Petrus Resources Ltd.
Annual Report 2014

Plain-text annual report

Annual Report December 31, 2014 HIGHLIGHTS Petrus Resources Ltd. (“Petrus” or the “Company”) is pleased to report operating and financial results for the fourth quarter and the 2014 fiscal year, in which the Company set new records for production, cash flow and reserves. • • • • • Petrus began 2014, its third full year of operations, with production of 4,052 boe per day (46% oil and liquids) and exited the year at a record 11,200 boe per day (46% oil and liquids), nearly a three-fold increase. On a debt-adjusted per share basis, exit production was up 28% year-over-year. Average 2014 production was 6,032 boe per day, up from 3,206 boe per day in 2013. Fourth quarter production averaged 9,822 boe per day, compared to 3,658 boe per day in the same period of 2013, an increase of 24% per debt-adjusted share. The increase in production drove strong cash flow growth. Petrus generated $61.3 million in cash flow from operations during the year, nearly double the $31.1 million generated in 2013. Cash flow from operations was $24.6 million in the fourth quarter, up from $9.2 million in the same period last year, an increase of 24% per debt-adjusted share. Cash flow growth was also enhanced by the Company’s continual efforts to build a more efficient business. Operating costs declined 20% in 2014, from $10.26 per boe in 2013 to $8.23 per boe. Annual cash costs including net royalties, operating costs, transportation, G&A and interest totaled $22.43 per boe, delivering a 56% operating margin for 2014. The Company’s cash costs in the fourth quarter totaled $15.86, resulting in a corporate netback of $27.24 and a 63% operating margin. Reserves per debt-adjusted share increased by 34% on a proved developed producing basis, and 26% on a proved plus probable basis. Total proved plus probable reserves increased from 14.9 mmboe in 2013 to 40.6 mmboe in 2014. The Company replaced 12.7 times annual production at an all-in annual Finding, Development and Acquisition (“FD&A”) cost of $21.49 per boe including future development capital (“FDC”) for the proved plus probable category. Petrus ended 2014 with $488.5 million of proved plus probable reserve value, discounted at 10%, 2.1 times the prior year total. On a debt-adjusted per share basis, the proved plus probable reserve value declined 1%, partly a reflection of the steep decline in the reserve evaluator’s price forecast. The Company’s proved developed producing reserve value grew 38% per debt-adjusted share. • Over the twelve month period ended December 31, 2014, Petrus invested $443.0 million in exploration and acquisition activity, up from $57.2 million in 2013. Petrus invested $115.2 million in finding and development activities, along with $327.7 million in acquisitions (net of dispositions). The investments were funded by cash flow, debt (including the issuance of a $90 million term loan) and net equity proceeds in 2014 of $200.8 million. • • • At December 31, 2014 Petrus had 140.6 million common shares outstanding and was 50% drawn against its $200.0 million credit facility. The Company ended the year with net debt of $215.0 million, 2.2 times annualized fourth quarter cash flow. At year end Petrus had 248,038 net acres of undeveloped land, a two-fold increase over the undeveloped land position a year earlier. The percentage of operated production more than doubled in 2014, from 32% to 78%. Subsequent to December 31, 2014 Petrus closed two acquisitions in the Ferrier area of Alberta; included in these acquisitions were approximately 815 boe per day of production and 1,759 net acres of undeveloped land. The acquisitions were made for total cash consideration of approximately $8.9 million (before post-closing adjustments) and closed in the first quarter of 2015. Petrus also disposed of working interest in a non-core property in the Pembina area of Alberta in the first quarter, for net proceeds of $8.2 million (before post-closing adjustments). • The Petrus Board of Directors has approved a base capital budget of $50 million for 2015, excluding acquisitions. The capital budget includes the drilling of 10 gross (six net) wells and the construction of a gas plant in the Ferrier area to reduce future third- party processing fees. The capital budget will be funded through cash flow. Page | 1 SELECTED FINANCIAL INFORMATION Twelve months ended Dec. 31, 2014 Twelve months Ended Dec. 31, 2013 Three months ended Dec. 31, 2014 Three months ended Sept. 30, 2014 Three months ended June 30, 2014 Three months ended Mar. 31, 2014 (000s) except per boe amounts OPERATIONS Average Production Natural gas (mcf/d) Oil (bbl/d) NGLs (bbl/d) Total (boe/d) Total (boe) Natural gas sales weighting Exit production (boe/d) Exit natural gas sales weighting Realized Sales Prices Natural gas ($/mcf) Oil ($/bbl) NGLs ($/bbl) Total ($/boe) Hedging gain (loss) ($/boe) Operating Netback ($/boe) Effective price Royalty income Royalty expense Operating expense Transportation expense Operating netback (2) ($/boe) G & A expense (1) Net interest expense Corporate netback (2) ($/boe) FINANCIAL ($000s except per share) Oil and natural gas revenue Cash flow from operations (2) Cash flow from operations per share (2) Net income (loss) Net income (loss) per share Capital expenditures Net acquisitions (dispositions) Common shares outstanding Weighted average shares As at quarter end ($000s) Net debt (3) Bank debt outstanding Bank debt available Shareholder’s equity Total assets 20,540 2,227 382 6,032 2,201,856 57% 11,200 54% 4.59 87.14 45.23 50.67 0.42 51.09 0.52 (8.69) (8.23) (1.94) 32.75 (2.27) (1.82) 28.66 112,705 61,250 0.57 (47,491) (0.45) 115,218 327,746 140,593 106,719 (215,049) 190,000 100,000 311,760 647,304 10,314 1,417 70 3,206 1,170,141 54% 4,052 54% 3.30 83.95 61.87 49.08 (1.12) 47.96 0.53 (7.66) (10.26) (1.83) 28.74 (1.59) (0.59) 26.56 58,055 31,091 0.36 8,141 0.09 58,851 (1,701) 86,377 86,343 (22,288) 23,380 36,620 156,002 211,952 34,626 2,998 1,053 9,822 903,620 59% 11,200 54% 3.97 67.47 47.52 39.37 3.73 43.10 0.47 (4.38) (6.43) (1.25) 31.51 (2.34) (1.93) 27.24 35,998 24,627 0.18 (63,308) (0.45) 53,049 195,028 140,593 140,571 (215,049) 190,000 100,000 311,760 647,304 17,557 1,799 203 4,928 453,359 59% 5,600 63% 4.23 95.51 51.08 52.04 (3.00) 49.04 0.28 (8.90) (9.69) (2.87) 27.86 (3.19) (2.88) 21.79 23,592 9,878 0.09 7,530 0.07 28,964 113,605 140,458 108,212 21,014 90,000 50,000 374,070 549,248 16,800 2,012 147 4,959 451,269 56% 4,836 55% 5.21 100.20 37.60 59.42 (3.32) 56.10 0.67 (12.76) (9.29) (2.17) 32.55 (1.77) (1.36) 29.42 26,815 13,278 0.15 5,505 0.06 9,275 — 101,748 91,106 415 — 90,000 213,508 259,110 12,864 2,134 95 4,373 393,601 49% 4,641 57% 6.03 94.13 60.91 64.99 (3.64) 61.35 0.73 (13.69) (9.47) (2.21) 36.71 (1.61) (0.85) 34.25 25,581 13,467 0.16 2,208 0.03 23,930 19,113 86,377 86,377 (51,638) 51,901 38,099 158,655 257,245 (1) G&A expenses are shown net of capitalized general & administrative costs. Please refer to the G&A section on page 12 in the December 31, 2014 MD&A. (2) Non-GAAP measures, including the methodology used to calculate debt-adjusted share amounts, are defined on page 8 of the December 31, 2014 MD&A. (3) Net debt includes working capital (deficiency). Page | 2 OPERATIONS UPDATE The Petrus Board of Directors has approved a base capital budget of $50 million for 2015, excluding acquisitions. The capital budget includes the drilling of 10 gross (six net) wells and the construction of a gas plant in the Ferrier area to reduce future third-party processing fees. The capital budget is expected to be funded through cash flow. The Company’s production was significantly diversified during the year as a result of acquisition activities that provided Petrus with new core areas in Ferrier and Central Alberta, more than doubling the operated production (to 78%) and doubling the net undeveloped land (to 248,035 acres). In late February, production was estimated at 9,700 boe per day, with some volumes shut in due to an interruption in service on a major TransCanada pipeline. Average fourth quarter production from the Company’s four operating areas was as follows: Average production for the quarter ended December 31, 2014 Average Production Natural gas (mcf/d) Oil (bbl/d) NGLs (bbl/d) Total (boe/d) Foothills Peace River Ferrier(1) Central Alberta(2) Total 11,313 871 119 2,876 4,468 908 34 1,687 6,490 10 590 1,681 12,355 1,209 310 3,578 34,626 2,998 1,053 9,822 Natural gas sales weighting 59% (1) Petrus closed a property acquisition in Ferrier September 5, 2014 and the corporate acquisition of Arriva Energy Inc. on September 8, 2014.Petrus amalgamated Arriva on October 8, 2014. (2) Petrus closed the acquisition of Ravenwood Energy Corp. on October 8, 2014. Petrus amalgamated Ravenwood on October 8, 2014. 