CONTENTS Highlights: By the Numbers 4 Letter to Shareholders 5 Operations Review 9 Management s Discussion and Analysis 19 Independent Auditors Report 43 Financial Statements 44 Notes to Financial Statements 48 Corporate Governance 75 Committees of the Board 76 Corporate Information IBC Abbreviations IBC Conversion of Units IBC Shareholders Meeting The Annual General Meeting of Shareholders of will be held on Friday, May 18, 2012 at 2:00 p.m. MDT in the Bow Glacier Room on the Third Floor of Centennial West Tower located at 250 Fifth Street S.W., Calgary, Alberta. All shareholders are cordially invited and encouraged to attend. To assure representation at the Meeting, those unable to attend are requested to complete the proxy form mailed with this and return it to Olympia Trust Company at their earliest convenience.
is an emerging Calgary based resource company actively engaged in natural gas and light crude oil exploration, development and production in key areas of the Western Canadian Sedimentary Basin. DeeThree commenced operations in 2007 as a private company focused on creating long-term shareholder value through prudent operational and financial management. DeeThree has created a platform for growth through a sound business strategy that includes low risk development, high impact exploration and strategic acquisitions. The Company has three core operating areas: the Peace River Arch area of northwestern Alberta as well as the Brazeau area of west central Alberta, which are prospective for natural gas, light crude oil and natural gas liquids, and the Lethbridge region of southern Alberta, which features shallow gas and prospective Bakken light oil, that have provided the Company with a balanced and diverse production base. Common shares of are listed for trading on the Toronto Stock Exchange under the symbol DTX and the United States OTCQX under the symbol DTHRF. HIGHLIGHTS: BY THE NUMBERS
($000s) ($000s) 12,500 2500 10,000 funds from operations funds from operations 11,833 2,345 2000 7,500 1500 5,000 2,500 1000 500 0 367 1,607 1,112 367 1,1121,689 2008 2009 2010 0 2008 2009 2010 page 1
DeeThree has made significant strides in its future growth program. During, we completed a strategic acquisition that has provided a more balanced and diverse production base, and as a result, we posted some impressive big numbers. 363% record revenue to up $ 32.7 million significant crude oil and liquids growth 698 bbls/d to up 4,006% page 2
506% expanded total production 1,860 boe/d 156% increased quality reserves 9,694 mboe page 3
Highlights: By the Numbers Years Ended December 31, 2010 Change (000s, except per share amounts) ($) ($) (%) Financial (1) Oil and natural gas revenues 32,747 7,073 363 Funds from operations (2) 11,833 1,689 601 Per share basic and diluted (2) 0.21 0.07 200 Cash flow from operating activities 7,100 1,729 311 Net loss (12,573) (15,070) 17 Per share basic and diluted (0.22) (0.65) 66 Capital expenditures (3) 187,557 22,275 742 Working capital (deficit) (4) (16,901) 28,505 (159) Shareholders equity 167,568 55,126 204 (000s) (#) (#) (%) Share Data At year-end 63,152 32,937 92 Weighted average basic and diluted 56,407 23,102 144 (%) Operating (5) Production Natural gas (mcf/d) 6,974 4,258 64 Crude oil (bbls/d) 561 16 3,406 NGLs (bbls/d) 137 1 13,600 Total (boe/d) 1,860 727 156 Average wellhead prices Natural gas ($/mcf) 3.71 4.26 (13) Crude oil and NGLs ($/bbl) 91.03 72.28 26 Total ($/boe) 48.23 26.65 81 Netbacks Operating netback ($/boe) 23.41 12.75 84 Funds flow netback ($/boe) (2) 17.35 6.36 173 Reserves Proved (mboe) 7,398 1,327 457 Proved plus probable (mboe) 9,694 1,599 506 Total net present value proved plus probable (10% discount, before tax) ($000s) 175,804 19,435 805 Undeveloped land Gross (acres) 284,780 226,035 26 Net (acres) 254,405 223,579 14 Gross (net) wells drilled Gas (#) 1 (1.0) 5 (5.0) (80) (-80) Oil (#) 15 (13.0) 2 (2.0) 650 (550) Standing (#) 1 (0.4) 1 (1.0) (-60) Dry and abandoned (#) 3 (3.0) 8 (8.0) (63) (-63) Total (#) 20 (17.4) 16 (16.0) 25 (9) Average working interest (%) 87 100 (13) (1) Amounts presented for the year ended December 31, 2010 have been restated for the effect of the adoption of International Financial Reporting Standards ( IFRS ). (2) Funds from operations, funds from operations per share and funds flow netback are not recognized measures under Canadian generally accepted accounting principles. Refer to the commentary in the Management s Discussion and Analysis under the heading Non-GAAP Measurements for further discussion. (3) Total capital expenditures, including acquisitions and excluding non-cash transactions. Refer to the commentary in the Management s Discussion and Analysis under the heading Capital Expenditures and Acquisitions for further information. (4) Current assets less current liabilities, excluding current derivative financial instruments. (5) For a description of the boe conversion ratio, refer to the commentary in the Management s Discussion and Analysis under the heading Other Measurements. page 4
LETTER TO SHAREHOLDERS
