Petrus Resources Ltd.
Annual Report 2012

Plain-text annual report

3 Annual Report December 31, 2012 MANAGEMENT’S DISCUSSION & ANALYSIS Petrus Resources Ltd. (“Petrus” or the “Company”) is a private Canadian energy company focused on property exploitation, strategic acquisitions and risk-managed exploration in the Peace River and foothills areas of Alberta. Additional information relating to the Company, is available electronically on the Company’s website at www.petrusresources.com. The following is management’s discussion and analysis ("MD&A") of the financial and operating results of the Company as at and for the three and twelve month periods ended December 31, 2012. This MD&A should be read in conjunction with the audited financial statements for the year ended December 31, 2012 and other operating and financial information included in this report. Readers are directed to the advisories at the end of this report regarding forward-looking statements, BOE presentation and non-IFRS measures. The following MD&A is dated May 6, 2013. OVERVIEW Petrus is pleased to present the operating and financial results for the three and twelve months ended December 31, 2012, which marked the first full year of operations as first production occurred in November 2011. Petrus began the year with four employees and production of 1,282 boe per day (90% natural gas weighted) and ended the year with 13 employees and significantly higher liquids production, exiting 2012 at 2,835 boe per day, weighted 58% to natural gas. Production shifted from 100% non-operated to 50% operated over the same period. Petrus has positioned itself in two core areas (Peace River and the Alberta foothills). CORPORATE HIGHLIGHTS • Sales production for the fourth quarter averaged 2,735 boe/d (56% natural gas weighted), a 6% increase from 2,571 boe/d (60% natural gas weighted) reported in the third quarter of 2012. The increased volume is attributed to incremental production from successful light oil drilling. • New oil production and the decrease in gas weighting from the Peace River acquisition in June generated a 316% increase per share in oil and natural gas liquids production from the first quarter to the fourth quarter of 2012, driving strong growth in cash flow per share. The Company’s natural gas weighting decreased from 90% at the start of the year to 58% at the end of December, and production shifted from 100% non-operated to 50% operated over the same period. • Cash flow from operations was $6.3 million in the fourth quarter, a 40% increase from $4.5 million in the third quarter. In the first quarter of 2012, Petrus reported cash flow of $890 thousand ($0.03 per share). The Company’s operating netback increased from $10.77 per boe in the first quarter to $27.46 per boe in the fourth quarter (155% increase). • Operating costs (net of processing income) declined from $13.69 per boe in the third quarter to $7.94 in the fourth quarter due to increased fee recoveries generated on jointly owned facilities as well as lower unit operating costs attributed to new high rate Cardium oil wells brought on stream. The Company is continuously working to improve operational efficiencies, including the installation of facilities to reduce trucked water volumes in the Peace River area. • Over the twelve month period ended December 31, 2012, Petrus invested $112 million in exploration and acquisition activity which added production of 1,553 boe per day (weighted 69% to light oil), reserves of 5.5 mmboe on a proved plus probable (“P+P”) basis and $81.9 million of reserve value (NPV10). • • • • Petrus ended the year with reserves of 12.2 mmboe on a P+P basis and $150 million of reserve value (NPV10), replacing 796% of annual production at an all-in annual Finding, Development and Acquisition (“FD&A”) cost of $24.79 per boe including future development capital (“FDC”) for the proved plus probable category. Petrus continues to maintain a strong balance sheet. The Company ended the year with working capital of $2.8 million and an undrawn $40 million credit line to finance future growth. In 2012 Petrus acquired 132,671 net acres of land and currently has a significant inventory of oil and gas drilling locations in each of its core operating areas. The inventory of gas locations for development will significantly increase with improved natural gas prices. Petrus hired nine full time staff during the year, opened a field office in Beaverlodge, Alberta and contracted with 10 field consultants for the operation of its Peace River assets. Page | 1 SELECTED FINANCIAL INFORMATION (000s) except per boe amounts OPERATIONS Average Production Natural gas (mcf/d) Oil (bbl/d) NGLs (bbl/d) Total (boe/d) Natural gas production weighting Realized Sales Prices Natural gas ($/mcf) Oil ($/bbl) NGLs ($/bbl) Total ($/boe) Hedging gain (loss) ($/boe) Operating Netback Effective price ($/boe) Royalty exp (recovery) ($/boe) Operating expense ($/boe) (1) Transportation expense ($/boe) Operating netback ($/boe) FINANCIAL ($000s except per share) Oil and natural gas revenue Funds from operations Funds from operations per share Net income (loss) Net income (loss) per share Capital expenditures Acquisitions Wtd average shares (000s) As at quarter end ($000s) Working capital (deficit) Shareholder’s equity Total assets Twelve months ended Dec. 31, 2012 Twelve months ended Dec. 31, 2011(2) Three months ended Dec. 31, 2012 Sept. 30, 2012 June 30, 2012 Mar. 31, 2012 7,490 585 47 1,880 66% 2.61 79.07 61.16 36.53 0.82 37.35 5.03 10.32 1.18 20.82 25,474 12,513 0.20 431 0.01 52,159 59,630 61,377 2,793 145,782 181,976 6,988 88 35 1,288 90% 3.01 89.57 59.29 24.08 — 24.08 5.66 13.44 1.05 3.86 1,977 (204) (0.02) (871) (0.08) 2,334 41,979 10,616 7,491 50,179 59,140 9,128 1,139 75 2,735 56% 9,189 991 48 2,571 60% 3.49 76.31 64.08 45.19 (0.56) 44.63 7.22 7.94 1.10 28.37 2.38 80.55 64.33 40.76 1.14 41.90 6.88 13.69 1.28 20.05 5,219 139 15 1,024 85% 1.92 74.8 67.39 20.87 2.59 6,425 77 28 1,176 91% 2.22 104.97 57.52 20.38 1.80 23.46 (5.85) 13.51 1.50 14.30 22.18 4.90 5.66 0.85 10.77 11,468 6,268 0.07 551 0.01 21,457 — 86,276 9,742 4,502 0.05 1,352 0.02 14,471 432 86,124 2,011 505 0.02 (601) (0.02) 5,507 59,198 32,174 2,253 890 0.03 1,459 0.05 10,725 — 32,033 2,793 145,782 181,976 17,285 145,675 167,438 21,652 138,688 153,261 (2,241) 52,293 62,836 (1) Operating expenses are presented net of processing income and overhead recoveries. (2) The Company commenced first production November 1, 2011 and therefore prior year data is not relevant in most cases for comparison purposes. Page | 2 EXPLORATION AND DEVELOPMENT ACTIVITY UPDATE The year ended December 31, 2012 was active and transformational for Petrus. Over the year, Petrus deployed $112 million of total exploration and development capital which added production of 1,553 boe/d (weighted 69% light oil), proved plus probable (“P+P”) reserves(1) of 5.5 mmboe, reserve value(1) of $81.9 million (NPV10), and $12 million in seismic and undeveloped land (132,671 additional net acres). In 2011 Petrus was focused on acquiring a discounted natural gas asset to take advantage of depressed natural gas prices. The Company was successful and acquired a valuable foothills asset. Petrus enhanced shareholder value in 2012 by diversifying its asset base and focusing on light oil exploration activity. The Company successfully grew production, reducing its natural gas weighting by 37%. At December 31, 2011 Petrus’ operating netback was $3.86/boe. At the end of 2012 Petrus realized an operating netback of $28.37/boe. Petrus is currently focused on light oil in each of its core operating areas though it is poised to take advantage of improved natural gas prices given its diversified inventory of natural gas and light oil drilling locations. Throughout this report operating and financial information is presented for the comparative year however variance analysis is not presented. The Company commenced first production November 1, 2011 and therefore prior year data is not relevant in most cases for comparison purposes. Peace River In Peace River, the Company spud four (4.0 net) Montney oil wells in the fourth quarter. Oil or natural gas has been successfully tested in each of the wells. Upon completion of the total nine wells drilled, Petrus released its drilling rig as planned in order to evaluate the results of the 2012 drilling program. The 2013 capital program has been refined based on evaluation of the drilling results. Petrus will deploy up to $5 million in 2013 drilling vertical Montney wells targeting light oil (previously the company intended to drill horizontal wells). As a result, the capital cost per location will decrease significantly. Petrus will also deploy capital in 2013 on water disposal facilities to optimize operating costs as well as other facilities in order bring additional new production on stream. Alberta Foothills In the fourth quarter, Petrus spud four (3.1 net) Cardium wells targeting light oil in the foothills. In Brown Creek the first operated drill tested oil, the second liquids-rich natural gas. Given the timing of the operations, both locations were awaiting tie-in at year end. The wells confirm our confidence in the Brown Creek area where Petrus has access to a number of oil and gas drilling locations. Petrus plans to spend up to $10 million in 2013 in this area. Petrus participated in the drilling of two non-operated Cardium foothills wells in the fourth quarter, with an average working interest of 20 %. The wells came on stream in February 2013 with average light oil production of 400 bbl/d (gross). The Cordel drilling program has been very successful to date and Petrus realizes low operating costs on a per boe basis given the prolific nature of the wells. One well (14 % working interest) was brought on production in the fourth quarter with production of approximately 80 bbl/d (gross). 2013 Capital Budget The Petrus board has approved a $49.3 million capital budget for 2013, of which a portion has been spent to date in 2013. The capital program is expected to be evenly split between the Foothills and Peace River areas, and will be funded through cash flow, existing working capital and access to a $40 million credit facility (currently undrawn). (1) Working interest reserves as defined on page 9 of this MD&A. Page | 3 PRESIDENT’S MESSAGE AND OUTLOOK 2012 has been a very exciting journey for Petrus. We entered the year with a 93% gas weighting and much industry pessimism over the future of natural gas prices. Gas storage ended March at record levels due to a very warm winter and the rapid expansion of North American shale gas plays. Global economic uncertainties and the frustratingly slow economic recovery in North America further reduced capital availability for junior oil and gas companies. By April, early drilling results began to validate the light oil opportunities we had identified in the Foothills acquisition. With the asset market in Western Canada firmly favouring buyers, we were able to identify and finance an operated, oil-weighted acquisition at attractive metrics. The acquisition brought to us additional oil exploration and development opportunities and the associated financing provided additional financial flexibility and, more importantly, new key shareholders. By mid-summer, we had added several new staff, opened a field office in Beaverlodge and began to plan for an initial round of evaluation drilling on the new assets. The summer also proved that the best cure for low gas prices is low gas prices. Gas displacement of coal for power generation resulted in a very limp storage refill season and prices began to respond. Fortunately, a normal winter has followed and gas prices today are approximately $2.00 per GJ higher than we received this time last year ($3.50 vs. $1.50). Reduced gas drilling and the continuing economic recovery in North America bode well for gas prices to at least stabilize at a level where currently producing wells are economically viable. For Petrus, the fall and early winter saw significant continued success in the Foothills drilling program. By yearend, our gas weighting had fallen to almost 50% and sales volumes had more than doubled from 1,176 boe/d in Q1 to 2,735 boe/d in Q4. Over that same period, through a combination of increased oil weighting and reduced operating expenses, funds from operations increased over 6-fold to $25MM on an annualized basis. Although significant progress has been made, Petrus is still in its early stages. Much of the headway we made through 2012 will only begin to show tangible results later in 2013 and beyond. Western Canadian juniors continue to be starved for capital and the buyer’s market for assets continues. Oil and gas equity valuations have languished as many other sectors have pushed the DOW to record levels. We’ve seen this cycle before and believe that with the elimination of some of the uncertainty around hot-button issues like Keystone-XL, Northern Gateway, and Kinder-Morgan, capital will again begin to flow back into our sector. As money follows money, momentum will build and valuations will inevitably improve. The Energy business is extremely important to the Canadian economy and we are doing our small part to provide products essential to consumers. Equally, energy security is vital for North America and we believe that Canadians, industry and citizens as resource owners, have always been faithful partners in the advancement of energy security. I urge the provincial governments, the Canadian government, and their US counterparts to move forward with the projects necessary to ensure that this important engine of the North American economy can continue to provide high quality employment and tremendous economic benefit to our collective populations. I also encourage Petrus shareholders to actively participate in the political dialogue around these important issues. Petrus’ Annual General Meeting will be held at the Metropolitan Conference Centre, 333 – 4th Avenue SW, Calgary on Tuesday June 4th, 2013 at 9:00 a.m. (Calgary time). Kevin Adair President, CEO and Director Page | 4 FINANCIAL AND OPERATIONAL RESULTS OF OIL AND NATURAL GAS ACTIVITIES Twelve months ended Dec. 31, 2012 Twelve months ended Dec. 31, 2011(1) Three months ended Dec. 31, 2012 Sept. 30, 2012 June 30, 2012 Mar. 31, 2012 Quarterly average production Natural gas (mcf/d) Oil (bbl/d) NGLs (bbl/d) Total (boe/d) Total (boe) Exit production (boe/d) Exit gas weighting Revenue (000s) Natural Gas Oil NGLs Commodity revenue Royalty revenue Oil and natural gas revenue Average realized prices Natural gas ($/mcf) Oil ($/bbl) NGLs ($/bbl) Total ($/boe) Hedging gain (loss) Total realized ($/boe) Average benchmark prices Natural gas AECO (C$/mcf) Crude Oil Edm Lt. (C$/ bbl) Foreign Exchange US$/C$ 7,490 585 47 1,880 688,205 2,853 58% 7,157 16,930 1,052 25,139 335 25,474 2.61 79.07 61.16 36.53 0.82 37.35 6,988 88 35 1,288 78,574 1,282 90% 1,283 458 151 1,892 85 1,977 3.01 89.57 59.29 24.08 — 24.08 9,128 1,139 75 2,735 251,621 2,853 58% 9,189 991 48 2,571 236,406 2,682 57% 5,219 139 15 1,024 93,151 2,612 68% 6,425 77 28 1,176 107,027 1,152 91% 2,935 8,000 437 11,372 95 11,467 3.49 76.31 64.08 45.19 (0.56) 44.63 2,012 7,248 376 9,636 107 9,744 913 946 91 1,950 61 2,011 1,297 736 148 2,181 72 2,253 2.38 80.55 64.33 40.76 1.14 41.90 1.92 74.80 67.39 $20.93 2.59 23.52 2.22 104.97 57.52 $20.38 1.80 22.18 Dec. 31, 2012 Dec. 31, 2011(2) Dec. 31, 2012 Sept. 30, 2012 June 30, 2012 Mar. 31, 2012 Three months ended 2.29 87.41 1.00 3.04 97.59 1.02 3.05 82.85 1.01 2.14 84.79 1.01 1.85 84.38 0.99 2.11 97.62 0.99 (1) The Company commenced first production November 1, 2011 and therefore prior year data is not relevant in most cases for comparison purposes. PRODUCTION AND COMMODITY PRICES Exit production for 2012 was 2,835 boe/d, compared to third quarter exit production of 2,682 boe/d. The increase is due to incremental production related to the foothills drilling program. The production weighting was approximately 58% natural gas at December 31, 2012 (September 30, 2012 – 57%). During the three months ended December 31, 2012, the benchmark natural gas price in Canada (set at the AECO hub) increased by 43% from the prior quarter (average price of $3.05 per mcf in the fourth quarter compared to $2.14 per mcf in the prior quarter). The average realized gas price during the fourth quarter of 2012 was $3.49 per mcf compared to $2.38 per mcf in the prior quarter, which represents a 47% increase. Natural gas revenue for the fourth quarter of 2012 was $2.9 million and production of 839,776 mcf accounted for approximately 56% of fourth quarter production volume and 26% of total revenue (compared to $2 million and production of 845,121 mcf for 60% of production volume and 21% of total revenue in the prior quarter). Oil prices decreased slightly from the third quarter of 2012 to the fourth quarter. The West Texas Intermediate benchmark (WTI) averaged $82.85 per bbl for the fourth quarter of 2012 compared to an average price of $84.79 per bbl for the third quarter of 2012. As with natural gas, there can still be net price differentials due to differences in regional demand and transportation constraints which affect the actual prices received for the commodities. Petrus includes condensate in the oil revenue stream for reporting purposes. The average realized price of Petrus’ crude oil and condensate was $76.31 for the fourth quarter of 2012 compared to $80.55 per bbl for the third quarter of 2012. The oil and condensate revenue for the fourth quarter of 2012 was $8 million and production of 104,832 bbl accounted for approximately 42% of fourth quarter production volume and 70% of fourth quarter total revenue (compared to $7.3 million and production of 91,044 bbl for 39% of production volume and 76% of total revenue in the prior quarter). Page | 5 Petrus’ natural gas liquids (NGL) production mix consisted of ethane, butane, propane, pentane and sulphur. The pricing received for Petrus’ NGL production is based on the specific product being produced and can therefore vary from period to period depending on the production mix. In the fourth quarter of 2012, Petrus’ overall realized NGL price averaged $64.08 per bbl compared to $64.33/bbl in the prior quarter. The NGL revenue for the fourth quarter of 2012 was $437,103 and production of 6,822 bbl accounted for approximately 3% of the Company’s production volume and 4% of total revenue in the fourth quarter (compared to $289,996 and production of 4,508 boe for 2% of total production and 3% of total revenue for the prior quarter). FUNDS FROM OPERATIONS AND EARNINGS Funds from operations is commonly used in the oil and gas industry to analyze operating performance. Funds from operations as presented does not have any standardized meaning prescribed by IFRS. All references to funds from operations throughout this report are based on cash flow from operating activities as per the Statement of Cash Flows before changes in non-cash working capital and decommissioning obligations. Petrus generated funds from operations of $6.3 million during the quarter ended December 31, 2012 ($4.5 million during the third quarter of 2012). The increase of $1.8 million is due to increased production and oil weighting of existing assets. Other factors contributed to the improved quarterly cash flow including improved natural gas prices and lower operating expenses (net of processing income and recoveries). Net income decreased to $430,939 in the fourth quarter (compared to net income of $1.4 million in the prior quarter). The decreased net income is explained by year-end bonus accruals, depletion and share based compensation expenses as well as an unrealized hedging loss recognized in the fourth quarter. The following table provides detail on the Company’s funds from operations on a barrel of oil equivalent (“boe”) basis. Prior year information is not presented as the Company’s production began November 1, 2011 and prior quarter comparisons are not be meaningful. Twelve months ended Dec. 31, 2012 Dec. 31, 2012 Sept. 30, 2012 June 30, 2012 Mar. 31, 2012 Three months ended O&G revenue Transportation Net revenue Royalty expense Royalty income Net O&G revenue Operating exp (1) Hedging gain (loss) G&A expense Interest expense Funds from operations $000s 25,139 (811) 24,328 (3,465) 335 21,198 (7,103) 563 (1,885) (260) $/boe $000s $/boe $000s $/boe $000s $/boe $000s $/boe 36.53 (1.18) 35.35 (5.03) 0.49 30.80 (10.32) 0.82 (2.74) (0.38) 11,372 (277) 11,095 (1,818) 96 9,374 (1,998) (142) (546) (187) 45.19 (1.10) 44.09 (7.22) 0.38 37.25 (7.94) (0.56) (2.17) (1.02) 9,637 (303) 9,334 (1,626) 106 7,816 (3,236) 270 (379) 32 40.76 (1.28) 39.48 (6.88) 0.46 33.06 (13.69) 1.14 (1.60) 0.13 1,950 (140) 1,810 503 61 2,416 (1,259) 242 (658) (236) 20.87 (1.50) 19.37 5.85 0.72 25.94 (13.51) 2.59 (7.06) (2.54) 2,181 (91) 2,090 (524) 72 1,638 (607) 193 (348) 14 20.38 (0.85) 19.53 (4.90) 0.67 15.30 (5.66) 1.80 (3.25) 0.12 12,513 18.18 6,616 25.56 4,502 19.04 505 5.42 890 8.32 (1) Operating expenses are presented net of processing income and overhead recoveries. (000s) Funds from operations Funds from operations/share Net income (loss) Net income (loss)/share Common shares (000s) Wtd average shares (000s) Twelve months ended Dec. 31, 2012 Twelve months ended Dec. 31, 2011(1) Three months ended Dec. 31, 2012 Sept. 30, 2012 June 30, 2012 Mar. 31, 2012 12,513 0.20 431 0.01 86,276 61,377 (204) (0.02) (871) (0.08) 32,033 10,616 6,268 0.07 (706) (0.01) 86,276 86,276 4,502 0.05 1,738 0.02 86,276 86,124 505 0.02 (2,060) (0.06) 83,493 32,174 890 0.03 1,459 0.05 32,033 32,033 (1) The Company commenced first production November 1, 2011 and therefore prior year data is not relevant in most cases for comparison purposes. Page | 6 Crown Royalties Oil and NGLs (000s) % of production revenue Natural gas (000s) % of production revenue Total (000s) % of production revenue Twelve months ended Dec. 31, 2012 Twelve months ended Dec. 31, 2011(1) Three months ended Dec. 31, 2012 Sept. 30, 2012 June 30, 2012 3,465 20% — — 3,465 14% 192 32% 253 20% 445 24% 1,382 21% 436 15% 1,818 16% 1,486 19% 140 7% 1,626 17% 306 30% (809) (89%) (503) (26%) Mar. 31, 2012 291 33% 233 18% 524 24% (1) The Company commenced first production November 1, 2011 and therefore prior year data is not relevant in most cases for comparison purposes. Petrus’ overall effective crown royalty rate was 16% for the three months ended December 31, 2012 which is consistent with the prior quarter. The increase in oil and NGL royalties paid in the fourth quarter compared to the prior quarter relate to the acquired Peace River properties and successful drilling results which increased the Company’s oil production. Other Income (000s) Interest income Total other income Realized hedging gain (loss) Unrealized hedging gain (loss) Total gain (loss) on derivatives Twelve months ended Dec. 31, 2012 Twelve months ended Dec. 31, 2011(1) 90 90 563 (770) (207) 68 68 — — — Three months ended Dec. 31, 2012 Sept. 30, 2012 June 30, 2012 Mar. 31, 2012 48 48 (142) (2,327) (2,469) 25 25 270 855 1,125 — — 242 (975) (734) 17 17 194 1,677 1,871 (1) The Company commenced first production November 1, 2011 and therefore prior year data is not relevant in most cases for comparison purposes. Petrus enters into future financial derivative contracts to hedge against the risk of commodity price declines. Improvements in commodity prices resulted in a fourth quarter hedging loss of $142,000, but this was offset by increased production revenue from non- hedged barrels. The Company realized a hedging gain of $270,473 in the prior quarter of 2012. At December 31, 2012, Petrus recorded a risk management asset of $371,574 as well as a risk management liability of $1.1 million ($765,988 net), which represents the value of the future derivative contracts had they settled on that date. Operating Expenses (000s) Operating expense Processing revenue Operating expense, net Operating expense, net (per boe) Twelve months ended Dec. 31, 2012 Twelve months ended Dec. 31, 2011(1) 9,249 (2,146) 7,103 $10.32 1,139 (83) 1,056 $13.44 Three months ended Dec. 31, 2012 3,236 (1,238) 1,998 $7.94 Sept. 30, 2012 3,425 (189) 3,236 $13.69 June 30, 2012 Mar. 31, 2012 1,612 (349) 1,263 $13.55 976 (370) 606 $5.66 (1) The Company commenced first production November 1, 2011 and therefore prior year data is not relevant in most cases for comparison purposes. Operating expenses totalled $3.2 million for the fourth quarter of 2012 ($3.4 million for the three months ended September 30, 2012). Operating costs net of recoveries and processing income were $7.94 per boe for the fourth quarter, as compared to $13.69 per boe in the third quarter. The significant decrease in net operating costs is attributed in part to (i) increased production from prolific Stolberg wells (lower fixed operating costs on a per boe basis), (ii) higher operating recoveries as compared to the prior quarter, (iii) high turnaround costs incurred at jointly owned facilities in the third quarter which increased normal third quarter operating costs by $2.13/boe. Transportation Expenses (000s) Transportation expense $/boe Twelve months ended Dec. 31, 2012 Twelve months ended Dec. 31, 2011(1) 811 $1.18 87 $1.11 Three months ended Dec. 31, 2012 277 $1.10 Sept. 30, 2012 303 $1.28 June 30, 2012 140 $1.50 Mar. 31, 2012 91 $0.85 (1) The Company commenced first production November 1, 2011 and therefore prior year data is not relevant in most cases for comparison purposes. Petrus pays commodity and demand charges for transporting its gas on various pipeline systems. Transportation expenses totalled $277,109 or $1.10 per boe in the fourth quarter of 2012 ($303,354 or $1.28 per boe for the third quarter of 2012). Page | 7 G&A Expenses (000s) Gross G&A expense Capitalized G&A Net G&A expense Share based compensation, net Total G&A expense, net Twelve months ended Dec. 31, 2012 Twelve months ended Dec. 31, 2011(1) Dec. 31, 2012 2,829 (944) 1,885 1,099 2,984 768 (107) 661 23 684 966 (420) 546 323 869 Three months ended Sept. 30, 2012 521 (142) 379 377 756 June 30, 2012 Mar. 31, 2012 959 (347) 612 177 835 383 (35) 348 223 571 (1) The Company commenced first production November 1, 2011 and therefore prior year data is not relevant in most cases for comparison purposes. The fourth quarter general and administration (“G&A”) expenses, net of capitalized costs directly attributable to exploration and development totalled $868,545 or $3.45/boe (compared to $755,795 or $3.20/boe for the third quarter of 2012). The increase in G&A for the fourth quarter is attributed to executive and employee bonuses as well as professional fees incurred for year-end reporting requirements. Depletion and Depreciation (000s) Depletion Depreciation Total Depletion ($/boe) Depreciation ($/boe) Total ($/boe) Twelve months ended Dec. 31, 2012 7,630 459 8,089 $11.09 $0.67 $11.75 Twelve months ended Dec. 31, 2011(1) 618 9 627 $7.86 $0.11 $7.97 Three months ended Dec. 31, 2012 5,423 174 5,597 $21.55 $0.69 $22.24 Sept. 30, 2012 2,208 82 2,290 $9.34 $0.34 $9.68 June 30, 2012 739 84 823 $7.93 $0.90 $8.83 Mar. 31, 2012 783 119 902 $7.87 $0.11 $7.98 (1) The Company commenced first production November 1, 2011 and therefore prior year data is not relevant in most cases for comparison purposes. Depletion and depreciation expense is calculated on a unit-of-production basis. This fluctuates period to period primarily as a result of changes in the underlying proved plus probable reserve base and in the amount of costs subject to depletion and depreciation, including future development costs. Such costs are segregated and depleted on an area by area basis relative to the respective underlying proved plus probable reserve base. Petrus recorded depletion expense in the fourth quarter of 2012 of $5.4 million or $21.55 per boe (compared to $2.2 million or $9.34 per boe for the third quarter of 2012). The increase is attributed to the Peace River assets which were acquired at the end of the second quarter as well as capital spending in fourth quarter which was transferred to property plant and equipment which had achieved technical feasibility. For the quarter ended December 31, 2012, depreciation expense totalled $173,687 (compared to $82,331 in the prior quarter). Page | 8 CAPITAL EXPENDITURES AND ACQUISITIONS From December 31, 2011 Petrus spent $112 million which added production of 1,553 boe/d (weighted 69% light oil), proved plus probable (“P+P”) reserves of 5.5 mmboe, reserve value of $81.9 million (NPV10), and $12 million in seismic and undeveloped land (132,671 additional net acres). At December 31, 2012 the Company has a significant number of future drilling locations to satisfy its current organic growth strategy. Capital expenditures, excluding acquisitions, totalled $21.5 million in the fourth quarter of 2012 compared to $14.9 million in the prior quarter. The majority of funds were invested in drilling and completions (8 gross; 7.1 net) wells were drilled during the fourth quarter of 2012. During the third quarter, Petrus incurred $432,175 on post-closing adjustments related to its second quarter asset acquisition. The Company invested $1.2 million in the fourth quarter ($3.6 million in the prior quarter) on undeveloped land in its core operating areas to further add to its inventory of drilling locations. ($000s) Drill and complete Oil and gas equipment Geological Land and lease Office Capitalized G&A Total Acquisitions Total capital Gross (net) wells spud Twelve months ended Dec. 31, 2012 Twelve months ended Dec. 31, 2011 Dec. 31, 2012 Sept. 30, 2012 30-Jun-12 Mar. 31, 2012 Three months ended 39,650 3,147 787 5,680 980 1,915 52,159 59,630 111,789 23 (15) 1,228 — 571 203 215 117 2,334 41,979 44,313 2 (0.9) 16,578 2,569 19 1,174 374 742 21,457 — 21,457 10 (9.1) 9,166 188 710 3,609 280 518 14,471 432 14,903 5 (3.2) 4,389 320 — — 274 524 5,507 59,198 64,705 4 (1.1) 9,517 70 58 897 52 131 10,725 — 10,725 4 (1.6) RLI(4) 6.1 10.4 14.2 — — — RESERVES The following table provides a summary of the Company’s reserves, evaluated by GLJ Petroleum Consultants (“GLJ”): Working Interest(1) Reserves (MBoe) FD&A(2) RLI(3) (MBoe) FD&A(2) Reserves and Reserve Ratio Summary December 31, 2012 December 31, 2011 Proved Producing Total Proved Total Proved +Probable 5,084 7,584 12,171 $49.64 $42.90 $24.79 5.05 7.54 12.09 2,887 4,912 6,703 $14.94 $10.51 $8.19 Net Present Value ($000s) Discounted at 10% Proved Producing Total Proved Total Proved +Probable (1)Working Interest reserves refer to Company interest reserves less royalty interest reserves as defined in the GLJ report (2)FD&A (finding, development and acquisition) cost is defined as capital costs for the time period including change in future development capital divided by change in reserves including revisions and production for that same time period. (3)RLI (reserve life index) is defined as total reserves by category divided by the annualized Q4 2012 production. (4)RLI (reserve life index) is defined as total reserves by category divided by the annualized Nov and Dec, 2011 production. 