58% 66% 44% 64% Foothills Petrus invested $65.6 million in the Foothills area in 2014 to drill 18 (6.0 net) wells and for the construction of production facilities; $17.7 million of the 2014 spending was invested during the fourth quarter. Production in the Foothills has grown 16% year-over-year from 2,427 boe per day in the fourth quarter of 2013 to 2,826 boe per day in the fourth quarter of 2014. Petrus has entered into two farm-in deals in the Foothills, one in Cordel and one in Brown Creek. The first well is a twin of an existing well in Brown Creek for a Notikewin gas target, and will earn Petrus a 65% working interest. The second is an offset location to a producing well in Cordel in which Petrus would earn a 75% working interest. The wells are being drilled in the first quarter and the drilling rig will be released. Peace River Petrus invested $28.4 million in the Peace River area in 2014 to drill 17 (16.6 net) wells and construct water disposal and production facilities; $4.3 million was invested during the fourth quarter to drill three (3.0 net) wells in the Berwyn area. Production in the Peace River area has grown 45% year-over-year, from 1,166 boe per day in the fourth quarter of 2013 to 1,687 boe per day in the fourth quarter of 2014. Two oil batteries with water disposal capabilities are now fully operational at Tangent and Berwyn contributing to significantly reduced operating costs and increased runtime. Operating costs per boe in the two areas have declined 54% from $25.30 in 2013 to $11.70 in 2014. Petrus has initiated a pilot waterflood program at Berwyn and expects to expand the waterflood area over the next year. Ferrier Petrus closed the corporate acquisition of Arriva Energy Inc. on September 8, 2014 and closed an acquisition of complimentary petroleum and natural gas assets on September 5, 2014 in the Ferrier area of Alberta. The two acquisitions provided Petrus with undeveloped land of 17,839 net acres, production of 1,160 boe per day on close of the acquisitions, in addition to incremental production awaiting tie in. Fourth quarter production was 1,681 boe per day. Petrus invested $134.9 million (including acquisitions of $117.9 million) in the Ferrier area in 2014. Following the close of the Arriva acquisition Petrus drilled five (3.9 net) wells in Ferrier. Two of the wells were drilled under a farm-in arrangement which earned Petrus a working interest in two sections of land plus an option on three additional sections. The well results have been consistent with expectations and Petrus plans to drill at least six wells in Ferrier in 2015. In the near term, Petrus expects to encounter third party facility constraints in the Ferrier area. The Company has secured capacity at a third party production facility for incremental Arriva volumes, and has initiated a process to build its own production facilities in order to mitigate capacity constraints. In addition, an interruption in service on a major TransCanada pipeline in the second half of January resulted Page | 3 in many producers being required to reduce sales volumes. Petrus was required to shut in approximately half of its Ferrier volumes and is currently flowing on varied capacity constraints. TransCanada has stated that it expects the pipeline issue to be rectified in the first quarter of 2015. Central Alberta Petrus closed the corporate acquisition of Ravenwood Energy Corp. on October 8, 2014. The acquisition provided Petrus with approximately 3,500 boe/d of production (40% oil and liquids) and 42,352 net acres of undeveloped land in the Thorsby/Pembina area of Alberta. In 2014 Petrus executed a horizontal well program targeting Glauconite light oil in the Thorsby area which was scheduled in conjunction with Ravenwood’s 2014 nine well drilling program. Tie in activities have added incremental production of over 250 boe per day to date subsequent to close of the transaction. Fourth quarter production in the Central Alberta area was 3,578 boe per day. Petrus invested $217 million (including acquisitions of $195 million) in the Central Alberta area in 2014. Following the close of the Ravenwood acquisition Petrus drilled five (4.7 net) wells in Thorsby. Petrus does not plan to invest additional capital in Central Alberta until commodity prices improve; however Petrus is evaluating waterflood expansion opportunities to optimize the assets in the near term. ANNUAL GENERAL MEETING The Company’s Annual General Meeting will be held at the Jamieson Place Conference Centre, 3rd floor, 308-4th Ave SW Calgary, Alberta, on Friday May 15, 2015 at 9:00 a.m. (Calgary time). The Information Circular and Annual Report for 2014 will be available on the Company’s website, www.petrusresources.com. Page | 4 PRESIDENT’S MESSAGE The past year was a particularly busy one for Petrus. Improving industry and market conditions in the first half of the year provided a constructive backdrop for the Company’s growth plans. A $19 million acquisition of partner interests in February doubled our Northern Foothills acreage and importantly, Petrus assumed operatorship of these low decline assets. A $50 million equity raise in May reduced the Company’s debt to zero and positioned the balance sheet to support additional acquisition and development activities in the second half of the year. During the summer, Petrus identified two separate corporate acquisition opportunities that fit our strategy of accumulating low-decline oil and liquids-rich gas assets. The Arriva acquisition closed in September followed by an oversubscribed private placement for $155 million later that month, and the closing of the Ravenwood acquisition in early October. Throughout the year, Petrus continued to actively drill its existing properties and also finished commissioning two new multi-well production facilities complete with water disposal facilities in the Peace River area. These facilities expenditures significantly reduced current and future operating costs in their respective fields. By mid-year, oil prices began to come under pressure with worldwide production consistently exceeding demand. New volumes added in North America over the previous five years had marginally outstripped world demand growth leading to surplus supply capability. Negative pricing pressure increased in the fall and culminated in late November with OPEC deciding to maintain their output volumes. The benchmark WTI oil price ended the year at approximately US$50 per bbl, down over 50% from the previous mid-summer highs. Similarly, natural gas prices also declined in the second half of 2014 as a result of robust supply. Moderating these effects to some extent was the coincident 10% decline in the Canadian dollar over the same period. Like many energy companies, Petrus has responded to these industry conditions by reducing capex, high-grading opportunities and reducing costs wherever practical. Our goal is to manage prudently through the downturn while maintaining an ability to significantly benefit during the eventual recovery. Our low decline and low cost asset base, combined with our ability to access capital to capture strategic opportunities are very significant competitive advantages in these times. Downturns are challenging but often have silver linings that aren’t immediately apparent. Cost structures that get unsustainably high during prolonged exuberance get reset. Minds and hands are refocused on less glamorous but equally effective optimization and cost control processes. Problems and irritations that seem significant when times are good don’t have the same relevance with the help of additional perspective. In the end, challenges and struggles often result in a leaner, more efficient industry and one that is more resilient to additional trials. There is no doubt that the North American industry is under pressure in our own markets from world suppliers that aren’t subject to the same rules. Data transparency in reserves, production, financial, and environmental performance are legislated here and these data are not disclosed at all in many other jurisdictions. Laws against collusive behavior are stringently enforced here and yet those same behaviors are open practice elsewhere – including OPEC itself. Without the tremendous efforts of North American energy companies and investors over the past five years, oil prices could have been much higher. The rest of the world failed to add any material production capacity, even at $100 oil, yet our companies and investors are disadvantaged by foreign suppliers acting in concert while hiding their actual capabilities from independent scrutiny. The huge reduction in oil and gas capital expenditures together with the stimulating effect of low prices will eventually rebalance the world oil market. Petrus is well positioned to participate fully in the resulting price recovery and we sincerely appreciate the support and patience of our shareholders while the rebalancing takes place. Kevin Adair President, CEO and Director Page | 5 MANAGEMENT’S DISCUSSION & ANALYSIS The following is management’s discussion and analysis ("MD&A") of the financial and operating results of the Company as at and for the three and twelve month periods ended December 31, 2014. The report is dated March 25, 2015. This MD&A should be read in conjunction with the December 31, 2014 audited financial statements. Readers are directed to the advisories at the end of this report regarding forward-looking statements, BOE presentation and non-IFRS measures. FINANCIAL AND OPERATIONAL RESULTS OF OIL AND NATURAL GAS ACTIVITIES Three months ended Sept. 30, 2014 Twelve months ended Dec. 31, 2014 Twelve months ended Dec. 31, 2013 Three months ended Dec. 31, 2014 Three months ended June 30, 2014 Three months ended Mar. 31, 2014 Quarterly average production Natural gas (mcf/d) Oil (bbl/d) NGLs (bbl/d) Total (boe/d) Total (boe) Exit production (boe/d) Exit gas weighting Revenue (000s) Natural Gas Oil NGLs Commodity revenue Royalty revenue Oil and natural gas revenue Average realized prices Natural gas ($/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$/C$ 20,540 2,227 382 6,032 2,201,856 11,200 54% 34,415 70,846 6,302 111,563 1,142 112,705 4.59 87.14 45.23 50.67 0.42 51.09 10,314 1,417 70 3,206 1,170,141 4,052 54% 12,438 43,425 1,572 57,435 620 58,055 3.30 83.95 61.87 49.08 (1.12) 47.96 34,626 2,998 1,053 9,822 903,620 11,200 54% 12,639 19,742 3,194 35,575 423 35,998 3.97 67.47 47.52 39.37 3.73 43.10 17,557 1,799 203 4,928 453,359 5,600 63% 6,830 15,811 951 23,592 128 23,720 4.23 95.51 51.08 52.04 (3.00) 49.04 16,800 2,012 147 4,959 451,269 4,836 50% 7,966 18,346 503 26,815 303 27,118 5.21 100.20 37.60 59.42 (3.32) 