong horizontal well legs, increasing to 30 fracturing stages per well and up to 40 tonnes per stage, improved placement of the horizontal well leg within the pay zone through the use of rotary steerable bits, and greater use of multi-well pads to exploit existing infrastructure. To date in 2015, the Company has drilled three 100 percent working interest, multi-stage fractured horizontal wells at Brazeau, all of which have met or exceeded expectations. Our results so far include a Belly River D zone well which tested at a final flowing rate of 1,700 bbls per day of crude oil and 1.9 mmscf per day of natural gas at 260 psi wellhead pressure after a four- day test. As such, DeeThree will be able to meet its production targets for the first quarter with fewer wells than originally planned. Capital cost reductions achieved to date are in-line with the 10 percent year-over-year cost reduction provided for in our 2015 budget. Brazeau remains a growth play over the long term. The play now extends over 40 miles of multizone fairway held at nearly 100 percent average working interest, with a current inventory of 440 horizontal locations. Brazeau offers 70 sections of pool area, with up to 10 commercial zones, several of which have only been tested and remain essentially undeveloped. Brazeau is a critical part of DeeThree s strong future.

15 DTX.TO 11 Risk Management DeeThree has secured several commodity contracts to protect its cash flow and support its 2015 capital budget. Prior to the decline in world oil prices last fall, the Company had 2,000 bbls per day of crude oil contracted for 2015 with 500 bbls per day in a U.S. dollar collar (US$85.00 per bbl floor and US$ per bbl ceiling). The remaining 1,500 bbls per day are hedged at a fixed price in Canadian dollars ranging from $99.00 per bbl to $ per bbl. Subsequent to year-end, the Company hedged an additional 500 bbls per day, 250 bbls per day for March 2015 to June 2016 at a fixed price of Cdn$72.92 per barrel and 250 bbls per day for 2016 at a fixed price of Cdn$78.00 per bbl. In addition, the Company has one foreign exchange contract and one interest rate contract in place (please see the following Management s Discussion and Analysis for further details). Outlook As we announced in mid-january, our 2015 capital program includes planned expenditures of up to $160 million. With 93 percent of 2015 capital spending focused on drilling and completing wells, we anticipate delivering production growth of 18 percent year-over-year, to 13,300 boe per day in We are prudently managing our capital expenditures and production levels in combination with our debt. At present, we are on-track to meet these targets. We will be focused throughout the year on meeting operational guidance while maintaining maximum financial and operational flexibility. As such, DeeThree will continue to re-evaluate its capital spending in the context of commodity prices. The Company remains focused on improving capital costs through further service cost reductions and added improvements to well drilling and completion processes, including infill drilling with up to eight wells per common pad targeting multiple zones at Brazeau. With a slower pace of activity in 2015, along with the EOR scheme on our Alberta Bakken property, we expect our production decline rate to improve by as much as 10 percent from the 40 percent corporate decline experienced in. As we announced in early March, per-well results to date in 2015 have been so strong that we were able to reduce the planned number of first-half 2015 wells from 10 to six, conserving additional capital without affecting planned production. The combination of lower declines, improved capital efficiencies and reduced spending will enhance DeeThree s sustainability. Many thanks to our office staff, the management team and all our shareholders for their continued support and their trust in all of us at DeeThree. On behalf of the Board of Directors, Martin Cheyne President & Chief Executive Officer March 25, 2015

16 12 DTX.TO > RESERVES SUMMARY AND ADDITIONAL INFORMATION SALES SUMMARY Three Months Ended December 31, Years Ended December 31, Natural gas (mcf/d) 16,510 10,251 13,823 9,881 Crude oil (bbls/d) 9,275 6,547 8,353 5,205 NGLs (bbls/d) Total (boe/d) 12,842 8,625 11,325 7,184 LAND SUMMARY Undeveloped Developed Total Gross Net Gross Net Gross Net (acres) (acres) (acres) (acres) (acres) (acres) Lethbridge 357, ,365 54,112 51, , ,183 Brazeau 76,960 63,072 47,400 32, ,360 95,485 Peace River Arch 29,600 17,589 48,082 24,453 77,682 42,042 Other 2,880 1,702 6,880 4,337 9,760 6,039 Total 466, , , , , , Lethbridge 254, ,223 50,890 48, , ,996 Brazeau 33,600 27,066 26,720 22,746 60,320 49,812 Peace River Arch 42,560 28,837 51,612 25,290 94,172 54,127 Other 3,680 2,142 7,040 4,474 10,720 6,616 Total 334, , , , , ,551 As at December 31,, DeeThree controlled petroleum and natural gas leases covering 437,728 net acres of undeveloped land, a 41 percent increase from the 311,268 net acres held at the end of During, DeeThree invested $8.2 million for the acquisition of 131,666 net acres of petroleum and natural gas rights in the Lethbridge area at an average cost of $61.92 per acre and $7.5 million for the acquisition of 29,356 net acres of petroleum and natural gas rights in the Brazeau area at an average cost of $ per acre.