71,336 90,923 149,484 38,665 51,968 67,542 — — — — — — — — — Reserves Summary In 2012 Petrus’ total working interest reserves increased 82% to 12.2 mmboe on a proved plus probable (“P+P”) basis and 54% on a total proved basis to 7.6 mmboe. The 5.5 mmboe net reserves addition in the working interest P+P category was accomplished at an all in finding, development and acquisition (“FD&A”) cost of $24.79 per boe including future development capital (“FDC”). Page | 9 LIQUIDITY AND CAPITAL RESOURCES As at December 31, 2012, the Company had a demand revolving credit facility of $40 million with a major Canadian lender. At December 31, 2012, the Company has a $180,000 letter of credit outstanding but has not drawn against the credit facility. The Company had working capital of $2.8 million (excluding non-cash items). The Company’s general capital management policy is to maintain a sufficient capital base in order to manage its business to enable the Company to increase the value of its assets and therefore its underlying share value. The Company’s objectives when managing capital are (i) to manage financial flexibility in order to preserve the Company’s ability to meet financial obligations; (ii) maintain a capital structure that allows Petrus the ability to finance its growth using internally generated cash flow and (iii) to maintain a flexible capital structure which optimizes the cost of capital at an acceptable risk level and provides an optimal return to equity holders. In the management of capital, Petrus includes share capital and total net debt, which is made up of debt and working capital (current assets less current liabilities). Petrus manages its capital structure and makes adjustments in light of economic conditions and the risk characteristics of the underlying assets. In order to maintain or adjust the capital structure, Petrus may issue new equity, increase or decrease debt, adjust capital expenditures and acquire or dispose of assets. Petrus anticipates that it will have adequate liquidity to fund future working capital and forecasted capital expenditures in 2013 through a combination of cash flow, current working capital and use of its credit facility. Petrus is able to modify its capital program in response to changes in commodity prices and cash flows. Should the Company choose to expand its capital program, actual funding alternatives will be influenced by the then current market environment and the ability to access capital on reasonable terms, balanced with the investment opportunities presented. Impairment Analysis Under International Accounting Standard (IAS) 36 – Impairment of Assets, impairment testing is performed at the cash generating unit (CGU) level and is a one step process for testing and measuring impairment of assets wherein each CGU’s carrying value is compared to the higher of “value in use” and “fair value less costs to sell.” Value in use is defined as the present value of future cash flows expected to be derived from the CGU. Impairment tests were performed at December 31, 2012 using future cash flows given a present value using a discount rate of 10%. For the Company’s cash generating units at December 31, 2012, no impairments were identified. Commitments The commitments for which the Company is responsible are as follows: Commitments (000s) Office equipment lease Capital commitments Corporate office lease Total Commitments Total < 1 year 1-5 years 16 5,400 1,506 6,922 5 5,400 502 5,907 11 — 1,004 1,015 Page | 10 ___________________________________________________________________________________________ Financial Reporting Update International Financial Reporting Standards (“IFRS”) Publicly accountable enterprises are required to apply IFRS, in full and without modification, for financial periods beginning on January 1, 2011. Private enterprises are not yet required to apply IFRS, however Petrus has elected to adopt the standards. Given that 2011 was Petrus’ first year of operations, Petrus had no financial statement balances to restate as at January 1, 2010. As a result, a reconciliation of Canadian GAAP to IFRS was not required. These financial statements present the Company’s financial results of operations issued under International Financial Reporting Standards (“IFRS”) as at and for the period ended December 31, 2012. These financial statements have been prepared by management using accounting policies consistent with IFRS as issued by the International Accounting Standards Board (“IASB”) and interpretations of the International Financial Reporting Interpretations Committee (“IFRIC”). Financial Instruments Financial instruments are comprised of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities. The fair values of cash and cash equivalents, accounts receivable, and accounts payable and accrued liabilities approximate their carrying amounts due to their short-term maturities. Disclosure Controls and Procedures Disclosure controls and procedures have been designed to ensure that information required to be disclosed by Petrus is accumulated and communicated to the Company’s management as appropriate to allow timely decisions regarding required disclosures. Petrus’ President and Chief Financial Officer have concluded that the Company’s disclosure controls and procedures are effective to provide reasonable assurance that material information related to Petrus, is made known to them by others within the Company. Internal Control over Financial Reporting (“ICFR”) Petrus’ President and Chief Financial Officer have designed internal controls over financial reporting related to the Company to provide reasonable assurance regarding the reliability of Petrus’ financial reporting and preparation of financial statements for external purposes in accordance with GAAP. It should be noted that while Petrus’ President and Chief Financial Officer believe that the Company’s disclosure and internal control procedures provide a reasonable level of assurance that they are effective, they do not expect that the disclosure and internal control procedures will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. ADVISORIES Basis of Presentation Financial data presented below have largely been derived from the Company’s financial statement, prepared in accordance with International Financial Reporting Standards (“IFRS”). Accounting policies adopted by the Company are set out in Note 3 to the financial statements. The reporting and the measurement currency is the Canadian dollar. All financial information is expressed in Canadian dollars, unless otherwise stated. Forward Looking Statements Certain information regarding Petrus set forth in this document, including management’s assessment of the Company’s future plans and operations, contains forward-looking statements WITHIN THE MEANING OF APPLICABLE SECURITIES LAW, that involve substantial known and unknown risks and uncertainties. The use of any of the words “anticipate”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “should”, “believe” and similar expressions are intended to identify forward- looking statements. Such statements represent Petrus’ internal projections, estimates or beliefs concerning, among other things, an outlook on the estimated amounts and timing of capital investment, anticipated future debt, production, revenues or other expectations, beliefs, plans, objectives, assumptions, intentions or statements about future events or performance. These statements are only predictions and actual events or results may differ materially. Although Petrus believes that the expectations reflected in the forward-looking statements are reasonable, it cannot guarantee future results, levels of activity, performance or achievement since such expectations are inherently subject to significant business, economic, competitive, political and social uncertainties and contingencies. Many factors could cause Petrus’ actual results to differ materially from those expressed or implied in any forward-looking statements made by, or on behalf of, Petrus. In particular, forward-looking statements included in this MD&A include, but are not limited to, statements with respect to: the size of, and future net revenues from, crude oil, NGL (natural gas liquids) and natural gas reserves; future prospects; the focus of and timing of capital expenditures; expectations regarding the ability to raise capital and to continually add to reserves through acquisitions and development; access to debt and equity markets; projections of market prices and costs; the performance characteristics of the Company’s crude oil, NGL and natural gas properties; crude oil, NGL and natural gas production levels and product mix; Petrus’ future operating and financial results; capital investment programs; supply and demand for crude oil, NGL and natural gas; future royalty rates; drilling, development and completion plans and the results therefrom; future land expiries; dispositions and joint venture arrangements; amount of operating, transportation and general and administrative expenses; treatment under governmental regulatory regimes and tax laws; estimated tax pool balances and anticipated IFRS elections and the impact of the conversion to IFRS. In addition, statements relating to “reserves” are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described can be profitably produced in the future. Page | 11 These forward-looking statements are subject to numerous risks and uncertainties, most of which are beyond the Company’s control, including the impact of general economic conditions; volatility in market prices for crude oil, NGL and natural gas; industry conditions; currency fluctuation; imprecision of reserve estimates; liabilities inherent in crude oil and natural gas operations; environmental risks; incorrect assessments of the value of acquisitions and exploration and development programs; competition; the lack of availability of qualified personnel or management; changes in income tax laws or changes in tax laws and incentive programs relating to the oil and gas industry; hazards such as fire, explosion, blowouts, cratering, and spills, each of which could result in substantial damage to wells, production facilities, other property and the environment or in personal injury; stock market volatility; ability to access sufficient capital from internal and external sources; completion of the financing on the timing planned and the receipt of applicable approvals; and the other risks. With respect to forward-looking statements contained in this MD&A, Petrus has made assumptions regarding: future commodity prices and royalty regimes; availability of skilled labour; timing and amount of capital expenditures; future exchange rates; the impact of increasing competition; conditions in general economic and financial markets; availability of drilling and related equipment and services; effects of regulation by governmental agencies; and future operating costs. Management has included the above summary of assumptions and risks related to forward-looking information provided in this MD&A in order to provide shareholders with a more complete perspective on Petrus’ future operations and such information may not be appropriate for other purposes. Petrus’ actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward- looking statements will transpire or occur, or if any of them do so, what benefits that the Company will derive therefrom. Readers are cautioned that the foregoing lists of factors are not exhaustive. These forward-looking statements are made as of the date of this MD&A and the Company disclaims any intent or obligation to update any forward-looking statements, whether as a result of new information, future events or results or otherwise, other than as required by applicable securities laws. BOE Presentation The oil and natural gas industry commonly expresses production volumes and reserves on a barrel of oil equivalent (“BOE”) basis whereby natural gas volumes are converted at the ratio of six thousand cubic feet to one barrel of oil. The intention is to sum oil and natural gas measurement units into one basis for improved measurement of results and comparisons with other industry participants. Petrus uses the 6:1 BOE measure which is the approximate energy equivalency of the two commodities at the burner tip. However, BOE’s do not represent an economic value equivalency at the wellhead and therefore may be a misleading measure if used in isolation. Abbreviations 000’s bbl bbl/d bcf boe/d CAD GJ GJ/d mbbls mboe mcf mcf/d mmbbls mmboe mmcf mmcf/d NGLs USD WTI thousand dollars barrel barrels per day billion cubic feet barrel of oil equivalent per day Canadian dollar gigajoule gigajoules per day thousand barrels thousand barrels of oil equivalent thousand cubic feet thousand cubic feet per day million barrels millions of barrels of oil equivalent million cubic feet million cubic feet per day natural gas liquids United States dollar West Texas Intermediate Page | 12 INDEPENDENT AUDITORS’ REPORT To the Shareholders of Petrus Resources Ltd.: We have audited the accompanying financial statements of Petrus Resources Ltd., which comprise the balance sheet as at December 31, 2012, and the statements of net income (loss) and comprehensive income (loss), changes in shareholders’ equity and cash flows for the year then ended and a summary of significant accounting policies and other explanatory information. Management's responsibility for the financial statements Management is responsible for the preparation and fair presentation of these financial statements in accordance with International Financial Reporting Standards, and for such internal control as management determines is necessary to enable the preparation of financial statements that are free from material misstatement, whether due to fraud or error. Auditors’ responsibility Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit in accordance with Canadian generally accepted auditing standards. Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement. An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditors’ judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditors consider internal control relevant to the entity's preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity's internal control. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that the audit evidence we have obtained in our audit is sufficient and appropriate to provide a basis for our audit opinion. Opinion In our opinion, the financial statements present fairly, in all material respects, the balance sheet of Petrus Resources Ltd. as at December 31, 2012 and its financial performance and its cash flows for the year then ended in accordance with International Financial Reporting Standards. Chartered accountants Calgary, Canada May 6, 2013 Page | 13 BALANCE SHEETS (AUDITED) (Expressed in Canadian dollars) As at ASSETS Current Cash and cash equivalents (note 5) Deposits and prepaid expenses Accounts receivable (note 15) Risk management asset (note 11) Non-current Exploration and evaluation assets (notes 6 and 7) Property, plant and equipment (notes 6 and 8) LIABILITIES AND SHAREHOLDER’S EQUITY Current Accounts payable and accrued liabilities Flow-through share premium liability Risk management liability (note 11) Non-Current Decommissioning obligation (note 10) Deferred income tax liability (note 16) Shareholders’ Equity Share capital (note 12) Contributed surplus Deficit See accompanying notes to the financial statements Commitments (note 21) Approved by the Board of Directors, (signed) “Don T. Gray” Don T. Gray Executive Chairman December 31, 2012 December 31, 2011 11,589,033 589,566 11,649,891 371,574 24,200,064 45,790,854 111,985,145 157,775,999 181,976,063 21,002,078 — 1,137,562 22,139,640 12,395,714 1,658,369 36,193,723 144,119,128 2,103,466 (440,254) 145,782,340 7,786,788 396,657 3,635,358 — 11,818,803 7,232,470 40,089,044 47,321,514 59,140,317 4,328,105 979,856 — 5,307,961 3,652,999 — 8,960,960 51,018,159 32,391 (871,193) 50,179,357 181,976,063 59,140,317 (signed) “Patrick Arnell” Patrick Arnell Director Page | 14 STATEMENTS OF NET INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS) (AUDITED) (Expressed in Canadian dollars, except for share information) REVENUE Oil and natural gas revenue Royalty expense Oil and natural gas revenue, net of royalties Other income Gain (loss) on financial derivatives (note 11) EXPENSES Operating (note 18) Transportation expenses General and administrative (note 19) Share-based compensation (notes 12 and 19) Finance (note 13) Exploration and evaluation expense (note 7) Depletion and depreciation (note 8) NET INCOME (LOSS) BEFORE INCOME TAXES Current tax expense Deferred income tax expense (note 16) TOTAL NET INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS) Net income (loss) per common share Basic and diluted See accompanying notes to the financial statements Year ended December 31, 2012 Inception to December 31, 2011 25,473,691 3,464,880 22,008,811 90,116 (206,662) 21,892,265 7,102,809 811,190 1,885,007 1,099,242 517,667 420,000 8,088,689 19,924,604 1,967,661 2,660 1,534,062 1,536,722 1,976,817 444,757 1,532,060 68,031 — 1,600,091 1,055,975 87,302 660,640 22,674 17,960 626,733 2,554,176 (871,193) — — 430,939 (871,193) 0.01 (0.08) Page | 15 STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY (AUDITED) (Expressed in Canadian dollars) Balance at inception Net loss Issuance of common shares Premium liability of flow-through shares Share-based compensation expensed Share-based compensation capitalized Share issue costs Tax benefit of share issue costs Deferred tax benefits Balance, December 31, 2011 Net income Issuance of common shares (note 12) Premium liability of flow-through shares Share-based compensation expensed Share-based compensation capitalized Share issue costs Tax benefit of share issue costs Deferred tax benefits Balance, December 31, 2012 See accompanying notes to the financial statements Share Capital Contributed Surplus Retained Earnings (Deficit) — — 54,204,418 (1,188,386) — — (2,206,403) 584,697 (376,167) 51,018,159 — 95,160,000 (215,422) — — (2,914,580) 876,400 194,570 144,119,128 — — — — 22,674 9,717 — — — 32,391 — — — 1,099,242 971,834 — — — 2,103,466 — (871,193) — — — — — — — (871,193) 430,939 — — — — — — — (440,254) Total — (871,193) 54,204,418 (1,188,386) 22,674 9,717 (2,206,403) 584,697 (376,167) 50,179,357 430,939 95,160,000 (215,422) 1,099,242 971,834 (2,914,580) 876,400 194,570 145,782,340 Page | 16 STATEMENTS OF CASH FLOWS (AUDITED) (Expressed in Canadian dollars) Funds generated by (used in): OPERATING ACTIVITIES Net income (loss) Adjust items not affecting cash: Share-based compensation Unrealized hedging losses (note 11) Finance expenses (note 13) Exploration and evaluation expense (note 7) Depletion and depreciation (note 8) Deferred income tax recovery (note 16) Change in operating non-cash working capital (note 17) Funds generated by operations FINANCING ACTIVITIES Issuance of common shares (note 12) Share issue costs (note 12) Bridge financing issuances Bridge financing repayments Change in financing non-cash working capital (note 17) Funds generated by financing activities INVESTING ACTIVITIES Property and equipment acquisitions (note 6) Exploration and evaluation asset expenditures (note 7) Petroleum and natural gas property expenditures (note 8) Other capital expenditures (note 8) Change in investing non-cash working capital (note 17) Funds used in investing activities Increase in cash and cash equivalents Cash and cash equivalents, beginning of year Cash and cash equivalents, end of year Cash interest paid Cash taxes paid See accompanying notes to the financial statements Year ended December 31, 2012 Inception to December 31, 2011 430,939 (871,193) 1,099,242 769,888 170,035 420,000 8,088,689 1,534,062 12,512,856 (7,441,454) 5,071,402 95,160,000 (2,914,580) — — (979,856) 91,265,564 (59,586,195) (16,979,120) (31,539,972) (765,295) 16,673,973 (92,534,721) 3,802,245 7,786,788 11,589,033 280,189 2,660 22,674 — 17,960 — 626,733 — (203,826) (635,422) (839,248) 49,200,418 (2,206,403) 12,000,000 (6,996,000) 160,037 52,158,052 (41,979,444) (1,856,926) (252,472) (214,649) 771,475 (43,532,016) 7,786,788 — 7,786,788 — — Page | 17 NOTES TO THE FINANCIAL STATEMENTS 1. NATURE OF THE ORGANIZATION Petrus Resources Ltd. (“Petrus” or the “Company”) is a privately held entity which was incorporated under the laws of the Province of Alberta on December 13, 2010. These financial statements report the twelve months ended December 31, 2012 and were approved by the Company’s Audit Committee May 6, 2013. The principal undertaking of Petrus is the investment in energy business-related assets. The operations of the Company consist of the acquisition, development, exploration and exploitation of these assets. It conducts many of its activities jointly with others. These financial statements reflect only the Company’s share of these jointly controlled assets and its proportionate share of the relevant revenue and related costs. The Company’s head office is located at 2400, 240 – 4th Avenue SW, Calgary, Alberta Canada. 2. BASIS OF PRESENTATION (a) Statement of Compliance These financial statements have been prepared by management using accounting policies have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”) and interpretations of the International Financial Reporting Interpretations Committee (“IFRIC”). (b) Measurement Basis These financial statements were prepared on the basis of historical cost and are presented in Canadian dollars. (c) Critical Accounting Estimates and Sources of Judgment The timely preparation of financial statements in conformity with IFRS requires management to make judgments, estimates and assumptions that affect the application of accounting policies and reported amounts of assets and liabilities and income and expenses. Accordingly, actual results may differ from these estimates. Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the period in which the estimates are revised and in any future periods affected. Significant estimates and judgments made by management in the preparation of the financial statements are outlined below. Depletion and reserve estimates Petroleum and natural gas assets are depleted on a unit of production basis at a rate calculated by reference to proved and probable reserves determined in accordance with National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). The calculation incorporates the estimated future cost of developing and extracting those reserves. Proved and probable reserves are estimated using independent reservoir engineering reports and represent the estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be recoverable in future years from known reservoirs and which are considered commercially producible. Reserves estimates, although not reported as part of the Company’s financial statements, can have a significant effect on net income (loss), assets and liabilities as a result of their impact on depletion and depreciation, decommissioning liabilities, deferred taxes, asset impairments and business combinations. Independent reservoir engineers perform evaluations of the Company’s petroleum and natural gas reserves on an annual basis. The estimation of reserves is an inherently complex process requiring significant judgment. Estimates of economically recoverable petroleum and natural gas reserves are based upon a number of variables and assumptions such as geoscientific interpretation, production forecasts, commodity prices, costs and related future cash flows, all of which may vary considerably from actual results. These estimates are expected to be revised upward or downward over time, as additional information such as reservoir performance becomes available or as economic conditions change. Impairment indicators and cash-generating units For purposes of impairment testing, petroleum and natural gas assets are aggregated into cash-generating units (“CGU’s”), based on separately identifiable and largely independent cash inflows. The determination of the Company’s CGU’s is subject to judgment. The recoverable amounts of CGU’s and individual assets have been determined based on the higher of the value-in-use calculations and fair values less costs to sell. These calculations require the use of estimates and assumptions, including the discount rate, future petroleum and natural gas prices, expected production volumes and anticipated recoverable quantities of proved and probable reserves. These assumptions are subject to change as new information becomes available and changes in economic conditions take place. Changes may impact the estimated life of the field and economical reserves recoverable and may require a material adjustment to the carrying value of petroleum and natural gas assets. The Company monitors internal and external indicators of impairment relating to its tangible assets. Technical feasibility and commercial viability of exploration and evaluation assets The determination of technical feasibility and commercial viability, based on the presence of proved and probable reserves, results in the transfer of assets from exploration and evaluation assets to property, plant and equipment. As discussed above, the estimate of proved and probable reserves is inherently complex and requires significant judgment. Thus any material change to reserve estimates could affect the technical feasibility and commercial viability of the underlying assets. Page | 18 Decommissioning obligation At the end of the operating life of the Company’s facilities and properties and upon retirement of its petroleum and natural gas assets, decommissioning costs will be incurred by the Company. This requires judgment regarding abandonment date, future environmental and regulatory legislation, the extent of reclamation activities, the engineering methodology for estimating cost, future removal technologies in determining the removal cost and discount rates to determine the present value of these cash flows. Income taxes Tax provisions are based on enacted or substantively enacted laws. Changes in those laws could affect amounts recognized in income or loss both in the period of change, which would include any impact on cumulative provisions, and in future periods. Deferred tax assets (if any) are recognized only to the extent it is considered probable that those assets will be recoverable. This involves an assessment of when those deferred tax assets are likely to reverse and a judgment as to whether or not there will be sufficient taxable income available to offset the tax assets when they do reverse. This requires assumptions regarding future profitability and is therefore inherently uncertain. To the extent assumptions regarding future profitability change, there can be an increase or decrease in the amounts recognized in respect of deferred tax assets as well as the amounts recognized in income or loss in the period in which the change occurs. Additionally, future changes in tax laws in the jurisdictions in which the Company operates could limit the ability of the Company to obtain tax deductions in future periods. Measurement of share-based compensation Share-based compensation recorded pursuant to share-based compensation plans are subject to estimated fair values, forfeiture rates and the future attainment of performance criteria. Business combinations Business combinations are accounted for using the acquisition method of accounting. The determination of fair value often requires management to make assumptions and estimates about future events. The assumptions and estimates with respect to determining the fair value of exploration and evaluation assets and petroleum and natural gas assets acquired generally require the most judgment and include estimates of reserves acquired, forecast benchmark commodity prices and discount rates. Changes in any of the assumptions or estimates used in determining the fair value of acquired assets and liabilities could impact the amounts assigned to assets, liabilities and goodwill in the purchase price allocation. Contingencies By their nature, contingencies will only be resolved when one or more future events occur or fail to occur. The assessment of contingencies inherently involves the exercise of significant judgment and estimates of the outcome of future events. 