56.10 12,864 2,134 95 4,373 393,601 4,641 57% 6,980 18,081 520 25,581 288 25,869 6.03 94.13 60.91 64.99 (3.64) 61.35 Twelve months ended Dec. 31, 2014 Twelve months ended Dec. 31, 2013 Three months ended Dec. 31, 2014 Three months ended Sept. 30, 2014 Three months ended Jun. 30, 2014 Three months ended Mar. 31, 2014 4.64 94.45 0.91 3.19 93.30 0.97 3.61 75.44 0.88 4.19 97.71 0.92 4.68 104.48 0.92 6.00 100.18 0.91 OIL AND NATURAL GAS REVENUE Average production for the fourth quarter of 2014 was 9,822 boe per day (59% natural gas), compared to 3,658 boe per day (49% natural gas) for the fourth quarter of the prior year. Total commodity revenue increased from $57.4 million in 2013 to $111.6 million in the year ended December 31, 2014. Natural gas During the three months ended December 31, 2014, the benchmark natural gas price in Canada (set at the AECO hub) increased by 2% from the prior year (average price of $3.61 per mcf in the fourth quarter compared to $3.53 per mcf in the prior year). The AECO price increased 45% from the average annual price of $3.19 per mcf in 2013 to $4.64 per mcf in 2014. The Company’s average realized gas price during the fourth quarter of 2014 was $3.97 per mcf compared to $3.78 per mcf in the prior year, which represents a 5% increase. Natural gas revenue for the fourth quarter of 2014 was $12.6 million and production of 3,185,615 mcf accounted for approximately 59% of fourth quarter production volume and 36% of commodity revenue (compared to revenue of $3.8 million and production of 998,016 mcf for 50% of production volume and 22% of commodity revenue in the prior year). The Company’s average realized gas price for the year ended December 31, 2014 was $4.59 per mcf compared to $3.30 per mcf in the prior year, which represents a 39% increase. Natural gas revenue for the year ended December 31, 2014 was $34.4 million and production of Page | 6 7,497,099 mcf accounted for approximately 57% of 2014 production volume and 31% of commodity revenue (compared to revenue of $12.4 million and production of 3,764,610 mcf for 54% of production volume and 22% of commodity revenue in the prior year). Crude oil and condensate Edmonton Light Sweet (“Edmonton”) crude oil prices decreased 23% from the fourth quarter of 2013 to the fourth quarter of 2014 ($75.44 per bbl for the fourth quarter of 2014 compared to an average price of $97.43 per bbl for the prior period). The average realized price of Petrus’ crude oil and condensate was $67.47 per bbl for the fourth quarter of 2014 compared to $93.93 per bbl for the same period in the prior year. For the year ended December 31, 2014 the Company’s average realized price for crude oil and condensate increased 4% from 2013 ($87.14 per bbl in 2014 compared to an average price of $83.95 per bbl in 2013). Petrus realized an average negative oil differential of $7.43 in 2014, compared to a negative differential of $7.33 in 2013. Petrus realized a negative differential of $6.53 in the fourth quarter of 2014 compared to a negative differential of $14.79 in the comparable period of the prior year. Oil and condensate revenue for the fourth quarter of 2014 was $19.7 million and production of 275,812 bbl accounted for approximately 30% of total production volume and 55% of commodity revenue (compared to revenue of $12.7 million and production of 163,576 bbl for 49% of total production volume and 75% of commodity revenue in the fourth quarter of the prior year). Fourth quarter production and revenue increased from the prior year as a result of the acquisitions of Arriva, Ravenwood and properties which were acquired early in the fourth quarter. Oil and condensate revenue for the year ended December 31, 2014 was $70.9 million and production of 812,986 bbl accounted for approximately 37% of total production volume and 64% of commodity revenue (compared to revenue of $43.4 million and production of 517,205 bbl for 44% of total production volume and 76% of commodity revenue in the prior year). The increase in production from 2013 to 2014 is attributed to the property and corporate acquisitions completed during the year. In addition, average commodity prices were stronger in 2014 compared to the prior year. Natural gas liquids (NGLs) The Company’s NGL production mix consists of ethane, propane, butane, pentane and sulphur. The pricing received for NGL production is based on the product mix, the fractionation process required and the demand for fractionation facilities. In the fourth quarter, Petrus’ combined realized NGL price averaged $47.52 per bbl compared to $67.20 per bbl in the prior year. NGL revenue for the fourth quarter of 2014 was $3.2 million and production of 96,873 bbl accounted for approximately 10% of the Company’s production volume and 9% of commodity revenue in the fourth quarter (compared to revenue of $0.4 million and production of 6,624 bbl for 2% of total production and 3% of commodity revenue for the fourth quarter of the prior year). The significant increase in NGL production and revenue is directly attributed to the property and corporate acquisitions completed early in the fourth quarter. NGL revenue for the year ended December 31, 2014 was $6.3 million and production of 139,354 bbl accounted for approximately 6% of the Company’s production volume and 5% of commodity revenue in the fourth quarter (compared to revenue of $1.6 million and production of 25,550 bbl for 2% of total production and 3% of commodity revenue for the fourth quarter of the prior year). The increase in production and revenue from 2013 to 2014 is due to the significant increase attributed to the acquisitions completed in 2014. The average NGL price realized offset the positive increase in production. Royalty Revenue Petrus records gross overriding royalty revenue for production related to land or mineral rights owned. The revenue is included in “Other Income” on the Company’s Statement of Net Income and Comprehensive Income. Royalty revenue received in the fourth quarter was $0.4 million compared to $0.2 million in the same quarter of the prior year. For the year ended December 31, 2014 Petrus earned $1.1 million, an increase of 91% from $0.6 million earned in the year ended December 31, 2013. The increase is attributed to higher commodity prices and incremental royalty revenue generated on lands acquired by way of the acquisition activity in 2014. On August 29, 2014 Petrus divested of certain gross overriding royalty interests in its Foothills area for cash proceeds of $4.2 million. A $2.2 million gain was recorded on the disposition. Page | 7 NON-GAAP MEASURES Petrus uses key performance indicators and industry benchmarks such as “cash flow from operations,” “cash flow from operations per share,” “cash flow from operations per debt-adjusted share,” and “net debt” to analyze financial and operating performance. These indicators are not defined by IFRS and therefore may not be comparable to performance measures presented by other companies. Management believes that in addition to net income, the aforementioned non-IFRS measurements are useful supplemental measures as they assist in the determination of the Company’s operating performance, leverage and liquidity. Investors should be cautioned, however, that these measures should not be construed as an alternative to both net income and net cash from operating activities, which are determined in accordance with IFRS, as indicators of the Company’s performance. Cash Flow from Operations Cash flow from operations represents cash flow from operating activities prior to changes in non-cash working capital and settlement of decommissioning obligations. Petrus evaluates its financial performance primarily on cash flow from operations and considers it a key performance indicator as it demonstrates the Company’s ability to generate sufficient cash flow to fund capital investment and repay debt. The reconciliation between cash flow from operations and cash flow from operating activities, as defined by IFRS, is as follows: ($000s) Cash flow from operating activities Changes in non-cash working capital Decommissioning expenditures Cash flow from operations Twelve months ended Dec 31, 2014 Twelve months ended Dec 31, 2013 Three months ended Dec 31, 2014 Three months ended Dec 31, 2013 80,988 (20,834) 1,096 61,250 26,238 4,853 — 31,091 47,198 (23,318) 747 24,627 7,079 2,141 — 9,220 Net Debt Working capital (net debt) is a non-GAAP measure and is calculated as current assets (excluding financial derivative assets) less current liabilities (excluding financial derivative liabilities) and bank debt. Petrus uses net debt as a key indicator of its leverage and strength of its balance sheet. The reconciliation of net debt, as defined, is as follows: ($000s) Current assets (excluding financial derivative assets) Less: current liabilities (excluding financial derivative liabilities) Less: bank debt Working capital (net debt) As at Dec 31, 2014 As at Dec 31, 2013 43,901 (69,831) (189,119) (215,049) 11,184 (10,092) (23,380) (22,288) Debt-adjusted shares Debt-adjusted shares are calculated by adding the shares outstanding for the relevant period to the share equivalent of the Company’s net debt at the end of the period. The calculation assumes the debt is extinguished with a share issuance. Petrus is a privately held company with no public market pricing data. In order to determine the price to convert the Company’s debt to shares, Petrus uses the current equity price if a share issuance was completed during the current period. If a share issuance was not completed, a six times debt-adjusted cash flow multiple is used to estimate the share price. The cash flow multiple is based upon trailing quarter annualized funds flow from operations which represents the annualized cash flow from operating activities prior to changes in non-cash working capital and settlement of decommissioning obligations. The multiple calculated does not, in any way, indicate a fair value for Petrus shares and the sole purpose is to show a comparative metric. Weighted average shares are used for the average quarterly and annual production metrics as well as for cash flow growth; end-of-period shares outstanding are used for exit production and reserves growth performance metrics. The table below reconciles the debt-adjusted shares for the average year-over-year cash flow growth performance metric. ($000s, except per share amounts) Weighted average shares outstanding Annualized trailing cash flow from operations before interest Share price to extinguish debt (1) Ending net debt Share equivalent on ending net debt Debt-adjusted shares (1) Equity price if shares issued arm’s length during the current quarter, otherwise six times debt-adjusted cash flow multiple on annualized trailing quarter cash flow is used to estimate the share price. 