Letter to Shareholders In, was transformed from a predominantly natural gas based exploration company to a balanced and thriving oil and gas producer, taking significant steps to grow our Company from one core area with a 97% bias towards natural gas to three core operating areas with a more diversified portfolio at currently 54% natural gas, 46% light crude oil and liquids. ALBERTA BAKKEN Throughout, the Company employed a two-stage approach to exploring and delineating its 180,000-acre Alberta Bakken fairway. First, we mapped our entire Lethbridge acreage to determine the opportunities for resource potential. Second, we identified the areas that we felt had a higher geological or economical risk potential. As a result, we successfully farmed out two of these higher risk areas under two significant joint ventures, which brought in $9 million of capital to DeeThree and resulted in 2 gross (0.8 net) exploration wells being drilled on our lands. In the meantime, DeeThree pursued its own exploration prospects, drilling 4 gross (4.0 net) wells during the year. Although production results from the four wells were mixed, the program provided our Company with a much better understanding of this light oil play. Consequently, during the first three months of 2012, we successfully drilled an exploratory test well at a rate of approximately 550 bbls/d of 30 API reservoir oil,, the best results received from this area to date. Despite its limited production history, this well has discovered what we believe is a significantly high original oil in place ( OOIP ) resource play that spreads over the eastern portion of our Lethbridge land base. We will now take a much more targeted approach to drilling in 2012 as we attempt to advance the project from the exploration stage to the development stage. During, DeeThree effected a significant transformation from a predominantly natural gas based exploration company to a balanced and thriving oil and gas producer. A TRANSFORMATIONAL ACQUISITION To mitigate the higher risk of our Alberta Bakken project, our Company made the strategic decision in early to diversify our production base and fine-tune our focus on lower risk light crude oil production. As a result, in late March (and effective January 1, ), DeeThree acquired approximately 1,830 boe/d (40% light crude oil and NGLs) of primarily high working interest, operated production and reserves in the Peace River Arch area of northwestern Alberta and the Brazeau region of west central Alberta for cash consideration of approximately $125 million. This transaction met all of the critical components that we require from any strategic acquisition: predictable, low decline production; existing infrastructure; and, a significant land base with a large inventory of drilling prospects. Brazeau s Belly River play is the crown jewel of the acquisition. This low decline light oil production base provides the Company with significant cash flow and a high OOIP with low recovery factors from pre-existing vertical wells. We believe this play is an excellent candidate for developmental horizontal multi-stage fracturing techniques that could further increase the potential of this important new region. During, the Company successfully drilled 4 gross (3.6 net) horizontal wells, which essentially doubled area production to a exit rate of approximately 1,579 boe/d, exceeding our expectations. Consequently, we are planning an aggressive 2012 drilling program in page 5
By all operating and financial measures, DeeThree significantly outperformed 2010, while achieving record results. the Brazeau area that includes 8 gross (7.3 net) wells. This Belly River light oil property (42 API) with its existing operated infrastructure provides excellent netbacks and per well economics that will drive an increase in DeeThree s oil weighting, cash flow, reserves and production growth for the foreseeable future. ACCOMPLISHMENTS This is about our operating year, the numbers we posted and our prospects for continued growth. Clearly, our year-over-year results were excellent. By all operating and financial measures, DeeThree significantly outperformed 2010, while achieving record results. Our accomplishments for the year ended December 31, are outlined below. Drilled 20 gross (17.4 net) wells (87% success rate), including 4 gross (3.1 net) Montney wells in the Peace River Arch area, 4 gross (3.6 net) Belly River wells at Brazeau along with 6 gross (6.0 net) Sunburst wells and 6 gross (4.8 net) Bakken wells in the Lethbridge region. Achieved average annual production of 1,860 boe/d and a fourth quarter average of 2,403 boe/d, representing a 156% and 278% year-over-year increase, respectively. Improved product balance by increasing light crude oil and NGLs volumes to 46% of total fourth quarter production, up from 3% a year ago. Increased proved reserves 457% to 7,398 mboe and proved plus probable reserves 506% to 9,694 mboe, including an 8,119% increase in proved plus probable crude oil and NGLs reserves to 5,260 mboe. Improved net asset value 23% to $3.32 per share. Achieved F&D costs of $33.77/boe on proved reserves and $26.56/boe on proved plus probable reserves. Achieved operating netbacks of $23.41/boe, an 84% improvement, as a result of increased crude oil and NGLs production. Increased oil and natural gas revenues 363% to $32.7 million. Recorded a 601% improvement in funds from operations to $11.8 million or $0.21 per share. Entered the year with a $10 million credit facility, which increased to $50 million at year-end. Commenced trading on the OTCQX exchange (symbol: DTHRF) on November 22,. page 6
OUTLOOK Due to the recent success of the Company s Bakken drilling program and the completion of the $17.3 million flow-through financing announced on March 27, 2012, the Board of Directors has approved an increase to our 2012 capital expenditures budget to $82 million from $57 million. The capital spending increase will primarily target capitalizing on our Bakken success by drilling 11 gross (11.0 net) wells in the Lethbridge area throughout the year, thereby accelerating the pace of our exploration and development of this exciting resource play opportunity. In addition, we will continue with our plans to drill 8.0 gross (7.3 net) wells in the Brazeau area throughout 2012, keeping one rig in operation in the area. Consequently, 2012 exit production is expected to increase from the previously announced 4,300 boe/d (61% crude oil and NGLs) to approximately 5,000 boe/d (70% crude oil and NGLs). Year-end debt levels are forecast to be approximately $46 million on projected 2012 fourth quarter cash flow of approximately $14 million, representing an annualized debt to cash flow ratio of 0.8 at year-end. page 7