3. SIGNIFICANT ACCOUNTING POLICIES (a) Cash and cash equivalents The Company’s cash and cash equivalents consist of deposits held in the Company’s chequing accounts and interest bearing savings accounts. (b) Revenue recognition Revenue from the sale of petroleum and natural gas is recognized when volumes are delivered and title passes to an external party at contractual delivery points and are recorded gross of transportation charges incurred by the Company. The costs associated with the delivery, including transportation and production-based royalty expenses, are recognized in the same period in which the related revenue is earned and recorded. Royalty income is recognized as it accrues in accordance with the terms of the respective overriding royalty agreements. Other income is recognized as it is earned which includes interest income as well as processing income. (c) Property, plant and equipment The Company’s property, plant and equipment is comprised of petroleum and natural gas assets and corporate assets. Capitalization Petroleum and natural gas assets are measured at cost less accumulated depletion and depreciation and accumulated impairment losses, if any. Petroleum and natural gas assets consists of the purchase price and costs directly attributable to bringing the asset to the location and condition necessary for its intended use. Petroleum and natural gas assets include developing and producing interests such as land acquisitions, geological and geophysical costs, facility and production equipment, other directly attributable costs and the initial estimate of the costs of dismantling and removing an asset and restoring the site on which it was located. Subsequent costs Costs incurred subsequent to the determination of technical feasibility and commercial viability are recognized as developing and producing petroleum and natural gas interests when they increase the future economic benefits embodied in the specific asset to which they relate. Such capitalized petroleum and natural gas interests generally represent costs incurred in developing proved and/or probable reserves and bringing in or enhancing production from such reserves, and are accumulated on a field or geotechnical area basis. The cost of day-to-day servicing of an item of petroleum and natural gas assets is expensed in income or loss as incurred. Petroleum and natural gas assets are derecognized upon disposal or when no future economic benefits are expected to arise from the continued use of the asset. Any gain or loss arising from the Page | 19 disposal of an asset, determined as the difference between the net disposal proceeds and the carrying amount of the asset, is recognized in income or loss. Leased assets Other leases are capital leases, which are recognized on the Company’s balance sheet. Petrus records the payments made in accordance with the lease as a reduction to the obligation recorded. Depletion and depreciation The costs related to area cost centres for petroleum and natural gas properties, including related pipelines and facilities, are depleted using a unit-of-production method based on the commercial proved and probable reserves allocated to its CGU. Petroleum and natural gas assets are not depleted until production commences. This depletion calculation includes actual production in the period and total estimated proved and probable reserves attributable to the assets being depleted, taking into account total capitalized costs plus estimated future development costs necessary to bring those reserves into production. Relative volumes of reserves and production (before royalties) are converted at the energy equivalent conversion ratio of six thousand cubic feet of natural gas to one barrel of oil. Proved and probable reserves are estimated using independent reservoir engineering reports and represent the estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be recoverable in future years from known reservoirs and which are considered commercially producible. Corporate assets are stated in the statement of financial position at cost less accumulated depreciation. Depreciation is calculated on a reducing balance method so as to write off the cost of these assets, less estimated residual values, over their estimated useful lives. The expected useful lives of property, plant and equipment are reviewed on an annual basis and, if necessary, changes in useful lives are accounted for prospectively. Impairment The carrying amounts of property, plant and equipment are grouped into CGU’s and the CGU’s are reviewed quarterly for indicators of impairment. Indicators are events or changes in circumstances that indicate that the carrying amount may not be recoverable. If indicators of impairment exist, the recoverable amount of the CGU is estimated. If the carrying amount of the CGU exceeds the recoverable amount, the CGU is written down with an impairment recognized in net income (loss). The assessment for impairment entails comparing the carrying value of the CGU with its recoverable amount: that is, the higher of fair value, less costs to sell, and value in use. Each CGU is identified in accordance with IAS 36, Impairment of Assets. Petrus’ property, plant and equipment are grouped into CGU’s based on separately identifiable and largely independent cash inflows considering geological characteristics, shared infrastructure and exposure to market risks. Estimates of future cash flows used in the calculation of the recoverable amount are based on reserve evaluation reports prepared by independent reservoir engineers. The recoverable amount is the higher of fair value, less costs to sell, and the value-in-use. Fair value, less costs to sell, is derived by estimating the discounted after-tax future net cash flows. Discounted future net cash flows are based on forecasted commodity prices and costs over the expected economic life of the reserves and discounted using market-based rates to reflect a market participant’s view of the risks associated with the assets. Value-in-use is assessed using the expected future cash flows discounted at a pre-tax rate. Impairments of property, plant and equipment are only reversed when there is significant evidence that the impairment has been reversed, but only to the extent of what the carrying amount would have been had no impairment been recognized. (d) Exploration & evaluation assets Capitalization All costs incurred after the rights to explore an area have been obtained, such as geological and geophysical costs, other direct costs of exploration (drilling, testing and evaluating the technical feasibility and commercial viability of extraction) and appraisal and including any directly attributable general and administration costs and share-based payments, are accumulated and capitalized as exploration and evaluation assets. Certain costs incurred prior to acquiring the legal rights to explore are charged directly to net income (loss). Amortization Exploration and evaluation costs are not amortized prior to the conclusion of appraisal activities. At the completion of appraisal activities, if technical feasibility is demonstrated and commercial reserves are discovered, then the carrying value of the relevant exploration and evaluation asset will be reclassified as a property, plant and equipment asset into the CGU to which it relates, but only after the carrying value of the relevant exploration and evaluation asset has been assessed for impairment and, where appropriate, its carrying value adjusted. Technical feasibility and commercial viability are considered to be demonstrable when proved or probable reserves are determined to exist. If it is determined that technical feasibility and commercial viability have not been achieved in relation to the exploration and evaluation assets appraised, all other associated costs are written down to the recoverable amount in net income (loss). Page | 20 Expired land leases included as undeveloped land in exploration and evaluation assets are recognized in exploration and evaluation cost in net income (loss) upon expiry. Impairment If and when facts and circumstances indicate that the carrying value of an exploration and evaluation asset may exceed its recoverable amount, an impairment review is performed. For exploration and evaluation assets, when there are such indications, an impairment test is carried out by grouping the exploration and evaluation assets with property, plant and equipment CGU’s to which they belong for impairment testing. The equivalent combined carrying value of the CGU’s is compared against the recoverable amount of the CGU’s and any resulting impairment loss is written off to net income (loss). The recoverable amount is the greater of fair value, less costs to sell, or value-in-use. (e) Business combinations Business combinations are accounted for using the acquisition method. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured at their fair values at the acquisition date. The cost of an acquisition is measured as the fair value of the assets given, equity instruments issued and liabilities incurred or assumed at the acquisition date. The excess of the cost of the acquisition over the fair value of the identifiable assets, liabilities and contingent liabilities acquired is recorded as goodwill. If the cost of the acquisition is less than the fair value of the net assets of the subsidiary acquired, the difference is recognized immediately in net income (loss). Transaction costs associated with a business combination are expensed as incurred. (f) Decommissioning obligations The Company’s activities give rise to dismantling, decommissioning and reclamation requirements. Costs related to these abandonment activities are estimated by management in consultation with the Company’s engineers based on risk-adjusted current costs which take into consideration current technology in accordance with existing legislation and industry practices. Decommissioning obligations are measured at the present value of the best estimate of expenditures required to settle the obligations at the reporting date. When the fair value of the liability is initially measured, the estimated cost, discounted using a risk-free rate, is capitalized by increasing the carrying amount of the related petroleum and natural gas assets. The increase in the provision due to the passage of time, or accretion, is recognized as a finance expense. Increases and decreases due to revisions in the estimated future cash flows are recorded as adjustments to the carrying amount of the related petroleum and natural gas assets. Actual costs incurred upon settlement of the liability are charged against the obligation to the extent that the obligation was previously established. The carrying amount capitalized in petroleum and natural gas assets is depleted in accordance with the Company’s depletion and depreciation policy. The Company reviews the obligation at each reporting date and revisions to the estimated timing of cash flows, discount rates and estimated costs will result in an increase or decrease to the obligations. Any difference between the actual costs incurred upon settlement of the obligation and recorded liability is recognized as an increase or reduction in income. (g) Finance expenses Finance expense may be comprised of interest expense on borrowings and accretion of the discount on decommissioning obligations. (h) Financial instruments Non-derivative financial instruments Non-derivative financial instruments comprise cash and cash equivalents, accounts receivables, accounts payable and accrued liabilities and outstanding credit facilities. Non-derivative financial instruments are recognized initially at fair value plus any directly attributable transaction costs. Subsequent to initial recognition, non-derivative financial instruments are measured based on their classification. The Company has made the following classifications: • • • Cash and cash equivalents are classified as financial assets at fair value, showing separately (i) those designated as such upon initial recognition and (ii) those classified as held for trading in accordance with IAS 39 Financial Instruments: Recognition and Measurement. Accounts receivable are classified as loans and receivables and are measured at amortized cost using the effective interest method. Typically, the fair value of these balances approximates their carrying value due to their short term to maturity. Accounts payable and accrued liabilities and outstanding credit facilities are classified as other liabilities and are measured at amortized cost using the effective interest method. Due to the short term nature of accounts payable and accrued liabilities, their carrying values approximate their fair values. The Company’s outstanding credit facilities bear interest at a floating rate and accordingly the fair market value approximates the carrying value. (i) Share capital Common shares are classified as equity. Incremental costs directly attributable to the issuance of common shares are recognized as a reduction in share capital, net of any tax effects. (j) Flow-through shares The resources expenditure deductions for income tax purposes related to exploratory activities funded by flow-through shares are renounced to investors in accordance with tax legislation. Upon issuance of a flow-through share, a liability is recognized representing the premium paid on flow- through common shares over regular common shares. This liability is reduced as the expenditures are incurred and tax attributes are renounced. The difference between the initial liability and the