106,719 111,920 3.25 (215,049) 66,169 172,888 86,343 37,888 2.37 (22,288) 9,389 95,732 Twelve months ended Dec 31, 2014 Twelve months ended Dec 31, 2013 Page | 8 CASH FLOW FROM OPERATIONS AND EARNINGS Petrus generated cash flow from operations of $24.6 million during the quarter ended December 31, 2014 ($9.2 million during the fourth quarter of 2013). Natural gas (AECO C$/mcf) increased 2% from the fourth quarter of 2013 to the fourth quarter of 2014, and Edmonton crude (Edm. Lt. C$/bbl) decreased 13% for the same period. The Company’s cash flow from operations effectively doubled from $31.1 million generated for the year in 2013 to $61.3 million for 2014. The increase is attributed to an 88% increase in total production year over year (due to development and acquisition activity) and a 3% increase in average commodity price for the year on a boe basis, as well as lower cash costs. Petrus reported a net loss of $63.3 million in the fourth quarter of 2014 (compared to net income of $2.1 million in the fourth quarter of the prior year). The loss was incurred due to an impairment charge due to weaker commodity prices. For the year ended December 31, 2014, Petrus reported a net loss of $47.5 million compared to net income of $8.1 million in the prior year. The following table provides detail on the Company’s cash flow from operations on a barrel of oil equivalent (“boe”) basis. Oil and natural gas revenue Transportation Net revenue Royalty expense Royalty income Net oil and natural gas revenue Operating expense (1) Hedging gain (loss) General & administrative(2) Interest expense (3) Twelve months ended Dec. 31, 2014 Twelve months ended Dec. 31, 2013 $000s 111,563 (4,279) 107,284 (19,140) 1,142 89,285 (18,130) (918) (4,992) (3,995) $/boe $000s $/boe 50.67 (1.94) 48.73 (8.69) 0.52 40.56 (8.23) (0.42) (2.27) (1.82) 57,435 (2,136) 55,299 (8,964) 620 46,955 (12,009) (1,311) (1,856) (688) 49.08 (1.83) 47.26 (7.66) 0.53 40.13 (10.26) (1.12) (1.59) (0.59) Three months ended Dec. 31, 2014 $000s $/boe Three months ended Dec. 31, 2013 $000s $/boe 35,575 (1,126) 34,449 (3,958) 423 30,914 (5,815) 3,371 (2,117) (1,744) 39.37 (1.25) 38.12 (4.38) 0.47 34.21 (6.43) 3.73 (2.34) (1.93) 16,939 (543) 16,396 (2,372) 155 14,179 (3,716) (409) (582) (252) 50.33 (1.61) 48.72 (7.05) 0.46 42.13 (9.88) (1.21) (1.73) (0.75) Cash flow from operations 61,250 27.82 31,091 26.56 24,627 27.25 9,220 28.56 (1) Operating expenses are presented net of processing income and overhead recoveries. (2) G&A expenses are shown net of capitalized general & administrative costs. Please see the G&A section on page 11 in the MD&A for more detail. (3) Interest expense is presented net of interest income. (000s except per share) Cash flow from operations Cash flow from operations/share Net Income (loss) Net income (loss)/share Common shares Weighted average shares Twelve months ended Dec. 31, 2014 Twelve months ended Dec. 31, 2013 Three months ended Dec. 31, 2014 Three months ended Dec. 31, 2013 61,250 0.57 (47,491) (0.45) 140,593 106,719 31,091 0.36 8,141 0.09 86,377 86,343 24,627 0.18 (63,308) (0.45) 140,593 140,571 9,220 0.11 2,086 0.02 86,377 86,377 Page | 9 Performance Metrics Petrus uses certain performance metrics as key indicators to demonstrate the Company’s ability to generate shareholder value. On a debt- adjusted per share basis, Petrus increased cash flow from operations 9% year-over-year from 2013. The same metric for the fourth quarter- over-fourth quarter was an increase of 24%. Petrus increased exit production on a per debt-adjusted thousand share basis 28% from the prior year as shown in the table below: Twelve months ended Twelve months ended % Change(2) Three months ended Three months ended % Change(2) Dec. 31, 2014 Dec. 31, 2013 Dec. 31, 2014 Dec. 31, 2013 Cash flow from operations per debt-adjusted share(1) ($) Exit production per debt-adjusted thousand shares(1) (boe per day) (1) Cash flow from operations per debt-adjusted share is a non-GAAP measure and is reconciled to the nearest GAAP measure on page 7 in the section heading “Non-GAAP” Measures. Debt adjusted calculation uses period ending debt. (2) Variance percentages may not recalculate due to rounding. $0.12 $0.35 0.054 $0.33 $0.10 0.042 28% 9% — — 24% — RESULTS OF OPERATIONS Royalty Expenses Royalties are paid to the Government of Alberta and to gross overriding royalty owners. The following table shows the Company’s quarterly royalty expenses by product category, based upon the primary product produced at the well. Twelve months ended Dec. 31, 2013 Twelve months ended Dec. 31, 2014 Three months ended Dec. 31, 2013 Three months ended Dec. 31, 2014 Royalty Expenses ($000s) Oil and NGLs ($000s) % of production revenue Natural gas (000s) % of production revenue Gas cost (allowance) (000s) Gross overriding Total (000s) 16,270 21% 6,219 18% (6,020) 2,671 19,140 9,837 22% 1,822 15% (2,951) 256 8,964 3,653 16% 2,902 23% (4,543) 1,946 3,958 2,562 20% 409 11% (735) 136 2,372 The increase in total royalties from the fourth quarter of 2013 ($2.4 million) to the fourth quarter of 2014 ($4.0 million) is the result of higher production levels. For the year ended December 31, 2014 Petrus recorded total royalties of $19.1 million compared to $9.0 million in the same period of 2013. The increase is related to production growth from the prior year. Gross overriding royalty expense incurred in 2014 ($2.7 million) was significantly higher than the prior year ($0.3 million) due to the overriding royalty structure attributed to acquired properties. Estimates for gas cost allowance were recognized in the fourth quarter related to the two corporate acquisitions. In addition, estimates were revised for the existing assets. Financial Instruments The Company utilizes commodity contracts as a risk management technique to mitigate exposure to commodity price volatility. The following table summarizes the financial derivative contracts Petrus has outstanding as at December 31, 2014: Natural Gas Contract Period Jan. 1, 2015 to Mar. 31, 2015 Jan. 1, 2015 to Mar. 31, 2015 Jan. 1, 2015 to Mar. 31, 2015 Jan. 1, 2015 to Mar. 31, 2015 Jan. 1, 2015 to Mar. 31, 2015 Jan. 1, 2015 to Mar. 31, 2015 Jan. 1, 2015 to Mar. 31, 2015 Jan. 1, 2015 to Mar. 31, 2015 Jan. 1, 2015 to Dec. 31, 2015 Jan. 1, 2015 to Dec. 31, 2015 Jan. 1, 2015 to Mar. 31, 2015 Apr. 1, 2015 to Oct. 31, 2015 Nov. 1, 2015 to Mar. 31, 2016 Daily Volume Price (CAD$/GJ) 2,000 GJ 2,000 GJ 1,000 GJ 1,000 GJ 1,000 GJ 500 GJ 1,000 GJ 1,000 GJ 5,000 GJ 4,000 GJ 3,000 GJ 3,000 GJ 6,000 GJ $3.75/GJ $3.81/GJ $3.84/GJ $4.04/GJ $4.10/GJ $4.18/GJ $4.43/GJ $4.83/GJ $3.50 – 3.63/GJ $3.49/GJ $4.17/GJ $3.35/GJ $3.74/GJ Type Fixed price Fixed price Fixed price Fixed price Fixed price Fixed price Fixed price Fixed price Costless Collar Fixed price Fixed price Fixed price Fixed price Page | 10 Crude Oil Contract Period Jan. 1, 2015 to Dec. 31, 2015 Jan. 1, 2015 to Dec. 31,2015 Jan. 1, 2015 to Dec. 31, 2015 Apr. 1, 2015 to Dec. 31, 2015 Apr. 1, 2015 to Dec. 31, 2015 Electric Power Contract Period Jan. 1, 2015 to Dec. 31, 2015 Type Daily Volume Price ($/Bbl) Fixed price Fixed Price Fixed Price Fixed Price Fixed Price 200 Bbl 100 Bbl 500 Bbl 250 Bbl 250 Bbl WTI $CAD100.00/Bbl WTI $CAD 95.50/Bbl WTI $95.00-104.50/Bbl WTI $97.80/Bbl WTI $92.50-103.50/Bbl Type Annual Volume Price (CAD) Fixed price 12,264 MW $50.00/MWH Subsequent to December 31, 2014 the Company entered into the following financial derivative contracts: Natural Gas Period Hedged Apr. 1, 2015 to Oct. 31, 2015 Nov. 1, 2015 to Mar. 31, 2016 Apr. 1, 2016 to Oct. 31, 2016 Nov. 1, 2016 to Mar. 31, 2017 Apr. 1, 2015 to Oct. 31, 2015 Nov. 1, 2015 to Mar. 31, 2016 Apr. 1, 2016 to Oct. 31, 2016 Nov. 1, 2016 to Mar. 31, 2017 Apr. 1, 2015 to Oct. 31, 2015 Nov. 1, 2015 to Mar. 31, 2016 Apr. 1, 2016 to Oct. 31, 2016 Nov. 1, 2016 to Mar. 31, 2017 Jan. 1, 2016 to Mar. 31, 2016 Apr. 1, 2016 to Oct. 31, 2016 Crude Oil Contract Period Apr. 1, 2015 to Jun. 30, 2015 Jul. 1, 2015 to Sep. 31, 2015 Jan. 1, 2016 to Dec. 31, 2016 Type Daily Volume Price (CAD$/GJ) Fixed price Fixed price Fixed price Fixed price Fixed price Fixed price Fixed price Fixed price Fixed price Fixed price Fixed price Fixed price Fixed price Fixed price 2,000 GJ 2,000 GJ 2,000 GJ 2,000 GJ 4,000 GJ 4,000 GJ 2,000 GJ 2,000 GJ 6,000 GJ 6,000 GJ 6,000 GJ 6,000 GJ 5,000 GJ 5,000 GJ $2.52/GJ $3.03/GJ $2.93/GJ $3.38/GJ $2.46/GJ $2.96/GJ $2.85/GJ $3.31/GJ $2.37/GJ $2.87/GJ $2.75/GJ $3.21/GJ $3.26/GJ $2.91/GJ Type Daily Volume Price ($/Bbl) Costless collar Costless collar Costless collar 2,000 Bbl 2,000 Bbl 700 Bbl WTI $USD45.00-60.10/Bbl WTI $USD45.00-66.00/Bbl WTI $CAD70.00-75.75/Bbl The impact of the contracts