In summary, was truly a landmark year for DeeThree and a culmination of strategic planning and skilled execution. The successes we achieved are directly related to the quality and performance of our employees and consultants: I am grateful for their efforts and dedication. I also thank the members of DeeThree s Board of Directors for their commitment, sound corporate governance and wise counsel. Finally, I wish to thank our shareholders for your confidence and support. We are excited about the opportunities in our sights for 2012 and are focused on delivering another solid year of success. On behalf of the Board of Directors, Martin Cheyne President & Chief Executive Officer March 28, 2012 page 8
OPERATIONS REVIEW
to 23% net asset value $ 3.32 per share
Operations Review OVERVIEW During, DeeThree acquired a total of 1,890 boe/d of production, reserves and facilities in the Peace River Arch and Brazeau areas along with an impressive inventory of drilling opportunities. Consequently, we focused our operational efforts on drilling and delineating a variety of oil plays in our two new core operating areas as well as in the Lethbridge region. Milestones achieved in included: Drilling and completing four successful Belly River horizontal oil wells at Brazeau, and as a result, increased area oil production 100% by year-end. Finding and delineating the Lethbridge area s Sunburst oil play horizontally. Drilling and producing our first successful Alberta Bakken well. Increasing total corporate light crude oil and NGLs production from 6 bbls/d at December 31, 2010 to 698 bbls/d by the year-end. Throughout 2012, DeeThree will advance these exploration and development plays into the delineation and development stage. During this prolonged period of low natural gas prices, we will continue to focus on increasing oil production and cash flow from our development properties, while continuing to explore our large land base at Lethbridge for Alberta Bakken potential. Our three oil plays, combined with the extensive inventory of drilling opportunities on Company owned and operated lands, will provide steady growth for the foreseeable future. The Peace River Arch, Brazeau and Lethbridge areas are the cornerstones for DeeThree s future development. The expertise and knowledge that we have acquired in each core operating area will support our Company s future expansion and exploration initiatives. page 9
CORE OPERATING AREAS AT A GLANCE The acquisition completed during the year is highly strategic to our Company s future growth and complements our emerging Alberta Bakken light oil play, providing additional high quality resource plays along with a more balanced product portfolio. Peace River Arch Alberta Brazeau Edmonton Calgary Lethbridge page 10
Total Corporate Average Rate (1) 1,860 boe/d (38% oil and NGLs) Exit Rate 3,455 boe/d (54% oil and NGLs) Drilling Inventory 290 to 450 wells Undeveloped Land 254,405 net acres (89% working interest) 2012 Drilling Plans 23 wells 2012 Capital Expenditures $82 million (1) Total corporate average rate also includes 75 boe/d from non-core operating areas. Peace River Arch Average Rate 502 boe/d (21% oil and NGLs) Exit Rate 1,010 boe/d (23% oil and NGLs) Drilling Targets Montney and Doig oil Drilling Inventory 40 wells Undeveloped Land 33,848 net acres (60% working interest) Facilities Gas plant: 10.0 mmscf/d capacit (50% owned) Associated gas infrastructure Brazeau Average Rate 713 boe/d (68% oil and NGLs) Exit Rate 1,579 boe/d (77% oil and NGLs) Drilling Targets Belly River oil Drilling Inventory 150 to 250 wells Undeveloped Land 15,761 net acres (82% working interest) Facilities Oil battery: 4,000 bbls/d capacity, (80% owned and operated) Associated pipeline infrastructure 2012 Drilling Plans 8 wells 2012 Capital Expenditures 39% Lethbridge Average Rate 570 boe/d (16% oil) Exit Rate 865 boe/d (42% oil) Drilling Targets Bakken and Sunburst oil Drilling Inventory 100 to 200 wells Undeveloped Land 199,852 net acres (99% working interest) Facilities Gas plant: 7.0 mmcf/d capacity (100% working interest) Pipelines: over 300 kilometres Oil battery: 1,000 bbls/d capacity (100% working interest) 2012 Drilling Plans 15 wells (4 Sunburst, 11 Bakken) 2012 Capital Expenditures 52% page 11
Sales increased significantly in due primarily to the property acquisition at Peace River Arch and Brazeau. We will continue to build our drilling inventory in all areas of operation, yielding continued growth into 2012 and beyond. SALES SUMMARY Three Months Ended December 31, Years Ended December 31, 2010 2010 Natural gas (mcf/d) 7,714 3,691 6,974 4,258 Crude oil (bbls/d) 957 18 561 16 NGLs (bbls/d) 161 1 137 1 Total (boe/d) 2,403 635 1,860 727 The Company s sales, revenue and cash flow increased significantly in largely due to the property acquisition of primarily high working interest, operated crude oil, natural gas and NGLs production and reserves along with a higher average realized price per boe. DeeThree s average production for was 1,860 boe/d. DeeThree will continue to build its drilling inventory in all areas of operation, yielding continued growth into 2012 and beyond. LAND SUMMARY Undeveloped Developed Total Gross Net Gross Net Gross Net (acres) (acres) (acres) (acres) (acres) (acres) Peace River Arch 56,720 33,848 49,202 22,440 105,922 56,288 Brazeau 19,200 15,761 15,360 11,097 34,560 26,858 Lethbridge 202,300 199,852 62,348 61,201 264,648 261,053 Other 6,560 4,944 8,970 5,406 15,530 10,350 Total 284,780 254,405 135,880 100,144 420,660 354,549 2010 Lethbridge 223,635 222,051 26,240 25,534 249,875 247,585 Other 2,400 1,528 2,730 1,020 5,130 2,548 Total 226,035 223,579 28,970 26,554 255,005 250,133 As at December 31,, DeeThree controlled petroleum and natural gas leases covering 254,405 net acres of undeveloped land, a 14% increase from the 223,579 net acres held at the end of 2010. During, DeeThree invested $9,500,000 for the acquisition of 47,800 net acres of petroleum and natural gas rights in the Peace River Arch and Brazeau areas at an average cost of $200 per acre, $1,600,000 for the acquisition of 9,400 net acres of petroleum and natural gas rights in the Lethbridge area at an average cost of $167 per acre and $2,200,000 for the acquisition of 11,900 net acres of petroleum and natural gas rights in other areas at an average cost of $187 per acre. page 12