17 DTX.TO 13 RESERVES Sproule Associates Limited ( Sproule ), an independent petroleum engineering firm, evaluated the natural gas, crude oil and NGLs reserves of the Company as at December 31, and Sproule based their evaluation on land data, well and geological information, reservoir studies, estimates of on-stream dates, contract information, current hydrocarbon product prices, operating cost data, capital budget forecasts and future operating plans provided by DeeThree, and prepared their report in accordance with the Canadian Securities Administrators National Instrument NI , Standards of Disclosure for Oil and Gas Activities. The required disclosure of the reserves estimates and future net revenue of the Company as at December 31,, based on forecast prices and costs, is outlined below along with the economic assumptions used in preparing those estimates. For purposes of computing such units, natural gas is converted to equivalent barrels of oil using a conversion factor of six thousand cubic feet of gas to one barrel of oil. This conversion ratio of 6:1 is based on an energy-equivalent conversion for the individual products at the burner tip and does not represent a value equivalency at the wellhead. Such disclosure of boes may be misleading, particularly if used in isolation. Also refer to the disclosure under Statement of Reserves Data and Other Oil and Gas Information included in the Company s Annual Information Form for the year ended December 31,. SUMMARY OF OIL AND GAS RESERVES The following table outlines the oil and gas reserves of the Company by product type on a gross (before royalties) and net (after royalties) basis: Crude Oil Natural Gas NGLs Total Gross Net Gross Net Gross Net Gross Net (mbbls) (mbbls) (mmcf) (mmcf) (mbbls) (mbbls) (mboe) (mboe) Proved Developed producing 10,837 8,375 24,815 22,336 1, ,032 12,810 Developed non-producing ,809 5, ,780 1,285 Undeveloped 12,388 10,248 23,053 20,915 1, ,542 14,716 Total proved 23,417 18,778 55,677 48,856 2,657 1,890 35,354 28,810 Probable 11,830 8,674 21,735 18,528 1, ,479 12,447 Total proved plus probable 35,247 27,452 77,412 67,384 3,684 2,574 51,833 41,257 Note: Table may not be additive due to rounding. NET PRESENT VALUES OF FUTURE NET REVENUE The net present values of future net revenue of the Company s reserves at various discount rates on a before-tax basis are outlined below. ($000s) Before Income Taxes Discounted At 0% 5% 10% 15% 20% Proved Developed producing 542, , , , ,336 Developed non-producing 56,697 25,884 14,291 9,372 6,970 Undeveloped 508, , , , ,908 Total proved 1,106, , , , ,214 Probable 599, , , , ,832 Total proved plus probable 1,706,779 1,184, , , ,047 Note: Table may not be additive due to rounding.

18 14 DTX.TO RECONCILIATION OF COMPANY INTEREST RESERVES BY PRINCIPAL PRODUCT The reconciliation of the Company s gross proved, probable and proved plus probable reserves for December 31, is as follows: Crude Oil Natural Gas Proved Proved Plus Plus Proved Probable Probable Proved Probable Probable (mbbls) (mbbls) (mbbls) (mmcf) (mmcf) (mmcf) January 1, 17,954 9,787 27,741 39,007 15,640 54,647 Acquisitions , ,819 Drilling extensions 9,508 4,792 14,300 19,354 8,499 27,853 Exploration Infill Discoveries Technical revisions (1,158) (2,797) (3,955) (722) (2,870) (3,592) Economic factors (40) (4) (43) (184) (43) (227) Production (3,045) (3,045) (5,088) (5,088) December 31, 23,417 11,830 35,247 55,677 21,735 77,412 NGLs Proved Proved Plus Plus Proved Probable Probable Proved Probable Probable (mbbls) (mbbls) (mbbls) (mboe) (mboe) (mboe) January 1, 1, ,564 26,285 13,128 39,413 Acquisitions ,058 Drilling extensions 1, ,639 13,893 6,688 20,581 Exploration Infill Discoveries Technical revisions (291) (220) (511) (1,569) (3,469) (5,065) Economic factors (6) (6) (76) (11) (87) Production (244) (244) (4,137) (4,137) December 31, 2,657 1,027 3,684 35,354 16,479 51,833 Note: Table may not be additive due to rounding. Total