which were outstanding during the reporting periods are recorded as realized hedging gains (losses) and affect the Company’s realized commodity price. The unrealized gain (loss) is recorded to demonstrate the impact of the outstanding contracts had they settled on the relative financial reporting period date. The contracts entered had the following impact on net income: Other Income ($000s) Realized hedging gain (loss) Unrealized hedging gain (loss) Total gain (loss) on derivatives Twelve months ended Dec. 31, 2014 Twelve months ended Dec. 31, 2013 Three months ended Dec. 31, 2014 Three months ended Dec. 31, 2013 (918) 17,311 16,393 (1,311) (1,495) (2,806) 3,371 15,205 18,576 (409) 11 (398) Weakened commodity prices resulted in a realized hedging gain of $3.4 million during the fourth quarter of 2014, compared to a $409,000 loss realized in the same quarter of the prior year. The fourth quarter realized gain increased the Company’s realized price by $3.73 per boe, compared to a decrease in the prior year comparable period of $1.22 per boe. For the year ended December 31, 2014 Petrus recorded a $925,000 gain on financial derivatives compared to a $1.3 million loss recorded in the prior year. Page | 11 Operating Expenses The following table shows the Company’s operating expenses for the reporting periods which are shown net of processing income and overhead recoveries: Operating Expenses ($000s) Operating expense, net Operating expense, net ($ per boe) Twelve months ended Dec. 31, 2014 Twelve months ended Dec. 31, 2013 Three months ended Dec. 31, 2014 Three months ended Dec. 31, 2013 18,129 8.23 12,009 10.26 5,815 6.43 3,716 11.03 Operating expenses totaled $5.8 million for the fourth quarter of 2014, a 57% increase from $3.7 million recorded in the same quarter of the prior year. The increase in aggregate net operating expenses is due to 142% higher average fourth quarter production in 2014 compared to the prior year. In addition, overhead recoveries were adjusted in the fourth quarter and third party facility equalizations were received. For the year ended December 31, 2014, operating costs on a per boe basis were 20% lower than the prior year. New water disposal facilities in the Peace River contributed to operating cost reductions. Transportation Expenses The following table shows transportation expenses paid in the reporting periods: Transportation Expenses ($000s) Transportation expense $ per boe Twelve months ended Dec. 31, 2014 Twelve months ended Dec. 31, 2013 Three months ended Dec. 31, 2014 Three months ended Dec. 31, 2013 4,279 1.94 2,136 1.83 1,126 1.25 543 1.61 Petrus pays commodity and demand charges for transporting its gas on various pipeline systems. The Company also incurs trucking costs on the portion of its oil and natural gas liquids production that is not pipeline connected. Transportation expenses totaled $1.1 million or $1.25 per boe in the fourth quarter of 2014 ($0.5 million or $1.61 per boe for the comparative period in the prior year). The decrease in transportation costs is due to the reduced reliance on trucking to deliver liquids production to sales points as more volume was transported via pipeline. Transportation costs increased year over year from $1.83 per boe for the year ended December 31, 2013 to $1.94 per boe for the same period in 2014. The increase is due to increased trucking costs as well as pipeline facility constraints that led to higher volumes being trucked to sales delivery points in the first half of 2014. General and Administrative Expenses The following table illustrates the Company’s general and administrative expenses which are shown net of capitalized costs directly related to exploration and development activities: General and Administrative Expenses ($000s) Gross general and administrative expense Capitalized general and administrative Net general and administrative expense Share based compensation expense Capitalized share based compensation Total general and administrative expense, net Twelve months ended Dec. 31, 2014 Twelve months ended Dec. 31, 2013 Three months ended Dec. 31, 2014 Three months ended Dec. 31, 2013 6,794 (1,802) 4,992 1,483 (741) 5,734 3,367 (1,511) 1,856 1,858 (929) 2,786 2,144 (27) 2,117 459 (229) 2,347 491 91 582 349 (174) 757 Fourth quarter 2014 gross general and administration expenses (before capitalized G&A and share based compensation), totaled $2.1 million or $2.37 per boe (compared to $0.5 million or $0.55 per boe for the fourth quarter of 2013). Petrus incurred transaction and one- time costs in the fourth quarter attributed to the corporate acquisitions and financing activities which occurred late in 2014. One-time costs totaled $1.3 million or $1.44 per boe. For the year ended December 31, 2014, the Company’s gross G&A costs (before capitalized G&A and share based compensation) were $6.8 million compared to $3.4 million incurred in 2013. The increase is due to the organic growth of the Company as well as the corporate acquisitions that occurred in the second half of 2014. Gross G&A for 2013 was $2.88 per boe and in 2014 gross G&A expenses incurred were $3.63 per boe (includes transaction and one-time costs associated with the acquisition activity of $0.59 per boe). Page | 12 Depletion and Depreciation The following table compares depletion and depreciation expenses recorded in the reporting periods: Depletion and Depreciation ($000s) Depletion Depreciation Total Depletion ($ per boe) Depreciation ($ per boe) Total ($ per boe) Twelve months ended Dec. 31, 2014 Twelve months ended Dec. 31, 2013 Three months ended Dec. 31, 2014 Three months ended Dec. 31, 2013 36,797 53 36,850 16.75 0.02 16.77 16,402 761 17,163 14.02 0.65 14.67 18,703 20 18,723 20.70 0.02 20.72 6,120 539 6,659 18.19 1.60 19.79 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 2014 of $18.7 million or $20.70 per boe, compared to the fourth quarter of 2013, when $6.1 million or $18.19 per boe was recorded. For the year ended December 31, 2014 Petrus recorded $36.9 million or $16.75 per boe related to depletion which represents a $2.08 per boe or 14% increase from $17.2 million or $14.67 per boe recorded in the prior year. The Company’s depletion and depreciation have increased from the prior year due to the increased production and reserves base (primarily attributed to acquisitions). SHARE CAPITAL The authorized share capital consists of an unlimited number of common voting shares without par value. The following table details the number of issued and outstanding instruments for the financial periods shown: Twelve months ended Dec. 31, 2014 Twelve months ended Dec. 31, 2013 Three months ended Dec. 31, 2014 Three months ended Dec. 31, 2013 (000s) Weighted average outstanding common shares Basic Diluted Outstanding instruments 86,377 140,593 Common shares 6,115 4,355 Stock options 6,408 Warrants 6,423 At March 25, 2015 the Company had 140,592,598 common shares outstanding. Subsequent to December 31, 2014 the Company issued 505,000 stock options. As at March 25, 2015 the Company had 6,620,000 and 6,422,603 stock options and performance warrants outstanding, respectively. 140,593 6,155 6,408 86,377 4,355 6,423 140,571 144,511 106,719 110,659 86,343 86,343 86,377 86,377 LIQUIDITY AND CAPITAL RESOURCES Revolving Credit Facility On July 31, 2014 the Company syndicated its existing credit facility to five institutions and structured a $100 million, committed, secured 364-day revolving plus one year term-out facility. It was comprised of a $20 million operating facility, as well as an $80 million syndicated facility. The facilities bear interest at Canadian bank prime, or at the Company’s option, Canadian bankers’ acceptances, plus applicable margin and stamping fee. The stamping fees range, depending on Petrus’ debt to EBITDA (which is: earnings before interest, taxes, depreciation and amortization as defined in the banking agreement), between 100 bps and 250 bps on Canadian bank prime borrowings and between 200 bps and 350 bps on Canadian dollar bankers’ acceptances. The undrawn portion of the facilities, are subject to a standby fee in the range of 50 bps to 87.50 bps. Concurrent with the closing of the acquisition of Arriva Energy Inc., Petrus obtained commitment from its syndicated lenders to increase its demand credit facility from $80 million to $120 million for a total combined credit facility, inclusive of the $20 million operating facility, of $140 million. At December 31, 2014, the Company had no outstanding letters of credit against the facility (December 31, 2013; Nil) and had drawn $100 million against the facility (December 31, 2013; $23.4 million). Page | 13 Concurrent with the closing of the acquisition of the Ravenwood Energy Corporation, Petrus obtained commitment from its syndicated lenders to increase its demand credit facility from $120 million to $180 million for a total combined credit facility, inclusive of the $20 million operating facility, of $200 million. The amount of the credit facility is subject to a borrowing base review performed on a semi-annual basis by the lender, based primarily on reserves and commodity prices estimated by the lenders as well as other factors. A decrease in the borrowing base could result in a reduction to the available credit facility. The next scheduled review of the borrowing base is to place on May 31, 2015. The Company has provided collateral by way of a $600 million debenture over all of the present and after acquired property of the Company. The facilities carry a financial covenant which limits the Company’s ability to borrow amounts greater than the facility limit as well as: (a) a financial covenant of PV10 to Net Secured Debt Ratio being less than 1.25 to 1.00 whereby Net Secured Debt (as defined by the banking agreement) means all amounts owing under the Credit Facility and any other secured debt of Petrus on a consolidated basis, minus restricted cash and cash equivalents and “PV10” means the discounted net present value (at a discount rate of 10%) of Petrus’ proved reserves, as adjusted for commodity swaps then in effect and (b) certain financial covenants only when any indebtedness under the second lien term facility remain outstanding which are: a. The Working Capital Ratio will not be less than 1.00 to 1.00; b. The Proved Asset Coverage Ratio will not be less than 1.25 to 1.00; and c. The PDP Asset Coverage Ratio will not be less than 1.00 to 1.00. At December 31, 2014 the Company was in compliance with financial covenants under the revolving credit facility. Term Loan Concurrent with the closing of the acquisition of Ravenwood Energy Corp., Petrus closed a $90 million second lien term loan facility with Macquarie Bank Limited (the "Macquarie Facility"). The Term Loan matures and is repayable in full 24 months following funding. Interest is due and payable monthly and accrues at a per annum rate of the (three-month) Canadian Dealer offered Rate (CDOR) plus 700 basis points. The Term Loan is subject to three financial covenants: (1) the same financial covenant of PV10 to Net Secured Debt Ratio being less than 1.25 to 1.00 as the Credit Facilities; (2) a covenant that Petrus may not, as of the effective date of each annual independent engineering reserve report and each internally prepared semi-annual internally prepared reserve report, permit the PDP to Net Secured Debt Ratio to be less than 1.00 to 1.00 where “PDP” means the present value (discounted at 10.0%) of future net revenues attributable to Petrus’ reserves and (3) Petrus' working capital ratio (current assets to current liabilities) will not be less than 1.0 to 1.0. Under the agreement, current assets are the current assets under IFRS plus any undrawn availability under the Revolving Credit Facility, less any non-cash amount required to be included in current assets as the result of the application of IFRS including non-cash commodity and interest rate hedges assets and liabilities. Current liabilities are the current liabilities under IFRS, excluding (a) non-cash obligations under GAAP including non-cash commodity and interest rate hedges assets and liabilities, and (b) the current portion of long-term Debt, including the term loan debt. The Term Loan is secured with a $250 million second lien priority interest on the same collateral as the Credit Facilities and requires a certain level of production volume to be hedged in 2015 and 2016. At December 31, 2014 the Company was in compliance with all covenants under the term loan agreement. 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 2014 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. Page | 14 CAPITAL EXPENDITURES Capital expenditures, excluding acquisitions and dispositions, totaled $53.0 million in the fourth quarter of 2014 compared to $9.7 million in the fourth quarter of the prior year. The majority of funds were invested in drilling and completions, construction of production facilities and tie-ins. During the year Petrus drilled 43 wells (29.3 net). Petrus invested $443.0 million (including acquisitions net of dispositions) in 2014, funded by cash flow from operations, debt and equity. The following table shows capital expenditures for the reporting periods indicated. All capital is presented before decommissioning obligations: Twelve months ended Dec. 31, 2014 Twelve months ended Dec. 31, 2013 Three months ended Dec. 31, 2013 Three months ended Dec. 31, 2014 ($000s) Drill and complete Oil and gas equipment Geological Land and lease Office Capitalized general and administrative Total Acquisitions/(dispositions) Total capital Gross (net) wells spud 78,543 28,433 2,630 3,170 640 1,802 115,218 327,746 442,964 43 (29.3) 44,259 9,129 698 2,177 91 2,497 58,851 (1,701) 57,150 21 (11.4) 39,423 10,389 1,202 2,152 372 (489) 53,049 195,027 248,076 14 (10.4) 3,844 3,616 97 1,421 60 698 9,736 — 9,736 1 (0.3) RESERVES The following table provides a summary of the Company’s reserves, as evaluated by third party reserve engineers: Reserves and Reserve Ratio Summary December 31, 2014(1) December 31, 2013(2) Company Interest Reserves Proved Producing Total Proved Total Proved +Probable Net Present Value Discounted at 10% Proved Producing Total Proved Total Proved +Probable (1)The Company’s December 31, 2014 reserves were evaluated by Sproule and Associates. (2)The Company’s December 31, 2013 reserves were evaluated by GLJ Petroleum Engineers and Sproule and Associates. (3)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. (4)RLI (reserve life index) is defined as total reserves by category divided by the annualized fourth quarter production. (MBoe) 5,696 8,638 14,864 ($000s) 88,804 127,454 228,083 (MBoe) 16,533 26,557 40,590 ($000s) 264,310 329,415 488,480 FD&A(3) $34.72 $31.38 $21.57 FD&A(3) $35.35 $27.44 $21.49 RLI(4) 4.6 7.3 11.2 — — — — — — — — — RLI(4) 4.2 6.4 11.0 — — — In 2014 Petrus’ total company interest reserves increased 273% to 40.6 mmboe on a proved plus probable (“P+P”) basis and 307% on a total proved basis to 26.6 mmboe. The 27.9 mmboe net reserves addition in the company interest P+P category was accomplished at an all in finding, development and acquisition (“FD&A”) cost of $21.49 per boe including future development capital (“FDC”). Page | 15 SUMMARY OF QUARTERLY RESULTS ($000s) except per share amounts Oil and natural gas revenue Transportation Net revenue Royalty expense (1) Royalty income (1) Net oil and natural gas revenue Operating expense (2) Hedging gain (loss) General and administrative expense (3) Interest expense (4) Dec. 31, 2014 Sep. 30, 2014 Jun. 30, 2014 Three months ended Mar. 31, 2014 Dec. 31, 2013 Sep. 30, 2013 Jun. 30, 2013 Mar. 31, 2013 35,574 (1,126) 34,448 (3,958) 423 30,913 (5,815) 3,371 (2,117) (1,725) 23,592 (1,303) 22,289 (4,035) 128 18,382 (4,395) (1,359) (1,446) (1,304) 26,815 (979) 25,836 (5,760) 303 20,379 (4,194) (1,496) (797) (614) 25,581 (872) 24,709 (5,387) 288 19,610 (3,727) (1,432) (634) (335) 16,939 (543) 16,396 (2,372) 155 14,179 (3,716) (409) (582) (252) 14,634 (636) 13,998 (2,276) 107 11,829 (2,460) (425) (571) (216) 13,915 (466) 13,449 (2.034) 179 11,594 (2,753) (150) (427) (216) 11,948 (491) 11,457 (2,282) 180 9,355 (3,080) (328) (276) (5) Cash flow from operations Per share – basic Net income (loss) Per share – basic Common shares (000s) Weighted average shares (000s) Total assets Net working capital (net debt) 5,566 0.06 47 0.01 86,276 86,276 184,139 (10,551) (1) The Company re-classified gross overriding royalty expense from other income to royalty expenses in the Statement of Net Income and Comprehensive Income. The comparative information has been re-classified to conform to current presentation. (2) Operating expenses are presented net of processing income and overhead recoveries. (3) General and administrative expense is presented net of capitalized G&A. (4) Interest expense is presented net of interest income. 24,627 0.18 (63,308) (0.45) 140,593 140,571 647,304 (215,049) 13,482 0.16 2,208 0.03 86,377 86,377 257,245 (51,638) 8,157 0.09 2,171 0.03 86,377 86,332 201,208 (21,558) 8,048 0.09 4,010 0.05 86,362 86,349 199,507 (15,756) 9,220 0.11 2,086 0.02 86,377 86,377 211,952 (22,288) 9,878 0.09 7,530 0.07 140,458 108,212 549,248 21,014 13,278 0.15 5,505 0.06 101,748 91,106 259,110 415 The oil and natural gas exploration and production industry is cyclical in nature. Petrus' financial position, results of operations and cash flows are affected by commodity prices and production levels. Petrus has had continued quarterly growth over the last two years as summarized in the table above. The slight decrease in production volume from the first quarter to the second quarter of 2013 was attributable to facility turnaround activity which required temporary production restrictions. Petrus' average quarterly production has increased, from 3,007 boe/d in the first quarter of 2013 to 6,032 boe/d in the fourth quarter of 2014. The production growth was equally attributable to the Corporation's exploration and development activities and acquisitions of producing properties. The Corporation's funds flow from operations was $5.7 million in the first quarter of 2013 and $24.6 million in the fourth quarter of 2014. Funds flow from operations increased with higher production levels as well as strengthened commodity prices, natural gas in particular. Commodity price improvements can enable higher reinvestment in exploration, development and acquisition activities in future periods as they increase the funds received from operations. Commodity price reductions reduce revenues received and can challenge the economics of the Corporation's development program as the quantity of reserves may not be economically recoverable. Petrus' reinvestment in future reserves will be dependent on its ability to obtain debt and equity financing as well as the funds it receives from operations. CRITICAL ACCOUNTING ESTIMATES 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 Page | 16 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. 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. ACCOUNTING POLICIES AND NEW STANDARDS Significant accounting policies The Company’s significant accounting policies can be read in note 3 to the Company’s audited financial statements as at and for the year ended December 31, 2014. New standards and interpretations not yet adopted On January 1, 2013, the Company adopted the following new standards and amendments which became effective for periods on or after January 1, 2013: Page | 17 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. 