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 2010. 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 51-101 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, are 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 disclosures of boes may be misleading, particularly if used in isolation. 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: Natural Gas Crude Oil NGLs Total Gross Net Gross Net Gross Net Gross Net (mmcf) (mmcf) (mbbls) (mbbls) (mbbls) (mbbls) (mboe) (mboe) Proved Developed producing 16,278 14,490 2,115 1,786 347 234 5,176 4,434 Developed non-producing 1,438 1,135 1 241 190 Undeveloped 2,436 2,221 1,405 1,203 170 125 1,981 1,698 Total proved 20,152 17,846 3,521 2,988 518 359 7,398 6,322 Probable 6,447 5,617 1,088 865 133 88 2,296 1,889 Total proved plus probable 26,600 23,464 4,609 3,853 651 447 9,694 8,211 Note: Table may not be additive due to rounding. TOTAL PRODUCTION (boe/d) UNDEVELOPED LANDS (net acres) PROVED PLUS PROBABLE RESERVES (gross mboe) 2,000 1,500 1,000 500 0 108 558 727 1,860 2008 2009 2010 300,000 250,000 200,000 150,000 100,000 50,000 0 215,248 222,809 223,579 254,405 2008 2009 2010 10,000 8,000 6,000 4,000 2,000 0 1,178 2,060 1,599 9,694 2008 2009 2010 page 13
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. Before Income Taxes Discounted At 0% 5% 10% 15% 20% (000s) ($) ($) ($) ($) ($) Proved Developed producing 153,556 121,227 101,951 89,018 79,683 Developed non-producing 3,639 2,749 2,147 1,722 1,410 Undeveloped 61,616 44,288 32,668 24,473 18,456 Total proved 218,811 168,265 136,766 115,214 99,549 Probable 80,532 52,740 39,037 30,929 25,585 Total proved plus probable 299,343 221,005 175,804 146,143 125,134 Note: Table may not be additive due to rounding. 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: Natural Gas Crude Oil Proved Proved Plus Plus Proved Probable Probable Proved Probable Probable (mmcf) (mmcf) (mmcf) (mbbls) (mbbls) (mbbls) December 31, 2010 7,626 1,530 9,156 49 15 64 Acquisitions 14,246 4,041 18,288 3,400 621 4,021 Drilling extensions 912 506 1,418 60 305 365 Exploration Infill 141 60 200 239 159 397 Discoveries Technical 97 427 524 (22) (11) (33) Economic factors (324) (116) (440) Production (2,545) (2,545) (205) (205) December 31, 20,152 6,448 26,600 3,521 1,088 4,609 NGLs Total Proved Proved Plus Plus Proved Probable Probable Proved Probable Probable (mbbls) (mbbls) (mbbls) (mboe) (mboe) (mboe) December 31, 2010 1,320 270 1,590 Acquisitions 559 133 692 6,333 1,427 7,760 Drilling extensions 212 389 601 Exploration Infill 263 169 432 Discoveries Technical 9 9 3 60 64 Economic factors (54) (19) (74) Production (50) (50) (679) (679) December 31, 518 133 651 7,398 2,296 9,694 Note: Table may not be additive due to rounding. page 14
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: Future Net Revenue Well Before Operating Development Abandonment Income Revenue Royalties Costs Costs Costs Taxes (000s) ($) ($) ($) ($) ($) ($) Proved 2012 66,239 10,024 12,623 28,482 214 14,896 2013 69,173 10,348 13,801 11,156 71 33,797 2014 49,487 7,767 11,753 73 29,894 2015 44,258 8,336 10,707 77 25,138 2016 36,854 7,391 9,792 242 19,429 2017 30,795 5,644 8,830 284 16,037 2018 25,841 4,283 7,959 210 13,389 2019 21,745 3,323 7,304 289 10,829 2020 18,391 2,620 6,444 253 9,074 2021 15,810 2,103 5,872 216 7,619 2022 13,730 1,740 5,371 89 6,530 2023 12,093 1,477 4,986 186 5,444 Remainder 77,783 9,542 39,286 2,220 26,735 Total proved 482,199 74,598 144,728 39,638 4,425 218,811 Proved plus probable 2012 76,706 11,097 13,370 33,591 46 18,602 2013 81,521 12,953 15,037 11,156 10 42,365 2014 59,855 11,074 13,150 33 35,598 2015 54,133 11,229 12,089 239 30,576 2016 45,505 9,761 11,042 142 24,560 2017 38,771 7,545 10,266 239 20,721 2018 33,225 5,992 9,370 269 17,594 2019 28,853 4,777 8,778 61 15,237 2020 25,050 3,895 8,172 352 12,631 2021 21,973 3,244 7,565 113 11,051 2022 19,686 2,765 7,198 256 9,467 2023 16,829 2,265 6,338 220 8,006 Remainder 142,172 18,321 68,070 2,847 52,934 Total proved plus probable 644,279 104,918 190,445 44,747 4,826 299,343 Note: Table may not be additive due to rounding. page 15
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 2007 0.935 72.27 77.06 6.86 6.65 2008 0.943 99.59 102.85 9.04 8.15 2009 0.880 61.63 66.20 4.01 4.19 2010 0.971 79.43 77.81 4.39 4.16 1.012 95.00 95.16 4.04 3.72 Forecast 2012 1.012 98.07 96.87 3.55 3.16 2013 1.012 94.90 93.75 4.18 3.78 2014 1.012 92.00 90.89 4.54 4.13 2015 1.012 97.42 96.23 5.95 5.53 2016 1.012 99.37 98.16 6.07 5.65 2017 1.012 101.35 100.12 6.19 5.77 2018 1.012 103.38 102.12 6.32 5.89 2019 1.012 105.45 104.17 6.44 6.01 2020 1.012 107.56 106.25 6.57 6.14 2021 1.012 109.71 108.38 6.70 6.27 Remainder +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr +2.0%/yr RESERVE LIFE INDEX The reserve life index of DeeThree has been calculated using 2012 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 6.7 years for total proved reserves and 7.7 years for total proved plus probable reserves. Proved Plus Proved Probable Proved Expected Expected Proved Plus 2012 2012 Plus Proved Probable Production Production Proved Probable (years) (years) Natural gas (mmcf) 20,152 26,600 3,261 3,466 6.2 7.7 Crude oil and NGLs (mbbls) 4,039 5,260 556 673 7.3 7.8 Total (mboe) 7,398 9,694 1,100 1,251 6.7 7.7 page 16