19 DTX.TO 15 TOTAL FUTURE NET REVENUE The following table provides a breakdown of the various components of total future net revenue on an undiscounted basis for proved and proved plus probable reserves: ($000s) Future Net Revenue Well Before Operating Development Abandonment Income Revenue Royalties Costs Costs Costs Taxes Proved ,485 51,018 45, ,500 24, ,107 60,724 50, , , ,129 58,083 48,921 42, , ,946 49,196 42,295 3, , ,228 42,168 38, , ,523 35,363 36,400 82, ,831 28,474 34, , ,981 23,329 32,570 59, ,111 19,187 31, , ,879 16,118 29,802 43, ,383 13,681 28,979 37, ,102 11,791 27, ,335 Remainder 593,263 88, , , ,834 Total proved 2,647, , , ,575 7,326 1,106,874 Proved plus probable ,774 64,711 52, ,025 23, ,697 88,835 62, , , ,033 97,571 60,986 56, , ,212 83,365 52,312 8, , ,810 68,337 48, , ,681 57,999 44, , ,467 48,696 42, , ,131 40,773 40,633 88, ,053 33,818 38, , ,531 28,519 37,431 69, ,068 24,213 36, , ,795 20,891 35,301 54,603 Remainder 1,159, , , , ,913 Total proved plus probable 4,042, ,419 1,095, ,050 10,850 1,706,779 Note: Table may not be additive due to rounding.

20 16 DTX.TO SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS The economic parameters, as determined by Sproule, assumed in preparing the forecast prices and costs reserves report are outlined below. Price Forecast Effective December 31, Currency WTI Edmonton Henry Alberta Exchange Cushing, Light Hub, AECO-C Year Rate Oklahoma Par Louisiana Spot (US$/Cdn$) (US$/bbl) (Cdn$/bbl) (US$/mmbtu) (Cdn$/GJ) Historical Forecast Remainder +1.5%/yr +1.5%/yr +1.5%/yr +1.5%/yr +1.5%/yr RESERVE LIFE INDEX The reserve life index of DeeThree has been calculated using 2015 estimated gross production volumes and gross proved and proved plus probable reserves using forecast prices and costs, all of which were taken from the December 31, Sproule reserves report. The reserve life index of the Company as at December 31,, on a boe basis, was 7.8 years for total proved reserves and 6.7 years for total proved plus probable reserves. Proved Plus Proved Probable Proved Expected Expected Proved Plus Plus Proved Probable Production Production Proved Probable Natural gas (mmcf) 55,677 77,412 6,488 20, Crude oil and NGLs (mbbls) 26,075 38,931 3,448 4, Total (mboe) 35,354 51,834 4,529 7, (years) (years)