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. IFRS 11 supersedes IAS 31 Interests in Joint Ventures and SIC 13 Jointly 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. Petrus has assessed the impact of adopting these pronouncements and has determined these standards did not have a material impact on the Company’s financial statements. In 2013, the IASB issued amendments to IAS 36 “Impairment of Assets” which reduce the circumstances in which the recoverable amount of CGUs is required to be disclosed and clarify the disclosures required when an impairment loss has been recognized or reversed in the period. The amendments are to be adopted retrospectively for fiscal years beginning January 1, 2014. Petrus will adopt these amendments effective January 1, 2014. The adoption will impact disclosures in the notes to the financial statements only in periods when an impairment loss or impairment reversal is recognized. Levies In May 2013, the IASB issued IFRIC 21 Levies, which clarifies that an entity recognizes a liability for a levy when the activity that triggers payment, as identified by the relevant legislation, occurs. No liability should be recognized before the specified minimum threshold to trigger that levy is reached. IFRIC 21 is required to be adopted retrospectively for fiscal years beginning January 1, 2014, with earlier adoption permitted. Petrus is currently assessing whether these changes will have an effect on its financial statements. 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. Page | 18 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 the notes to the audited financial statements as at and for the twelve months ended December 31, 2013. 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. 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 nine 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 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 Page | 19 mcf/d mmbbls mmboe mmcf mmcf/d NGLs USD WTI 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 Cover page photo credit: Alain Sleigher Photography Page | 20 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 sheets as at December 31, 2014 and 2013, and the statements of net income (loss) and comprehensive income (loss), changes in shareholders’ equity and cash flows for the years 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 audits. We conducted our audits 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 audits 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 financial position of Petrus Resources Ltd. as at December 31, 2014 and 2013 and its financial performance and its cash flows for the years then ended in accordance with International Financial Reporting Standards. Chartered accountants Calgary, Canada March 25, 2015 Page | 21 BALANCE SHEETS (Expressed in 000’s of Canadian dollars) As at ASSETS Current Cash Deposits and prepaid expenses Accounts receivable (note 15) Risk management asset (note 10) Non-current Exploration and evaluation assets (notes 5 and 6) Property, plant and equipment (notes 5 and 7) LIABILITIES AND SHAREHOLDER’S EQUITY Current Bank indebtedness (note 8) Accounts payable and accrued liabilities Risk management liability (note 10) Non-Current Long term debt (note 8) Decommissioning obligation (note 9) Deferred income tax liability (note 16) Shareholders’ Equity Share capital (note 11) Contributed surplus Retained earnings (deficit) See accompanying notes to the financial statements Commitments (note 21) Approved by the Board of Directors, (signed) “Don T. Gray” Don T. Gray Chairman December 31, 2014 December 31, 2013 19,524 1,042 23,336 14,609 58,511 94,073 494,720 588,793 647,304 99,710 69,831 197 169,738 89,409 58,634 17,763 335,544 346,106 5,445 (39,791) 311,760 647,304 — 303 10,881 26 11,210 50,529 150,213 200,742 211,952 23,380 10,092 2,287 35,759 — 15,547 4,644 55,950 144,339 3,962 7,701 156,002 211,952 (signed) “Donald Cormack” Donald Cormack Director Page | 22 STATEMENTS OF NET INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS) (Expressed in 000’s of 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 10) EXPENSES Operating (note 18) Transportation expenses General and administrative (note 19) Share-based compensation (note 11) Finance (note 13) Exploration and evaluation expense (note 6) Depletion and depreciation (note 7) Impairment (note 7) NET INCOME (LOSS) BEFORE INCOME TAXES Deferred income tax expense (recovery) (note 16) TOTAL NET INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS) Net income (loss) per common share Basic and diluted (note 12) See accompanying notes to the financial statements Year ended December 31, 2014 Year ended December 31, 2013 112,705 (19,140) 93,565 2,182 16,393 112,140 18,129 4,279 4,992 741 4,696 1,158 36,850 104,762 175,607 (63,467) (15,975) (15,975) (47,492) 58,055 (8,963) 49,092 50 (2,806) 46,336 12,009 2,136 1,856 929 1,112 — 17,163 — 35,205 11,131 2,990 2,990 8,141 (0.45) 0.09 Page | 23 STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY (Expressed in 000’s of Canadian dollars) Balance, December 31, 2012 Net income Issuance of common shares (note 11) Premium liability of flow-through shares Share-based compensation (note 11) Tax effect of share issue costs Balance, December 31, 2013 Net income (loss) Issuance of common shares (note 11) Premium liability of flow-through shares Share-based compensation (note 11) Share issue costs Tax effect of share issue costs Balance, December 31, 2014 See accompanying notes to the financial statements Share Capital Contributed Surplus Retained Earnings (Deficit) Total 144,119 — 216 (14) — 18 144,339 — 205,571 (235) — (4,759) 1,190 346,106 2,103 — — — 1,859 — 3,962 — — — 1,483 — — 5,445 (440) 8,141 — — — — 7,701 (47,492) — — — — — (39,791) 145,782 8,141 216 (14) 1,859 18 156,002 (47,492) 205,571 (235) 1,483 (4,759) 1,190 311,760 Page | 24 STATEMENTS OF CASH FLOWS (Expressed in 000’s of Canadian dollars) Funds generated by (used in): OPERATING ACTIVITIES Net income (loss) Adjust items not affecting cash: Share-based compensation (note 11) Unrealized hedging (gains) losses (note 10) Finance expenses (note 13) Depletion and depreciation (note 7) Impairment (note 7) Exploration and evaluation expense (note 6) Gain on disposition (note 5) Deferred income tax expense (recovery) (note 16) Decommissioning expenditures Funds generated by operations Change in operating non-cash working capital (note 17) Cash provided by operations FINANCING ACTIVITIES Issuance of common shares (note 11) Share issue costs (note 11) Increase in bank indebtedness Increase in long term debt Debt transaction costs Cash provided by financing activities INVESTING ACTIVITIES Property and equipment (acquisitions) dispositions (note 5) Corporate acquisitions (note 5) Exploration and evaluation asset expenditures (note 6) Petroleum and natural gas property expenditures (note 7) Other capital expenditures Change in investing non-cash working capital (note 17) Cash used in investing activities Increase (decrease) in cash Cash, beginning of year Cash, end of year Cash interest paid Cash taxes paid See accompanying notes to the financial statements Page | 25 Year ended December 31, 2014 Year ended December 31, 2013 (47,492) 742 (17,311) 691 36,850 104,762 1,158 (2,175) (15,975) (1,096) 60,154 20,834 80,988 205,571 (4,759) 73,097 90,000 (881) 363,028 (29,746) (298,000) (6,654) (107,922) (642) 18,472 (424,492) 19,524 — 19,524 4,004 — 8,141 929 1,495 373 17,163 — — — 2,990 — 31,091 (4,853) 26,238 215 — 23,380 — — 23,595 1,701 — (5,197) (52,834) (91) (5,001) (61,422) (11,589) 11,589 — 661 — 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. On October 8, 2014 Petrus amalgamated its two wholly owned subsidiaries, Arriva Energy Inc. and Ravenwood Energy Corp. 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. The Company’s head office is located at 2400, 240 – 4th Avenue SW, Calgary, Alberta Canada. These financial statements report the twelve months ended December 31, 2014 and comparative periods and were approved by the Company’s Audit Committee March 25, 2015. 2. BASIS OF PRESENTATION (a) Statement of Compliance These financial statements have been prepared by management in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”). The policies applied in these financial statements are based on IFRS guidance issued and outstanding as of March 25, 2015." (b) Measurement Basis These financial statements were prepared on the basis of historical cost except for financial derivatives and share based payments which are measured at fair value. This method is consistent with the method used in prior years. The financial statements are presented in Canadian dollars. (c) Critical Accounting Estimates 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 (“CGUs”), based on separately identifiable and largely independent cash inflows. The determination of the Company’s CGUs 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 value less costs of disposal. 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 Page | 26 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. Financial Instruments Financial instruments are subject to valuations at the end of each reporting period. Generally the valuation is based on active and efficient markets. However, certain financial instruments may not be traded on an efficient market or the market may disappear or be subject to conditions that impede the efficiency of the market. 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. 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. Income taxes are subject to measurement uncertainty. 