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 0.7 times on a proved basis and 0.9 times on a proved plus probable basis, while the Company achieved an average F&D cost of $33.77/boe on a proved basis and $26.56/boe on a proved plus probable basis. In 2010, given the depressed natural gas prices, coupled with the Company s drilling results throughout the year, DeeThree recorded negative reserves additions, and as a result, is unable to calculate an F&D cost. Consequently, the Company has not presented F&D costs or recycle ratios for 2010. On a proved plus probable basis, our Company s recycle ratio was 0.9 times, while we achieved an average F&D cost of $26.56/boe. 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 year ended December 31,. Year Ended December 31, Proved Reserves Capital expenditures ($000s) 188,941 Change in future capital ($000s) 39,028 Total capital costs ($000s) 227,969 Reserves additions (mboe) 6,750 F&D costs, excluding future development costs ($/boe) 27.99 F&D costs, including future development costs ($/boe) 33.77 Operating netback ($/boe) 23.41 Recycle ratio 0.7 Proved Plus Probable Reserves Capital expenditures ($000s) 188,941 Change in future capital ($000s) 44,137 Total capital costs ($000s) 233,077 Reserves additions (mboe) 8,774 F&D costs, excluding future development costs ($/boe) 21.53 F&D costs, including future development costs ($/boe) 26.56 Operating netback ($/boe) 23.41 Recycle ratio 0.9 (1) For a description of the boe conversion ratio, refer to the commentary at the beginning of the Management s Discussion and Analysis. (2) The aggregate of the exploration and development costs incurred in and the change during the year in estimated future development costs may not reflect total F&D costs related to reserves additions for the year. page 17
NET ASSET VALUE Years Ended December 31, 2010 (000s, except per share amounts) ($) ($) Present value of petroleum and natural gas reserves (1) 175,804 19,435 Net undeveloped land (2) 51,846 41,900 Working capital (deficit) (16,901) 28,505 Proceeds from stock options (3) 1,596 4,251 Net asset value 212,345 94,091 Diluted shares outstanding (#) (4) 64,029,591 34,822,091 Net asset value per share 3.32 2.70 (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 2010. (3) Calculated proceeds from in-the-money options using a year-end closing common share price of $2.05 per share (2010 $4.30 per share). (4) Calculated as basic shares outstanding at December 31 plus in-the-money options. page 18
MANAGEMENT S DISCUSSION AND ANALYSIS
improved operating netback $ 23.41 to 84% per boe
Management s Discussion and Analysis The following Management s Discussion and Analysis ( MD&A ) of financial condition and results of operations for ( DeeThree or the Company ) is dated March 28, 2012 and should be read in conjunction with the Company s audited financial statements and related notes. The financial statements have been prepared in accordance with International Financial Reporting Standards ( IFRS ) as issued by the International Accounting Standards Board ( IASB ). Previously, the Company prepared its 2010 annual financial statements in accordance with Canadian generally accepted accounting principles ( previous GAAP ). The adoption of IFRS has not had an impact on the Company s operations or strategic decisions. In accordance with IFRS 1 First Time Adoption of International Financial Reporting Standards, DeeThree's transition date to IFRS was January 1, 2010, and therefore, the comparative information for 2010 has been prepared in accordance with the Company s IFRS accounting policies. The 2009 and 2008 financial information contained within this MD&A has been prepared following previous GAAP, and as allowed by IFRS 1, has not been restated for the effects of adopting IFRS. Certain amounts in prior years have been reclassified to conform to the current year s IFRS presentation format. NON-GAAP MEASUREMENTS This MD&A contains the terms funds from operations and funds from operations per share, which should not be considered an alternative to or more meaningful than cash flow from operating activities as determined in accordance with IFRS or previous GAAP. These terms do not have any standardized meaning as prescribed by IFRS or previous GAAP. DeeThree s determination of funds from operations and funds from operations per share may not be comparable to that reported by other companies. Management uses funds from operations to analyze operating performance and leverage, and considers funds from operations to be a key measure as it demonstrates the Company s ability to generate cash necessary to fund future capital investments and to repay debt, if applicable. Funds from operations is calculated using cash flow from operating activities as presented in the statement of cash flows before changes in non-cash working capital. DeeThree presents funds from operations per share whereby per share amounts are calculated using weighted average shares outstanding consistent with the calculation of earnings per share. The following table reconciles funds from operations to cash flow from operating activities, which is the most directly comparable measure calculated in accordance with IFRS: Three Months Ended December 31, Years Ended December 31, 2010 2010 (000s) ($) ($) ($) ($) Cash flow from operating activities 754 (23) 7,100 1,729 Changes in non-cash working capital 3,340 31 4,733 (40) Funds from operations 4,094 8 11,833 1,689 During the three months and year ended December 31,, the Company s funds from operations totaled $4,094,000 ($0.06 per basic and diluted share) and $11,833,000 ($0.21 per basic and diluted share), respectively, versus $8,000 ($nil per basic and diluted share) and $1,689,000 ($0.07 per basic and diluted share) in the respective periods of 2010. The Company considers corporate netbacks