21 DTX.TO 17 FINDING AND DEVELOPMENT COSTS AND RECYCLE RATIO The recycle ratio is a measure for evaluating the effectiveness of a company s re-investment program. The ratio measures the efficiency of capital investment, which is accomplished by comparing the operating netback per boe to that year s reserves finding and development (F&D) cost per boe. For the year ended December 31,, DeeThree s recycle ratio was 1.6 times on a proved basis and 2.1 times on a proved plus probable basis, while the Company achieved an average F&D cost, including future development costs, of $27.89 per boe on a proved basis and $21.51 per boe on a proved plus probable basis. The table below provides detailed calculations relating to F&D costs and recycle ratios for the Company s proved and proved plus probable reserves for the years ended December 31, and Years Ended December 31, 2013 Proved Reserves Capital expenditures ($000s) 296, ,885 Change in future capital ($000s) 71,640 73,146 Total capital costs ($000s) 368, ,031 Reserve additions (mboe) 13,203 14,549 F&D costs, excluding future development costs ($/boe) F&D costs, including future development costs ($/boe) Operating netback ($/boe) Recycle ratio Proved Plus Probable Reserves Capital expenditures ($000s) 296, ,885 Change in future capital ($000s) 59, ,543 Total capital costs ($000s) 356, ,428 Reserve additions (mboe) 16,554 21,847 F&D costs, excluding future development costs ($/boe) F&D costs, including future development costs ($/boe) Operating netback ($/boe) Recycle ratio (1) For a description of the boe conversion ratio, refer to the commentary at the end of the Management s Discussion and Analysis. (2) The aggregate of the exploration and development costs incurred in and 2013 and the change during the year in estimated future development costs may not reflect total F&D costs related to reserve additions for the year.

22 18 DTX.TO NET ASSET VALUE Years Ended December 31, 2013 (000s, except per share amounts) ($) ($) Present value of petroleum and natural gas reserves (1) 893, ,009 Net undeveloped land (2) 77,954 62,483 Working capital deficit (171,347) (77,586) Proceeds from stock options (3) 14,048 18,193 Net asset value 814, ,099 Diluted shares outstanding (#) (4) 93,137,688 76,779,805 Net asset value per share (1) Total proved plus probable, discounted at 10%, before tax per the Sproule December 31 reserves evaluations. (2) Based on a third-party evaluation as at December 31, and (3) Calculated proceeds from in-the-money options using a year-end closing common share price of $5.11 per share (2013 $9.57 per share). (4) Calculated as basic shares outstanding at December 31 plus in-the-money options.

23 DTX.TO 19 > MANAGEMENT S DISCUSSION AND ANALYSIS The following Management s Discussion and Analysis (MD&A) of the financial condition and results of operations for DeeThree Exploration Ltd. ( DeeThree or the Company ) is dated March 25, 2015 and should be read in conjunction with the Company s audited financial statements and related notes for the years ended December 31, and 2013 and with the MD&A and unaudited interim financial statements for the periods ended March 31,, June 30, and September 30,. All financial information is reported in Canadian dollars, unless otherwise noted. This MD&A contains additional measures under generally accepted accounting principles (GAAP), non-gaap measures and forward-looking statements. Readers are cautioned that the MD&A should be read in conjunction with the Company s disclosure under Non-GAAP Measures and Forward-looking Information and Statements included at the end of this MD&A. ABOUT DEETHREE EXPLORATION LTD. DeeThree is a Canadian company actively engaged in crude oil and natural gas exploration, development and production in key areas of the Western Canada Sedimentary Basin. DeeThree is focused on creating long-term shareholder value through a successful drilling program, growth-oriented field operations and prudent financial management. DeeThree s strategic platform for growth includes low-risk development and higher-risk exploration as well as strategic acquisitions. The Company has two core operating areas: the Brazeau area of west central Alberta, which features crude oil, natural gas and natural gas liquids (NGLs), and the Ferguson area of southern Alberta, which features Bakken oil and shallow natural gas. These two core areas have provided the Company with a balanced and diverse production base. The Company s experienced technical team has a proven track record of driving quarter-over-quarter organic growth with these assets. DeeThree commenced operations in 2007 as a private company focused on development and production of natural gas in southern Alberta. In late 2008, DeeThree completed its first significant acquisition from a major oil and natural gas producer comprised of properties in the Lethbridge area of southern Alberta, which became known as the Ferguson area. Ferguson was the Company s primary focus until late in the first quarter of 2011, when DeeThree closed a transformational acquisition of properties in the Brazeau and Peace River Arch areas. Since 2012, the Company has been successful in exploration and development activities in the Brazeau and Ferguson areas and continues to achieve growth in production, reserves and net asset value. DeeThree is headquartered in Calgary, Alberta and the common shares of DeeThree are listed for trading on the Toronto Stock Exchange under the symbol DTX and on the United States OTCQX under the symbol DTHRF. FINANCIAL AND OPERATING HIGHLIGHTS DeeThree s average annual production of 11,325 boe/d for reflects strong operating performance from existing wells in the Ferguson and Brazeau areas as well as strong production from new wells drilled during the year. For the year ended December 31,, DeeThree realized a combined average sales price of $73.38/boe, an 8 percent increase over the prior year. This was primarily due to increased market prices for crude oil for the majority of the