deferred tax liability created is recorded as a deferred tax expense. Page | 21 (k) Income taxes The Company’s income tax expense is comprised of current and deferred tax. Income tax expense is recognized through income or loss except to the extent that it relates to items recognized directly in equity, in which case the related income taxes are also recognized in equity. Current tax is the expected tax payable on taxable income for the period, using tax rates enacted or substantively enacted at the reporting date, and any adjustment to tax payable in respect of previous years. Deferred tax is recognized on temporary differences between the carrying amounts of assets and liabilities in the financial statements and the corresponding tax basis used in the computation of taxable income. Deferred tax liabilities are generally recognized for all taxable temporary differences. Deferred tax assets are generally recognized for all deductible temporary differences to the extent that it is probable that taxable income will be available against which those deductible temporary differences can be utilized. The carrying amount of deferred tax assets is reviewed at the end of each reporting period and reduced to the extent that it is no longer probable that sufficient taxable income will be available to allow all or part of the asset to be recovered. Deferred tax assets and liabilities are measured at the tax rates that are expected to apply in the period in which the liability is expected to be settled or the asset realized, based on tax rates (and tax laws) that have been enacted or substantively enacted by the end of the reporting period. The measurement of deferred tax liabilities and assets reflects the tax consequences that would follow from the manner in which Petrus expects, at the end of the reporting period, to recover or settle the carrying amount of its assets and liabilities. (l) Joint interests Significantly all of the Company’s activities are conducted jointly with others through unincorporated joint ventures. The Company accounts for its share of the results and net assets of these Joint Ventures as jointly controlled assets. The audited financial statements include Petrus’ share of these jointly controlled assets and a proportionate share of the relevant revenue and related costs. (m) Share-based compensation The Company follows the fair value method of valuing stock option and performance warrant grants. Share-based compensation expense is determined based on the estimated fair value of shares on the date of grant. Forfeitures are estimated at the grant date and are subsequently adjusted to reflect actual forfeitures. The expense is recognized over the service period, with a corresponding increase to contributed surplus. The Company capitalizes the qualifying portion of share-based compensation expense directly attributable to the exploration and development activities of exploration and evaluation assets and petroleum and natural gas assets, with a corresponding decrease to share-based compensation expense. At the time the stock options or performance warrants are exercised, the issuance of common shares is recorded as an increase to shareholders’ capital and a corresponding decrease to contributed surplus. (n) Earnings per share Earnings per share are presented for basic and diluted earnings. Basic per share information is computed by dividing the net income (loss) for the period attributable to equity owners of the Company by the weighted average number of common shares outstanding during the period. The weighted average number of shares for fully diluted earnings per share information is calculated using the treasury stock method whereby it is assumed that proceeds obtained upon exercise of share warrants and stock options issued under the Company’s Stock Option Plan would be used to purchase common shares at the average market price during the period. The treasury stock method also assumes that the deemed proceeds related to unrecognized share-based payments expense are used to repurchase shares at the average market price during the period. Under the treasury stock method, stock options and share warrants have a dilutive effect only when the average market price of the common shares during the period exceeds the exercise price of the options or warrants (they are "in-the-money"). Exercise of in-the-money stock options and share warrants is assumed at the beginning of the year or date of issuance, if later. Should the Company have a loss for the period, stock options and share warrants would be anti- dilutive and therefore will have no effect on the determination of loss per share. (o) Changes in presentation From January 1, 2012 the Company re-classified processing income from interest and other income to operating expenses in the Statement of Net Income (Loss) and Comprehensive Income (Loss). The comparative information has been re-classified to conform to current presentation. Processing income re-classified from interest and other income to net against operating expenses was $82,892. p) New standards and interpretations not yet adopted The IASB issued the following IFRSs effective for annual periods beginning on or after January 1, 2013. Earlier application is permitted providing that IFRS 10, IFRS 11, IFRS 12, IAS 27 and IAS 28 are adopted together, except that IFRS 12 may be adopted earlier. Petrus has assessed the impact of adopting these pronouncements and has determined these standards will not have a material impact on the Company’s financial statements. IFRS 10 Consolidated Financial Statements builds on existing principles by identifying the concept of control as the determining factor in whether an entity should be included within the consolidated financial statements of the parent company. The standard provides additional guidance to assist in the determination of control where it is difficult to assess. IFRS 10 replaces those parts of IAS 27 Consolidated and Separate Financial Statements (revised 2011) that address when and how an entity should prepare consolidated financial statements and replaces SIC 12 Consolidation – Special Purpose Entities in its entirety. IAS 27 retains the current guidance for separate financial statements. IFRS 11 Joint Arrangements provides for a more substance based reflection of joint arrangements by focusing on the rights and obligations of the arrangement, rather than its legal form (as is currently the case). The standard addresses inconsistencies in the reporting of joint arrangements by requiring a single method to account for interests in jointly controlled entities. IFRS 11 supersedes IAS 31 Interests in Joint Ventures and SIC 13 Jointly Page | 22 Controlled Entities – Non-Monetary Contributions by Ventures. IAS 28 Investments in Associates and Joint Ventures (revised 2011) has been amended to conform to changes based on the issuance of IFRS 10 and IFRS 11. IFRS 12 Disclosure of Interests in Other Entities requires extensive disclosures relating to an entity’s interests in subsidiaries, joint arrangements, associates and unconsolidated structured entities. An entity is required to disclose information that help users of its financial statements evaluate the nature of and risks associated with its interests in other entities and the effects of those interests on its financial statements. The effective date of IFRS 12 is January 1, 2013. IFRS 13 Fair Value Measurement establishes a single framework for measuring fair values. This standard applies to all transactions and balances (whether financial or non-financial) for which IFRS requires or permits fair value measurements, with the exception of share-based payment transactions accounted for under IFRS 2 Share-based Payment and leasing transactions within the scope of IAS 17 Leases. IFRS 13 defines fair value, provides guidance on its determination and introduces consistent requirements for disclosures on fair value measurements. Other accounting standards and interpretations IFRS 9 Financial Instruments issued in November 2009 and amended in October 2010 introduces new requirements for the classification and measurement of financial assets and financial liabilities and for derecognition. IFRS 9 is expected to be published in three parts. The first part, Phase 1 – classification and measurement of financial instruments sets out the requirements for recognizing and measuring financial assets, financial liabilities and some contracts to buy or sell non-financial items. Phase 1 simplifies the measurement of financial assets by classifying all financial assets as those being recorded at amortized cost or being recorded at fair value. Phase 1 is effective for periods beginning on or after January 1, 2015, although earlier adoption is allowed. Except for certain additional disclosures, the adoption of this standard is not expected to have an impact on the Company’s financial statements. 4. DETERMINATION OF FAIR VALUES A number of the Company’s accounting policies and disclosures require the determination of fair value, for both financial and non-financial assets and liabilities. Fair values have been determined for measurement and/or disclosure purposes based on the following methods. When applicable, further information about the assumptions made in determining fair values is disclosed in the notes specific to that asset or liability. Petroleum and natural gas properties and equipment and exploration and evaluation assets The fair value of petroleum and natural gas properties and equipment recognized in a business combination, is based on market values. The market value of petroleum and natural gas properties and equipment is the estimated amount for which property, plant and equipment could be exchanged on the acquisition date between a willing buyer and a willing seller in an arm’s length transaction after proper marketing wherein the parties had each acted knowledgeably, prudently and without compulsion. The market value of oil and natural gas interests (included in petroleum and natural gas properties and equipment) and intangible exploration and evaluation assets is estimated with reference to the discounted cash flow expected to be derived from oil and natural gas production based on externally prepared reserve reports. The risk- adjusted discount rate is specific to the asset with reference to general market conditions. Cash and cash equivalents, accounts receivable, deposits and prepaid expenses, accounts payable and accrued liabilities The fair value of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities is estimated as the present value of future cash flow, discounted at the market rate of interest at the reporting date. At December 31, 2012 and December 31, 2011, the fair value of these balances approximated their carrying value due to their short term to maturity. Derivatives The fair value of commodity price risk management contracts is determined by discounting the difference between the contracted prices and published forward price curves as at the Statement of Financial Position date, using the remaining contracted oil and natural gas volumes and a risk-free interest rate (based on published government rates). The fair value of options is based on option models that use published information with respect to volatility, prices and interest rates. Share-based payments The fair value of employee share-based payments is measured using a Black-Scholes option-pricing model. Measurement inputs include share price on measurement date, exercise price of the instrument, expected volatility in share price (based on weighted average historic volatility adjusted for changes expected due to publicly available information), weighted average expected life of the instruments (based on historical experience and general option holder behavior), expected dividend yield, risk-free interest rate (based on government bonds) and estimated forfeiture rate at the initial grant date. The Company’s financial instruments recorded at fair value require disclosure about how the fair value was determined based on significant levels of inputs described in the following hierarchy: • Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Page | 23 • Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1. Prices in Level 2 are either directly or indirectly observable as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, time value and volatility factors, which can be substantially observed or corroborated in the marketplace. • Level 3 – Valuations in this level are those with inputs for the asset or liability that are not based on observable market data. Assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy level. The following tables provide fair value measurement information for financial assets and liabilities as of December 31, 2012. The carrying value of cash and cash equivalents, accounts receivables, deposits and accounts payables and accrued liabilities included in the Statement of Financial Position approximate fair value due to the short-term nature of those instruments. These assets and liabilities are not included in the following table. Financial Assets Fair value of financial instruments Financial Liabilities Fair value of financial instruments 5. CASH AND CASH EQUIVALENTS Carrying Amount As at December 31, 2012 Level 1 Fair Value Level 2 Level 3 371,574 371,574 1,137,562 1,137,562 — — 371,574 1,137,562 — — The components of the Company’s cash and cash equivalents are as follows: Balance as at December 31, Cash in chequing accounts Cash in interest bearing savings accounts Balance, December 31, 2012 6. ACQUISITIONS 2012 1,510,260 10,078,773 11,589,033 2011 781,988 7,004,800 7,786,788 On June 29, 2012 Petrus closed an acquisition of petroleum and natural gas assets in the Peace River area of Alberta, with an effective date of April 1, 2012, for total cash consideration of $60.3 million, net of adjustments and acquisition related expenses. The transaction was accounted for as a business combination using the acquisition method whereby the net assets acquired and the liabilities assumed are recorded at fair value and was financed by existing cash balances and proceeds from an equity financing. A total of $72,243 in acquisition related costs, which relate to professional fees, have been charged to finance expenses in the Statement of Net Income (Loss) and Comprehensive Income (Loss) in the year ended December 31, 2012. The financial statements incorporate the operations of the properties beginning June 30, 2012. During the period June 30, 2012 to December 31, 2012, the Company recorded oil and natural gas revenue of $11.3 million and net income of $6.3 million related to the acquisition. The impact of this acquisition on revenue and net income, as if acquired at the beginning of the year, would have been incremental revenue of $11.3 million and incremental net income of approximately $6.3 million. The following table summarizes the net assets acquired pursuant to the acquisition: Fair value of net assets acquired Prepaid operating expenses Exploration and evaluation assets Petroleum and natural gas properties and equipment Decommissioning obligations Total net assets acquired 568,271 5,612,500 61,754,458 (7,652,684) 60,282,545 On October 31, 2011 Petrus closed an acquisition of petroleum and natural gas assets in the Alberta foothills area, with an effective date of July 1, 2011 for cash consideration of $42 million, net of adjustments. The transaction was accounted for as a business combination. Petrus recorded $5.2 million in exploration and evaluation assets for the value of undeveloped land and seismic, $36.8 million in property and equipment and $3.6 million of decommissioning liabilities were recognized in relation to the acquired properties. Acquisition costs of $18 thousand were charged to finance expenses on the Statement of Net Income (Loss) and Comprehensive Income (Loss) for the period ended December 31, 2011. The financial statements incorporate the operations of the properties beginning November 1, 2011. During the period November 1, 2011 to December 31, 2011, the Company recorded oil and natural gas revenue of $2 million and a net loss of $230 thousand related to the acquisition. The impact of this acquisition on revenue and net loss, as if acquired at the beginning of 2011, would have been incremental revenue of $10.3 million and an incremental net loss of $1.1 million, respectively. Page | 24 7. EXPLORATION AND EVALUATION ASSETS The components of the Company’s Exploration and Evaluation assets are as follows: Balance at inception Additions Capitalized G&A and share-based compensation Acquisitions (note 6) Decommissioning costs incurred Balance, December 31, 2011 Additions Acquisitions (note 6) Capitalized G&A and share-based compensation Decommissioning costs incurred Transfers to property, plant and equipment Balance, December 31, 2012 — 1,970,697 58,267 5,160,551 42,955 7,232,470 42,693,416 5,612,500 957,661 919,996 (11,625,189) 45,790,854 Exploration and evaluation assets consist of Petrus’ undeveloped land and exploration and development projects which are pending the determination of technical feasibility. Additions represent the Company’s share of costs incurred on these assets during the period. Exploration and evaluation assets are not subject to depletion. During the year ended December 31, 2012 the Company established technical feasibility and commercial viability in each of its core operating areas, as economical quantities of reserves were determined to exist. The Company determined that no indicators of impairment exist, and transferred $11.6 million of costs to property, plant and equipment (2011 – Nil). For the year ended December 31, 2012 the Company incurred exploration and evaluation expense in the Statement of Net Income (Loss) and Comprehensive Income (Loss) of $420,000 which relates to expiring undeveloped land in minor properties (2011 - $Nil). During the year ended December 31, 2012 the Company capitalized $957,661 (2011 - $107,823) of general & administrative expenses (“G&A”) directly attributable to development activities. Included in this amount is non-cash related share-based compensation of $485,917 (2011 - $4,859). 8. PROPERTY, PLANT AND EQUIPMENT $ Balance at inception Cash additions Acquisitions (note 6) Capitalized G&A and share-based compensation Transfers from exploration and evaluation assets Depletion & depreciation Change in decommissioning provision Balance, December 31, 2011 Cash additions Acquisitions (note 6) Capitalized G&A and share-based compensation Transfers from exploration and evaluation assets Depletion & depreciation Balance, December 31, 2012 Cost — 246,532 36,818,894 58,267 — — 3,592,084 40,715,777 5,647,482 61,754,458 957,661 11,625,189 — 120,700,567 Accumulated DD&A Net book value — — — — — (626,733) — (626,733) — — — (8,088,689) (8,715,422) — 246,532 36,818,894 58,267 — (626,733) 3,592,084 40,089,044 5,647,482 61,754,458 957,661 11,625,189 (8,088,609) 111,985,145 Estimated future development costs of $42.8 million (2011 - $10.2 million) associated with the development of the Company’s proved plus probable undeveloped reserves were included with the costs subject to depletion. During the year ended December 31, 2012 the Company capitalized $957,661 (2011 - $107,823) of general & administrative expenses (“G&A”) directly attributable to development activities. Included in this amount is non-cash related share-based compensation of $485,916 (2011 - $4,859). 9. REVOLVING CREDIT FACILITY The Company has a demand revolving credit facility of $40 million with a major Canadian lender which is undrawn at December 31, 2012. The credit facility was obtained for general corporate purposes. The facility is available on a revolving basis for a period until June 29, 2013 and then for a further year under the term out provisions. The initial term out date may be extended for further 364 day periods at the request of Petrus, subject to approval by the lender. The credit facility provides that advances may be made by way of direct Canadian advances (at an interest rate equal to the Page | 25 Bank of Canada prime rate plus 0.75% per annum), U.S. dollar advances (at an interest rate equal to the U.S. Base Rate plus 0.75% per annum), or bankers’ acceptances (at a stamping fee calculated on the face amount of the banker’s acceptance at a rate equal to 175 basis points per annum). The amount of the credit facility is subject to a borrowing base test performed on a semi-annual review by the lender, based primarily on reserves and using commodity prices estimated by the lender as well as other factors. The Company has provided security by way of a $100 million debenture over all of the present and after acquired property of the Company. A decrease in the borrowing base could result in a reduction to the available credit facility. The next semi-annual review of the credit facility is to take place on June 29, 2013. At December 31, 2012, the Company has a letter of credit of $180,000 against the facility (2011; no letters of credit) but otherwise the facility is undrawn (2011; nil). 10. DECOMMISSIONING OBLIGATION The decommissioning liability was estimated based on the Company’s net ownership interest in all wells and facilities, the estimated costs to abandon and reclaim the wells and facilities and the estimated timing of the costs to be incurred in future periods. The estimated future cash flows have been discounted using an average risk free rate of two percent and an inflation rate of two percent (December 31, 2011; three percent and two percent, respectively). The Company has estimated the net present value of the decommissioning obligations to be $12.4 million as at December 31, 2012 which is equal to the undiscounted, uninflated total future liability of $12.4 million. These payments are expected to be incurred over the operating lives of the assets (10 years). The following table reconciles the decommissioning liability: Balance as at December 31, Opening balance Acquisitions (note 6) Liabilities incurred Accretion expense Balance, December 31, 2012 11. FINANCIAL RISK MANAGEMENT 2012 3,652,999 7,652,684 919,996 170,035 12,395,714 2011 — 3,592,084 42,955 17,960 3,652,999 The Company utilizes commodity contracts as a risk management technique to mitigate exposure to commodity price volatility. The following table summarizes the financial derivative contracts Petrus has outstanding as at December 31, 2012: Natural Gas Period Hedged Jan. 1, 2013 to Mar. 31, 2013 Apr. 1, 2013 to Oct. 31, 2013 Jan. 1, 2013 to Mar. 31, 2013 Nov. 1, 2013 to Mar. 31, 2014 Apr. 1, 2013 to Oct. 31, 2013 Crude Oil Period Hedged Jan 1, 2013 to Dec. 31, 2013 Jan 1, 2013 to Dec. 31, 2013 Jan 1, 2013 to Dec. 31, 2013 Jan 1, 2014 to Dec. 31, 2014 Total risk management asset Total risk management liability Type Daily Volume Fixed price Costless collar Fixed price Costless collar Costless collar Type Costless collar Fixed price Fixed price Put Option 4,000 GJ 1,500 GJ 2,000 GJ 4,000 GJ 4,000 GJ Daily Volume 400 Bbl 200 Bbl 100 Bbl 200 Bbl Price (CAD) $2.25/GJ $2.50 - $3.02/GJ $2.62/GJ $3.25 - $3.53/GJ $2.80 - $3.02/GJ Price (USD) WTI $82.50 - $92.45/Bbl WTI $98.35/Bbl WTI $90.73/Bbl WTI $85.00/Bbl 371,574 (1,137,562) For the twelve months ended December 31, 2012, Petrus recorded a realized gain of $563,226 and an unrealized loss of $769,888. The Company had not entered into financial derivative contracts in the year ended December 31, 2011, therefore there is no comparative financial information. Page | 26 12. SHARE CAPITAL Authorized The authorized share capital consists of an unlimited number of common voting shares without par value. Issued and Outstanding Common shares Balance at inception Common shares issued under private placement Flow-through shares issued, net of premium Common shares issued under private placement Share issue costs Tax benefit of share issue costs Balance, December 31, 2011 Common shares issued under private placement (1) Common shares issued under private placement (2) Common shares issued under private placement (4) Flow-through shares issued, net of premium (3) Flow-through shares issued, net of premium (4) Share issue costs Tax benefit of share issue costs Deferred tax benefits Balance, December 31, 2012 Number of Shares Amount — 11,050,000 2,970,966 18,012,050 — — 32,033,017 80,000 50,774,571 2,772,557 605,488 10,000 — — — 86,275,633 — 11,050,000 5,941,932 36,024,100 (2,206,403) 208,530 51,018,159 160,000 88,855,499 4,851,975 1,059,604 17,500 (2,914,580) 876,400 194,570 144,173,650 Share Issuances (1) In April 2012 the Company completed a subsequent closing to its November 2011 private equity placement and issued 80,000 common shares at a price of $2.00 per common share for gross proceeds of $160,000. (2) The Company completed its third significant private equity placement on June 29, 2012. 50,774,571 common shares were issued at a price of $1.75 per share for gross proceeds of $88,855,499. (3) On June 29, 2012, the Company also issued 605,488 flow-through shares at a price of $2.10 per share for total gross proceeds of $1,271,525. Of the issuance price, $0.35 per share or $211,921 was determined to be the premium on the flow-through shares. Petrus spent $1,059,604 on qualified exploration and development expenditures to satisfy the obligation. (4) On July 5, 2012 the Company issued 2,772,557 common shares at a price of $1.75 per share for gross proceeds of $4.9 million. In addition, the Company issued 10,000 common shares on a flow-through basis at a price of $2.10 per share for gross proceeds of $21,000. Of the issuance price, $0.35 per share or $3,501 was determined to be the premium on the flow-through shares. The issuances were subsequent additional closings related to the June 2012 private equity placement. SHARE-BASED COMPENSATION Performance Warrants The Company may issue performance warrants to employees, consultants and directors of the Company. Performance warrants are granted for a term of three years and vest based on three criteria, time (one third vest per year), market (one third vest as certain share price hurdles are achieved) and employment or service. Upon exercise of the warrants the Company settles the obligation by issuing common shares of the Company and cash settlements are not required. The shares to be offered consist of common shares of the Company`s authorized but unissued common shares. The aggregate number of shares issuable upon the exercise of all warrants granted shall not exceed 20% of the issued and outstanding shares as at April 30, 2012. At December 31, 2012, all 6,422,603 of the performance warrants were issued. Stock Options The Company has a stock option plan in place whereby it may issue stock options to employees, consultants and directors of the Company. The aggregate number of shares that may be acquired upon exercise of all Options granted pursuant to the Plan shall, at any date or time of determination, be equal to ten percent (10%) of the number that is equal to (i) the number of the Company’s basic Common shares then issued and outstanding; minus (ii) a number equal to five (5) times the number of Common Shares that are issuable upon exercise of the then outstanding Performance Warrants minus (iii) a number equal to fifty percent (50%) of the number of Common Shares that have previously been issued upon the exercise of Performance Warrants. At December 31, 2012, 3,995,000 stock options were issued. The summary of performance warrant and stock option activity is presented below: Page | 27 Balance at inception Granted Exercised Forfeited or expired Balance, December 31, 2011 Granted Exercised Forfeited or expired Balance, December 31, 2012 Exercisable, December 31, 2012 Number of warrants Weighted Average Exercise Price ($) — 4,934,000 — — 4,934,000 1,581,603 — 93,000 6,422,603 — — $2.00 — — $2.00 $2.00 — $2.00 $2.00 — The following tables summarize information about the performance warrants outstanding at December 31, 2012: Grant date December 19, 2011 March 20, 2012 May 1, 2012 June 5, 2012 July 10, 2012 August 6, 2012 November 5, 2012 Warrants Outstanding Number outstanding Weighted average exercise price Weighted average remaining life (years) Warrants Exercisable Weighted average exercise price Number exercisable 4,934,000 400,000 400,000 225,000 56,603 400,000 100,000 6,515,603 $2.00 $2.00 $2.00 $2.00 $2.00 $2.00 $2.00 $2.00 3.97 4.22 4.33 4.43 4.53 4.60 4.85 4.08 — — — — — — — — $2.00 $2.00 $2.00 $2.00 $2.00 $2.00 $2.00 $2.00 The fair value of each warrant granted of $0.25 per warrant is estimated on the date of grant using the Black-Scholes pricing model with the following weighted average assumptions (at December 31): Risk free interest rate Expected life (years) Estimated volatility of underlying common shares (%) Estimated forfeiture rate Expected dividend yield (%) 2012 1.23% 5 50% 20% 0% 2011 1.36% 5 65% 20% 0% Petrus estimated the volatility of the underlying common shares by analyzing the volatility of peer group private companies with similar corporate structure, oil and gas assets and size. With respect to the market condition inherent in the warrants, Petrus estimated the probability of achieving the condition and applied