to be a key measure as they demonstrate DeeThree s profitability relative to current commodity prices. Corporate netbacks are comprised of operating, funds flow and net loss netbacks. Operating netback is calculated as the average sales price of its commodities and then subtracts royalties, operating costs and transportation expenses. Funds flow netback starts with the operating netback and further deducts general and administrative costs, finance expense and adds finance income as well as realized gains on financial instruments. To calculate the net loss netback, DeeThree takes the funds flow netback and deducts share-based compensation expense as well as depletion and depreciation charges, accretion expense, unrealized gains on financial instruments, any impairment or exploration and evaluation expense and deferred income taxes. There is no IFRS measure that is reasonably comparable to netbacks. See the section entitled Netbacks (per unit) for the netback calculations. Net debt and working capital (deficit), which represent current assets less current liabilities, excluding current derivative financial instruments, are used to assess efficiency, liquidity and the general financial strength of the Company. There is no IFRS measure that is reasonably comparable to net debt or working capital (deficit). OTHER MEASUREMENTS All dollar amounts are referenced in Canadian dollars. Where amounts are expressed on a barrel of oil equivalent ( boe ) basis, natural gas volumes have been converted to oil equivalence at 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, primarily applicable 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. Readers should be aware that historical results are not necessarily indicative of future performance. FORWARD-LOOKING STATEMENTS Certain statements contained in this MD&A may constitute forward-looking statements. These statements relate to future events or the Company s future performance. All statements other than statements of historical fact may be forward-looking statements. Forward-looking statements are often, but not always, identified by the use of words such as seek, anticipate, plan, continue, estimate, expect, may, will, project, predict, potential, targeting, intend, could, might, should, believe and similar expressions. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. The Company believes that the expectations reflected in those forward-looking statements are reasonable, but no assurance can be given that these expectations will prove to be correct and such forward-looking statements included in this MD&A should not be unduly relied upon by investors. These statements speak only as at the date of this MD&A and are expressly qualified, in their entirety, by this cautionary statement. In particular, this MD&A contains forward-looking statements pertaining to the following: projections of market prices and costs, supply and demand for natural gas and crude oil, the quantity of reserves, natural gas and crude oil production levels, capital expenditure programs, treatment under governmental regulatory and taxation regimes, and expectations regarding the Company s ability to raise capital and to continually add to reserves through acquisitions and development. page 19
With respect to forward-looking statements contained in this MD&A, the Company has made assumptions regarding, among other things, the legislative and regulatory environments of the jurisdictions where the Company carries on business or has operations, the impact of increasing competition and the Company s ability to obtain additional financing on satisfactory terms. The Company s actual results could differ materially from those anticipated in these forward-looking statements as a result of the risk factors included in this MD&A such as: volatility in the market prices for natural gas and crude oil; uncertainties associated with estimating reserves; geological, technical, drilling and processing problems; liabilities and risks, including environmental liabilities and risks inherent in natural gas and crude oil operations; incorrect assessments of the value of acquisitions; and, competition for, among other things, capital, acquisitions of reserves, undeveloped lands and skilled personnel. This forward-looking information represents the Company s views as at the date of this MD&A and such information should not be relied upon as representing its views as of any date subsequent to the date of this MD&A. DeeThree has attempted to identify important factors that could cause actual results, performance or achievements to vary from those current expectations or estimates expressed or implied by the forward-looking information. However, there may be other factors that cause results, performance or achievements not to be as expected or estimated and that could cause actual results, performance or achievements to differ materially from current expectations. There can be no assurance that forward-looking information will prove to be accurate, as results and future events could differ materially from those expected or estimated in such statements. Accordingly, readers should not place undue reliance on forward-looking information. The Company disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as expressly required by applicable securities legislation. DESCRIPTION OF THE COMPANY DeeThree is an emerging Calgary based resource company actively engaged in natural gas and light crude oil exploration, development and production in key areas of the Western Canadian Sedimentary Basin. DeeThree commenced operations in 2007 as a private company focused on creating long-term shareholder value through prudent operational and financial management. DeeThree has created a platform for growth through a sound business strategy that includes low risk development, high impact exploration and