24 20 DTX.TO year. With average operating costs of $9.44/boe, transportation costs of $2.18/boe and average royalties of 23 percent, DeeThree achieved an operating netback of $45.16/boe, a 12 percent increase over the prior year. DeeThree incurred $296.5 million of capital expenditures in, with a capital program that focused on the drilling of 47 gross (46.93 net) wells, with 18 gross (18.0 net) in the Ferguson area, 28 gross (27.93 net) in the Brazeau area, and 1 gross (1.0 net) in the Peace River Arch area. The capital program also included approximately $22.6 million of minor acquisitions, $8.9 million on land and $31.0 million related to upgrading of existing facilities as well as facility and pipeline construction to handle the Company s growing production. During the year, DeeThree increased its proved plus probable reserves by 32 percent to 51.8 million boe (75 percent oil and NGLs) at December 31, from 39.4 million boe (77 percent oil and NGLs) in the prior year. DeeThree s reserve additions were predominately a result of the successful drilling program in the Company s Brazeau and Ferguson areas, which continue to demonstrate their high quality and generate strong returns through the Company s rapid pace of development. During, DeeThree issued a total of 5,714,200 common shares and 752,000 flow-through shares for net proceeds of approximately $69.4 million, and issued common shares on the exercise of options for $2.4 million, for total cash proceeds of $71.8 million. This allowed the Company to reduce debt and free up borrowing capacity, which was redrawn to fund the Company s capital program.

25 DTX.TO 21 FUNDS FROM OPERATIONS (1) Three Months Ended December 31, Year Ended December 31, ($000s) Net income 28,312 3,305 76,233 18,048 Non-cash items: Depletion and depreciation (D&D) expense 23,785 15,984 80,799 51,309 Deferred income tax expense 10,285 1,974 28,331 9,253 Share-based compensation (2) ,069 2,238 Accretion Unrealized loss (gain) on financial instruments (22,572) (524) (25,494) 3,074 Loss on disposition Exploration and evaluation (E&E) expense 859 3,160 9,318 8,876 Funds from operations (1) 41,773 24, ,196 93,295 (1) Funds from operations and funds from operations per share are not recognized measures under International Financial Reporting Standards (IFRS). Refer to Non-GAAP Measurements for further discussion. (2) The share-based compensation amount included in the calculation of funds from operations was adjusted for the non-cash portion related to certain field employees that was reclassified to operating expenses for presentation in the statement of operations and comprehensive income. During the three months ended December 31,, the Company generated funds from operations totalling $41.8 million ($0.47 per basic share and $0.46 per diluted share) compared to $24.7 million ($0.32 per basic share and $0.31 per diluted share) in the comparative period of 2013 and $52.7 million ($0.59 per basic share and $0.57 per diluted share) in the third quarter of. The year-over-year increase is primarily attributable to increased revenue, stemming from increased production and a higher realized price for the majority of the year. The quarter-over-quarter decrease reflects decreased revenue associated with decreased commodity prices, partially offset by lower operating and transportation costs. Funds from operations totalled $173.2 million ($2.01 per basic share and $1.95 per diluted share) for the year ended December 31, compared to $93.3 million ($1.23 per basic share and $1.18 per diluted share) recorded in NET INCOME For the three months ended December 31,, the Company recorded net income of $28.3 million ($0.32 per basic share and $0.31 per diluted share) compared to $3.3 million ($0.04 per basic and diluted share) in the same period of 2013 and net income of $21.1 million ($0.24 per basic share and $0.23 per diluted share) in the third quarter of. The Company s increased net income for the year was primarily due to the impact of unrealized mark-to-market gains recognized mostly in the fourth quarter of the year. The quarter-over-quarter increase was also primarily due to the impact of the unrealized and realized gains relating to the Company s mark-to-market assets and decreased E&E expense, partially offset by decreased revenue from lower commodity prices. Net income for the year ended December 31, was $76.2 million ($0.89 per basic share and $0.86 per diluted share) compared to $18.0 million ($0.24 per basic share and $0.23 per diluted share) in 2013.