the probability to each individual vesting tranche in order to fairly estimate the fair value of each warrant. Balance, December 31, 2011 Granted Exercised Forfeited or expired Balance, December 31, 2012 Exercisable, December 31, 2012 Number of stock options Weighted Average Exercise Price ($) — 3,995,000 — — 3,995,000 — — $1.75 — — $1.75 — Page | 28 The following tables summarize information about the stock options outstanding at December 31, 2012: Grant date June 29, 2012 July 10, 2012 August 27, 2012 November 5, 2012 Stock Options Outstanding Stock Options Exercisable Number outstanding 3,600,000 65,000 175,000 155,000 3,995,000 Weighted average exercise price Weighted average remaining life (years) Number exercisable Weighted average exercise price $1.75 $1.75 $1.75 $1.75 $1.75 4.50 4.53 4.60 4.85 4.51 — — — — — $1.75 $1.75 $1.75 $1.75 $1.75 The fair value of each stock option granted of $0.77 per option is estimated on the date of grant using the Black-Scholes pricing model with the following weighted average assumptions (at December 31): Risk free interest rate Expected life (years) Estimated volatility of underlying common shares (%) Estimated forfeiture rate Expected dividend yield (%) 2012 1.20% 5 50% 20% 0% 2011 — — — — — Petrus estimated the volatility of the underlying common shares by analyzing the volatility of peer group private companies with similar corporate structure, oil and gas assets and size. The following table summarizes the Company’s share-based compensation at December 31, 2012: Share-based compensation expensed in net income Share-based compensation capitalized to exploration and evaluation assets Share-based compensation capitalized to property, plant and equipment Total share-based compensation 1,099,242 485,917 485,916 2,071,075 13. FINANCE EXPENSES The components of finance expenses are as follows: Cash: Interest Acquisition related expenses (note 5) Non cash: Accretion on decommissioning obligations (note 8) Total finance expenses 14. CAPITAL MANAGEMENT 2012 2011 275,389 72,243 347,632 170,035 517,667 — — — 17,960 17,960 The Company’s general capital management policy is to maintain a sufficient capital base in order to manage its business to enable the Company to increase the value of its assets and therefore its underlying share value. The Company’s objectives when managing capital are (i) to manage financial flexibility in order to preserve the Company’s ability to meet financial obligations; (ii) maintain a capital structure that allows Petrus the ability to finance its growth using internally generated cashflow and (iii) to maintain a flexible capital structure which optimizes the cost of capital at an acceptable risk level and provides an optimal return to equity holders. In the management of capital, Petrus includes share capital and total net debt, which is made up of debt and working capital (current assets less current liabilities). Petrus manages its capital structure and makes adjustments in light of economic conditions and the risk characteristics of the underlying assets. In order to maintain or adjust the capital structure, Petrus may issue new equity, increase or decrease debt, adjust capital expenditures and acquire or dispose of assets. Page | 29 15. FINANCIAL INSTRUMENTS Risks associated with Financial Instruments Credit risk The Company may be exposed to certain losses in the event that counterparties to financial instruments fail to meet their obligations in accordance with agreed terms. The Company mitigates this risk by entering into transactions with highly rated major financial institutions and by routinely assessing the financial strength of its customers. At December 31, 2012, financial assets on the statement of financial position are comprised of cash and cash equivalents, prepaid expenses, risk management assets and accounts receivable. The maximum credit risk associated with these financial instruments is the total carrying value. The Company’s accounts receivable are with customers and joint venture partners in the petroleum and natural gas business and are subject to normal credit risk. Concentration of credit risk is mitigated by marketing the majority of the Company’s production to reputable and financially sound purchasers under normal industry sale and payment terms. As is common in the petroleum and natural gas industry in western Canada, Petrus’ receivables relating to the sale of petroleum and natural gas are received on or about the 25th day of the following month. Of the $11.2 million of accounts receivable outstanding as at December 31, 2012 (all of which is less than 90 days old), $6.1 million is owed from eight parties and was received subsequent to the year end (December 31, 2011 - $4.7 million from four parties). As at December 31, 2012 had no past due receivables. Liquidity risk Liquidity risk relates to the risk the Company will encounter difficulty in meeting obligations associated with its financial liabilities that are settled by cash as they become due. The Company’s approach to managing liquidity risk is to ensure, as much as possible, that it will have sufficient liquidity to meet its short-term and long-term financial obligations when due, under both normal and unusual conditions without incurring unacceptable losses or risking harm to the Company’s reputation. The financial liabilities on its statement of financial position consist of accounts payable, risk management liabilities and accrued liabilities. The Company anticipates it will continue to have adequate liquidity to fund its financial liabilities through its future cash flows. Typically the Company ensures that it has sufficient cash on demand to meet expected operational expenses for a normal period. To achieve this objective, the Company prepares annual capital expenditure budgets, which are regularly monitored and updated as considered necessary. Further, the Company utilizes authorizations for expenditures on operated and non-operated projects to further manage capital expenditures. The Company also attempts to match its payment cycle with collection of oil and natural gas revenue on the 25th day of each month. At December 31, 2012, the Company had a $40 million (undrawn) credit facility to provide capital when needed (disclosed in note 9). Petrus anticipates it will continue to have adequate liquidity to fund its financial liabilities through its future funds from operations and available bank debt. Market risk Market risk is the risk of uncertainty arising from movements of the market price of commodities, exchange rates and interest rates. The objective of market risk management is to manage and control exposures that could affect the Company’s income or loss or the value of its derivative financial instruments. Commodity Price Risk Commodity price risk is the risk that the fair value of future cash flows will fluctuate as a result of changes in commodity prices. A significant change in commodity prices can materially impact the Company’s borrowing base limit under its revolving credit facility and may reduce the Company’s ability to raise capital. Commodity prices for petroleum and natural gas are not only influenced by Canadian and United States demand, but also by world events that dictate the levels of supply and demand. For the year ended December 31, 2012, it is estimated that a $0.25/mcf change in the price of natural gas would have changed net income by $554,770. For the year ended December 31, 2012, it is estimated that a $5.00/CDN WTI/bbl change in the price of oil would have changed net income by $686,120. The Company does not apply hedge accounting for these contracts (refer to note 11). Foreign Currency Risk Foreign currency risk is the risk that future cash flows will fluctuate as a result of changes in foreign exchange rates. Petroleum and to a certain extent natural gas prices are based upon reference prices denominated in US dollars, while the majority of the Company’s expenses are denominated in Canadian dollars. The exchange rate effect cannot be quantified, but generally an increase in the value of the Canadian dollar as compared to the US dollar will reduce the prices received by Petrus for its petroleum and natural gas sales. Interest Rate Risk Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. The Company’s cash and cash equivalents and accounts receivable are not exposed to significant interest rate risk. The revolving credit facility is exposed to interest rate cash flow risk as it is priced on a floating interest rate subject to fluctuations in market interest rates. The remainder of Petrus’ financial assets and liabilities are not exposed to interest rate risk. The Company’s credit facility is undrawn at December 31, 2012 and therefore considers management this risk to be limited at year end. Page | 30 16. DEFERRED INCOME TAXES Income (loss) before taxes Combined federal and provincial tax rate Computed “expected” tax expense (recovery) Increase/(decrease) in taxes resulting from: Permanent items Tax impact of flow-through shares Deferred tax benefits not previously recognized Share issuance costs Change in rates Part XXII.6 tax Other Current tax expense Deferred tax expense Effective tax rate Year ended December 31, 2012 Year ended December 31, 2011 1,967,661 25% 491,915 524,153 597,638 (107,289) — — 2,660 27,645 2,660 1,534,062 78.1% (871,193) 25% (230,866) 6,619 331,563 — (551,600) (6,075) — 450,359 — — 0.0% The components of the Company’s deferred tax liability at December 31, 2012 are as follows (at December 31, 2011 the Company had a deferred income tax asset which was not recognized due to the uncertainty as to future realization): $ Net book value of assets in excess of tax pools Asset retirement obligations Share issuance costs Non capital loss carry-forwards Unrealized hedging gain Deferred tax liability Year ended December 31, 2012 (9,763,312) 3,098,929 913,280 3,901,138 191,596 (1,658,369) Year ended December 31, 2011 — — — — — — The Company had non-capital losses of approximately $15,604,554 (2011 - $2,495,201) which may be applied against future income for Canadian tax purposes. These non-capital losses expire in 2031 and 2032. 17. SUPPLEMENTAL CASH FLOW INFORMATION The following table reconciles the changes in non-cash working capital as disclosed in the statements of cash flows: $ Source (use) in non-cash working capital: Accounts receivable Deposits and prepaid expenses Accounts payable and accrued liabilities Risk management asset Flow-through share premium liability Risk management liability Operating activities Financing activities Investing activities 18. OPERATING EXPENSES Year ended December 31, 2012 Year ended December 31, 2011 (8,014,533) (192,909) 16,673,973 (371,574) (979,856) 1,137,562 8,252,663 (7,441,454) (979,856) 16,673,973 (3,635,358) (396,657) 4,328,105 — — — 296,090 (635,422) 160,037 771,475 The Company’s gross operating expenses for 2012 were $9.3 million (December 31, 2011; $1.2 million) which includes $1.5 million (December 31, 2011; $167,879) of processing, gathering and compression charges and $8 million (December 31, 2011; $1 million) of other operating expenses incurred to operate the Company’s producing assets. The Company generated processing income recoveries of $2.2 million (December 31, 2011; $82,892) which reduced the Company’s reported operating expenses to $7.1 million for the year ended December 31, 2012 ($1.1 million for the year ended December 31, 2011). Page | 31 19. GENERAL AND ADMINISTRATIVE EXPENSES The Company’s general and administrative expenses consisted of the following expenditures: $ Salaries and benefits Subscriptions and licenses Office costs Legal, accounting and consulting Capitalized general and administrative 20. KEY MANAGEMENT PERSONNEL Year ended December 31, 2012 1,892,848 66,643 504,901 364,105 (943,490) 1,885,007 Year ended December 31, 2011 408,485 36,589 132,578 189,805 (106,817) 660,640 The Company consider its directors and officers to be key management personnel. The following table outlines transactions with key management personnel: Year ended December 31, 2012 Year ended December 31, 2011 704,738 19,442 1,381,246 2,105,426 401,944 8,364 31,039 441,347 11 — 1,004 1,015 $ Salaries and wages Short term employee benefits Share based compensation, gross 21. COMMITMENTS AND CONTINGENCIES The commitments for which the Company is responsible are as follows: Commitments (000s) Office equipment lease Capital commitments Corporate office lease Total commitments 22. SUBSEQUENT EVENTS Total < 1 year 1-5 years 16 5,400 1,506 6,922 5 5,400 502 5,907 Subsequent to December 31, 2012, the Company entered into the following commodity financial derivative contracts: Natural Gas Period Hedged Nov. 1, 2013 to Mar. 31, 2014 Apr. 1, 2014 to Oct. 31, 2014 Crude Oil Period Hedged Feb 1, 2013 to Dec. 31, 2013 Jan 1, 2014 to Dec. 31, 2014 Jan 1, 2014 to Dec. 31, 2014 Type Daily Volume Fixed price Fixed price 1,000 GJ 1,500 GJ Type Daily Volume Fixed price Fixed price Fixed price 100 Bbl 100 Bbl 300 Bbl Price (CAD) Price (USD) $3.55/GJ $3.44/GJ WTI $95.85/Bbl WTI $92.00/Bbl WTI $89.00/Bbl Common share issuance On April 26, 2013 the Company issued 52,655 common shares at a price of $2.00 per share and 34,024 flow-through shares at a price of $2.40 per share for total gross proceeds of $186,968. The issuance was a made pursuant to an Exempt Offering which provided employees and key consultants an opportunity to purchase common and flow-through shares of the Company. Under National Instrument 45-102, the common shares issued are subject to a restricted hold period which expires August 27, 2013. Page | 32 CORPORATE INFORMATION OFFICERS Kevin L. Adair, P. Eng. President and Chief Executive Officer DIRECTORS Don T. Gray Executive Chairman Calgary, Alberta SOLICITOR Burnet, Duckworth & Palmer LLP Calgary, Alberta Neil Korchinski, P. Eng. Vice President, Engineering Kevin L. Adair Calgary, Alberta AUDITOR Ernst & Young LLP Chartered Accountants Calgary, Alberta Cheree Stephenson, CA Vice President, Finance and Chief Financial Officer Joe Looke Irving, Texas INDEPENDENT RESERVE EVALUATOR GLJ Petroleum Consultants Calgary, Alberta Peter Verburg Corporate Secretary Patrick Arnell Calgary, Alberta BANKERS Canadian Imperial Bank of Commerce Calgary, Alberta Rick F. Braund Calgary, Alberta Peter Verburg Calgary, Alberta TRANSFER AGENT Valiant Trust Company Calgary, Alberta HEAD OFFICE 2400, 240 – 4th Avenue S.W. Calgary, Alberta T2P 5H4 Phone: 403-984-9014 Fax: 403-984-2717 WEBSITE www.petrusresources.com Page | 33 

Continue reading text version or see original annual report in PDF format above