strategic acquisitions. The Company has three core operating areas: the Peace River Arch area of northwestern Alberta as well as the Brazeau area of west central Alberta, which are prospective for natural gas, light crude oil and natural gas liquids, and the Lethbridge region of southern Alberta, which features shallow gas and prospective Bakken light oil, that have provided the Company with a balanced and diverse production base. Common shares of DeeThree are listed for trading on the Toronto Stock Exchange under the symbol DTX and the United States OTCQX under the symbol DTHRF. In late 2008, DeeThree completed its first significant acquisition from a major oil and gas producer of properties in the Lethbridge area of southern Alberta (the Lethbridge property ). The Lethbridge property was the primary focus of the Company until late in the first quarter of when DeeThree closed a transformational acquisition of properties in the Peace River Arch and Brazeau areas of Alberta. See First Quarter Acquisition section for further information. First Quarter Acquisition On March 22, (and effective January 1, ), the Company acquired certain oil and gas assets principally located in the Peace River Arch area of northern Alberta and the Brazeau area of central Alberta (together, the property acquisition or acquired properties ) for total cash consideration of $123,185,000 after certain adjustments. This acquisition involved the purchase of approximately 1,830 boe/d (40% light crude oil and NGLs) of primarily high working interest, operated crude oil, natural gas and NGLs production and reserves. The property acquisition was accounted for as a business combination under IFRS 3 Business Combinations. Acquisition costs of $1,125,000 were charged to general and administrative ( G&A ) expense on the statement of income and comprehensive income. Second Quarter Transactions In April, the Company entered into a farm-out and joint venture agreement with a major oil and gas company (the farmee ). The terms of the agreement involved a four well commitment on a total of 15,815 acres of DeeThree s undeveloped lands that are strategically located in the Lethbridge area. The farmee was committed to drill four horizontal earning wells by December 31, and was responsible for 100% of the costs through completion to earn a 60% working interest in the farm-out lands with no payout terms. The farmee has elected to terminate the agreement after having drilled only one well of the four well commitment. A termination fee of $3,000,000 has been paid to DeeThree. The farmee earned a 60% working interest in the well and in 6.0 sections of the farm-out lands and has no right to earn additional interests in the farm-out lands. In June, the Company entered into a farm-out and joint venture agreement with a junior oil and gas company (the farmee ). The farmee paid DeeThree $5,000,000 and committed to drill and complete, at its sole risk and expense, two horizontal wells (the test wells ) evaluating the Mississippian and/or upper Devonian formations on 58 sections of land located in the northern portion of page 20
DeeThree s Lethbridge property approximately 40 miles north of recent drilling activity. The farmee was responsible for 100% of the costs of the test wells through completion to earn a 60% working interest in seven sections of farm-out lands (with no payout terms) for each well drilled. The test wells were to be drilled and completed prior to December 31,. After fulfilling the two test well obligation, the farmee had the right to elect to drill additional wells on similar terms and conditions until it had either elected to not drill an option well or had earned an interest in the balance of the 58 sections of land. Subsequent to year-end, the farmee elected not to drill the second test well, and as a result, has paid DeeThree a termination fee of $1,000,000 pursuant to the original agreement. Third Quarter Transactions In July (and effective June 1, ), the Company executed a purchase and sale agreement with a private oil and gas company pursuant to which DeeThree acquired producing assets and undeveloped land for cash consideration of $1,470,000 subject to certain adjustments. The Company purchased approximately 60 boe/d of crude oil and natural gas production primarily in the Brazeau area along with approximately 4,754 net acres of undeveloped land. Also in July, the Company executed a purchase and sale agreement with a small private oil and gas company whereby DeeThree issued 400,000 common shares out of treasury in exchange for approximately 12,800 net acres of undeveloped land located primarily in the Peace River Arch area of Alberta. Fourth Quarter Transactions There were no significant transactions during the fourth quarter of. FINANCIAL AND OPERATING RESULTS Sales Volumes Three Months Ended December 31, Years Ended December 31, 2010 2010 Sales Natural gas (mcf/d) 7,714 3,691 6,974 4,258 Crude oil (bbls/d) 957 18 561 16 NGLs (bbls/d) 161 1 137 1 Total sales (boe/d) 2,403 635 1,860 727 (%) (%) (%) (%) Production Split Natural gas 54 97 63 98 Crude oil 40 3 30 2 NGLs 6 7 Total 100 100 100 100 PRODUCTION SPLIT (%) 98 63 2 30 7 2010 Natural Gas Crude Oil NGLs page 21