26 22 DTX.TO FINANCIAL AND OPERATING RESULTS SALES VOLUMES Three Months Ended December 31, Year Ended December 31, Sales Natural gas (mcf/d) 16,510 10,251 13,823 9,881 Crude oil (bbls/d) 9,275 6,547 8,353 5,205 NGLs (bbls/d) Total sales (boe/d) 12,842 8,625 11,325 7,184 (%) (%) Production Split Natural gas Crude oil NGLs Total For the fourth quarter of, the Company s production averaged 12,842 boe/d compared to 8,625 boe/d in the same period of 2013 and 12,294 boe/d in the third quarter of. This represents a 49 percent year-over-year and a 4 percent quarter-over-quarter increase and reflects new production from the tie-in of wells drilled during. For the year ended December 31,, DeeThree s production averaged 11,325 boe/d compared to 7,184 boe/d in the previous year, representing a 58 percent increase. During, production was comprised of 13,823 mcf/d of gas, 8,353 bbls/d of crude oil and 668 bbls/d of NGLs, thereby increasing the Company s crude oil and NGL production to 80 percent of total corporate production from 77 percent a year earlier. REVENUE Three Months Ended December 31, Year Ended December 31, ($000s) Natural gas 5,833 3,777 23,848 12,347 Crude oil 61,530 46, , ,555 NGLs and other 2,594 1,341 11,973 6,089 Total oil and natural gas revenue 69,957 51, , ,991 During the three months ended December 31,, revenue increased by 35 percent to $70.0 million from $51.9 million in the comparative period of The year-over-year increase was a result of increased production. When compared to the third quarter of, revenue decreased by 20 percent to $70.0 million from $87.2 million due to decreased commodity prices. During, revenue totalled $303.3 million compared to $178.0 million a year earlier. Total revenue increased by 70 percent over 2013 primarily as a result of the increase in sales volumes as well as higher crude oil market prices for the year as a whole.

27 DTX.TO 23 Pricing for both the three and 12-month periods ended December 31, is discussed in further detail in Commodity Prices and Foreign Exchange below. COMMODITY PRICES AND FOREIGN EXCHANGE Three Months Ended December 31, Year Ended December 31, Benchmark Prices Crude oil WTI (US$/bbl) Edmonton Light (MSW) (Cdn$/boe) Differential MSW/WTI (US$/bbl) (6.36) (14.93) (7.17) (7.57) Hardisty Bow River (Cdn$/boe) Differential Bow River/WTI (US$/bbl) (13.65) (31.07) (18.95) (24.02) Natural gas NYMEX (US$/mmbtu) (1) AECO (Cdn$/GJ) (2) Average Realized Prices Natural gas ($/mcf) Crude oil ($/bbl) NGLs ($/bbl) Combined average ($/boe) Foreign Exchange Cdn$/US$ US$/Cdn$ (1) Mmbtu is the abbreviation for millions of British thermal units. One mcf of natural gas is approximately 1.02 mmbtu. (2) GJ is the abbreviation for gigajoule. One mcf of natural gas is approximately 1.05 GJ. CRUDE OIL PRICING The average realized price of DeeThree s crude oil was $72.11/bbl for the fourth quarter of compared to $77.62/bbl in the fourth quarter of 2013 and $91.60/bbl in the third quarter of. DeeThree s realized oil price decreased by 7 percent from the prior year s fourth quarter and by 21 percent from the third quarter of, due to a combination of a decrease in the US$ WTI benchmark oil price, offset by the change in the differentials and a weakened Canadian dollar. For the year ended December 31,, the Company s average realized crude oil price was $87.74/bbl compared to $83.98/bbl during 2013, a 4 percent increase driven by higher average benchmark prices and a weakened Canadian dollar. NATURAL GAS PRICING DeeThree receives a premium to the AECO gas index price due to the heat content of its sales gas. DeeThree s average realized natural gas price was $3.84/mcf in the fourth quarter of versus $4.00/mcf in the fourth quarter of 2013 and $4.39/mcf in the third quarter of. The Company s realized gas price decreased by 4 percent from the same period of 2013 and 13 percent from the third quarter of.