For the fourth quarter of, the Company s production averaged 2,403 boe/d compared to 635 boe/d in the same period of 2010 and increased 13% from the 2,135 boe/d recorded in the third quarter of. The 278% year-over-year increase was primarily related to the property acquisition that closed on March 22, as well as bringing on new production from successful wells drilled during. For the year ended December 31,, DeeThree s production averaged 1,860 boe/d compared to 727 boe/d a year ago, representing a 156% increase. During, production was comprised of 6,974 mcf/d of natural gas, 561 bbls/d of crude oil and 137 bbls/d of NGLs, thereby increasing the Company s crude oil and NGLs production to 37% of total corporate production versus 2% a year ago. Revenue Three Months Ended December 31, Years Ended December 31, 2010 2010 (000s) ($) ($) ($) ($) Natural gas 2,439 1,353 9,454 6,614 Crude oil 8,287 119 19,221 428 NGLs 1,093 11 3,965 31 Royalty income 54 107 Total oil and natural gas revenue 11,873 1,483 32,747 7,073 During the three months ended December 31,, revenue increased 701% to $11,873,000 from $1,483,000 in 2010 and rose 26% from the $9,440,000 recorded in the third quarter of. The year-over-year increase was a result of the property acquisition (resulting in an increase in crude oil and NGLs production to 37% compared to 3% in the fourth quarter of 2010) along with additional production being brought on-stream from drills and higher realized prices for crude oil and NGLs, resulting in an increase in the corporate average price per boe. During the fourth quarter of 2010, the Company had fixed price physical contracts for future natural gas sales, which were included as part of natural gas revenue. There were no similar contracts in place during the fourth quarter of. During, revenue totaled $32,747,000 versus $7,073,000 a year ago. Total revenue increased 363% primarily as a result of the 156% year-over-year increase in sales volumes and the change in product mix to a heavier oil and NGL weighting. OIL AND NATURAL GAS REVENUE ($000s) AVERAGE SALES PRICE ($/boe) 35,000 30,000 25,000 20,000 15,000 10,000 5,000 0 1,649 5,018 7,073 32,747 2008 2009 2010 50 40 30 20 10 0 41.97 24.64 26.65 48.23 2008 2009 2010 page 22
Commodity Prices and Foreign Exchange Three Months Ended December 31, Years Ended December 31, 2010 2010 ($) ($) ($) ($) Benchmark Prices Natural gas NYMEX (US$/mmbtu) (1) 3.62 3.81 4.07 4.42 AECO (CDN$/GJ) (2) 3.01 3.58 3.43 3.95 Crude oil WTI (US$/bbl) 94.06 85.17 95.12 79.53 Edmonton light (CDN$/boe) 97.59 80.36 95.22 77.54 Average Realized Prices Natural gas ($/mcf) (3) 3.44 3.98 3.71 4.26 Crude oil ($/bbl) 94.17 70.11 94.37 72.81 NGLs ($/bbl) 73.73 84.30 77.35 65.84 Total sales price ($/boe) 53.70 25.38 48.23 26.65 Foreign Exchange CDN$/US$ 1.02 0.99 0.99 0.97 US$/CDN$ 0.98 1.01 1.01 1.03 (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 equal to 1.05 GJ. (3) Natural gas prices for the three months and year ended December 31, 2010 include realized gains/losses from physical fixed price contracts. The Company s financial results are significantly influenced by fluctuations in commodity prices, including price differentials and foreign exchange rates. The Company protects itself from fluctuations in prices by maintaining an appropriate hedging strategy. As at the date of this MD&A, DeeThree had six crude oil hedges in place (see Risk Management section below for details), five which were entered into during and one entered into subsequent to year-end. Most commodity prices are based on U.S. dollar benchmarks, which result in the Company s realized prices being influenced by the Canadian/U.S. exchange rates. The Company does not sell or transact in foreign currency, but may be impacted by foreign currency exchange rate changes related to commodity prices as outlined above. As at the date of this MD&A, DeeThree also had two foreign currency exchange risk management contracts in place to mitigate these risks (see Risk Management section below for contract details), both of which were entered into during. During the three-month period ended December 31,, benchmark natural gas prices in Canada fell 16% from the same period last year. In Canada, the benchmark index is the price set at the AECO hub, a major storage site near the TransCanada Energy pipeline exit point from Alberta at Empress. The benchmark index for United States natural gas prices is the market price as established by the New York Mercantile Exchange at Henry Hub ( NYMEX ), a major point of natural gas pipeline intersection in Louisiana. NYMEX is linked to AECO through transportation tariffs from the respective hubs to common markets and through foreign exchange rates. AECO prices averaged $3.01/GJ throughout the fourth quarter of compared to $3.58/GJ a year ago. DeeThree s average realized gas price during the three-month period was $3.44/mcf versus $3.98/mcf last year. During the fourth quarter of 2010, the Company s average realized gas price included approximately $0.39/mcf related to hedge contracts that were included as part of natural gas revenue. No similar contracts were in place during the three-month period. Oil prices remained relatively strong in the final quarter of with West Texas Intermediate ( WTI ) averaging $94.06/bbl compared to $85.17/bbl in the same period last year. The benchmark for crude oil prices in North America, and substantially globally, is WTI delivered to Cushing, Oklahoma, again as determined by the NYMEX. Canadian crude prices are based on refiner postings in Canadian dollars at Edmonton, Alberta, and as with natural gas, are linked to WTI through transportation tariffs to common markets and the foreign exchange rate. The average realized price of DeeThree s crude oil was $94.17/bbl for the fourth quarter of compared to $70.11/bbl a year ago, while NGLs averaged $73.73/bbl versus $84.30/bbl in 2010. During, DeeThree s average realized gas price was $3.71/mcf versus $4.26/mcf last year. During 2010, the Company s average realized gas price included approximately $0.34/mcf related to physical hedge contracts that were included as part of natural gas revenue. No similar contracts were in place during. The average realized price of the Company s crude oil was $94.37/bbl for the year compared to $72.81/bbl in 2010, while NGLs averaged $77.35/bbl versus $65.84/bbl a year ago. Information regarding the Company s risk management program can be found in the Business Risks and Risk Mitigation section of this MD&A. page 23