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) 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, processing income and gains on disposition. (b) 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, including any directly attributable general and administration costs and share-based payments 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 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 Page | 27 expected to arise from the continued use of the asset. Any gain or loss arising from the 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. 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 on the balance sheet at cost less accumulated depreciation. Depreciation is calculated on a declining balance method so as to write off the cost of these assets, less estimated residual values, over their estimated useful lives consistent with the treatment used for tax purposes. Impairment 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 of disposal, and value in use. Each CGU is identified in accordance with IAS 36, Impairment of Assets. Petrus’ property, plant and equipment are grouped into CGUs 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 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 recoverable amount is the higher of fair value, less costs of disposal, and the value-in-use. Fair value, less costs of disposal, 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. (c) 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). Depletion & depreciation 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). 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 Page | 28 by grouping the exploration and evaluation assets with property, plant and equipment CGUs to which they belong for impairment testing. The equivalent combined carrying value of the CGUs is compared against the recoverable amount of the CGUs and any resulting impairment loss is written off to net income (loss). The recoverable amount is the greater of fair value, less costs of disposal, or value-in-use. (d) 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. (e) 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 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. (f) Finance expenses Finance expense may be comprised of interest expense on borrowings, acquisition related (transaction) costs, foreign exchange expenses and accretion of the discount on decommissioning obligations. (g) Financial instruments Non-derivative financial instruments Non-derivative financial instruments are comprised of cash, 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 is classified as a financial asset at fair value. 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. Risk Management Contracts The Company enters into risk management contracts in order to manage its exposure to market risks from fluctuations in commodity prices, foreign exchange rates and interest rates in the normal course of operations. Petrus has not designated its risk management contracts as effective hedges, and thus has not applied hedge accounting, even though it considers most of these contracts to be economic hedges. As a result, all risk management contracts are classified as fair value through profit or loss and are recorded at fair value on the balance sheet with changes in fair value recorded in the statement of income (loss) and comprehensive income (loss). The fair values of these derivative instruments are generally based on an estimate of the amounts that would be paid or received to settle these instruments at the balance sheet date. (h) 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. Page | 29 (i) 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. (j) 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. (k) Joint interests A portion of the Company’s exploration, development and production activities are conducted jointly with others through unincorporated joint ventures. These financial statements reflect only the Company’s proportionate interest of these joint operations and the proportionate share of the relevant revenue and related costs. (l) 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. (m) 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. (n) New standards and interpretations On January 1, 2014, the Company adopted the following new standards and amendments which became effective for periods on or after January 1, 2014: Amendments to IAS 32, “Financial Instruments: Presentation”: The amendments clarify that the right to offset financial assets and liabilities must be available on the current date and cannot be contingent on a future event. IAS 32 does not impact the Company’s financial statements. Amendments to IAS 36 “Impairment of Assets.” The amendment reduces the circumstances in which the recoverable amount of CGUs is required to be disclosed and clarifies the disclosures required when an impairment loss has been recognized or reversed in the period. Petrus adopted these amendments effective January 1, 2014. The adoption impacted disclosures in the notes to the financial statements as an impairment loss was recognized. IFRIC 21, “Levies”: which clarifies that an entity recognizes a liability for a levy when the activity that triggers payment, as identified by the relevant legislation, occurs. The adoption of IFRIC 21 did not result in any changes to the accounting for levies by the Company. Page | 30 Future accounting standards and interpretations IFRS 9 Financial Instruments – IFRS 9 Financial Instruments – On July 24, the IASB issued IFRS 9 “Financial Instruments” (“IFRS 9”) to replace IAS 39, “Financial Instruments: Recognition and Measurement”. IFRS 9 is effective for years beginning on or after January 1, 2018. Early adoption is permitted if IFRS 9 is adopted in its entirety at the beginning of a fiscal period. The Company is currently evaluating the impact of adopting IFRS 9 on the financial statements. In May, 2014 the IASB published IFRS 15, “Revenue from Contracts with Customers” (“IFRS 15”) replacing IAS 11, “Construction Contracts”, IAS 18, “Revenue” and several revenue related interpretations. IFRS 15 establishes a single revenue recognition framework that applies to contracts with customers. The standard requires an entity to recognize revenue to reflect the transfer of goods and services for the amount it expects to receive when control is transferred to the purchaser. Disclosure requirements have also been expanded. The new standard is effective for annual periods beginning on or after January 1, 2017. The Company is currently evaluating the impact of adopting IFRS 15 on the 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. The fair value less cost to sell value used to determine the recoverable amount of the impaired petroleum and natural gas properties are classified as Level 3 fair value measurements. Refer to “Financial Instruments” section below for fair value hierarchy classifications. 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 balance sheets 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. Financial Instruments The fair value of cash, deposits, accounts receivable, accounts payable and bank indebtedness approximate their carrying amount due to the short term nature of the instrument. The Company’s fair value measurements 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. 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, 2014. Page | 31 $000s Financial Assets Fair value of financial instruments Financial Liabilities Fair value of financial instruments 5. ACQUISITIONS AND DISPOSITIONS a. Property acquisitions and dispositions (i) Business combination Carrying Amount As at December 31, 2014 Level 1 Fair Value Level 2 Level 3 14,609 14,609 197 197 — — 14,609 197 — — On February 28, 2014 Petrus closed an acquisition of petroleum and natural gas assets in the central Alberta foothills, for total cash consideration of $19.1 million, net of adjustments. 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. The acquisition was financed by way of the Company’s revolving credit facility. Acquisition related costs, which relate to professional fees, are charged to finance expenses in the Statement of Net Income (Loss). Petrus obtained resource tax pools equal to the total net assets acquired of $19.1 million. Neither deferred tax nor goodwill was recorded in conjunction with the acquisition. The following table summarizes the net assets acquired pursuant to the acquisition: Fair value of net assets acquired $000s Exploration and evaluation assets Petroleum and natural gas properties and equipment Decommissioning obligations Total net assets acquired 5,446 17,058 (3,391) 19,113 From the date of acquisition to December 31, 2014, the assets contributed approximately $6.9 million of revenue and $4.1 million of operating income. If the acquisition had taken place at January 1, 2014, the proforma incremental revenue and operating income (defined as revenue, net of royalties, less operating and transportations costs) of the Company for the twelve months ended December 31, 2014 would have been approximately $8.9 million and $5.3 million, respectively. The proforma information is not necessarily indicative of the results of operations that would have resulted had the acquisitions been effective ono the dates indicated, or future results. (ii) Royalty interest disposition On August 29, 2014 Petrus closed the disposition of non-core royalty interest properties for total cash consideration of $4.2 million after post-closing adjustments. The Company recorded a gain of $2.2 million on the divestiture during the twelve months ended December 31, 2014. (iii) Business combination On September 5, 2014 Petrus closed an acquisition of petroleum and natural gas assets in the Ferrier area of Alberta and on November 7, 2014 Petrus closed a minor acquisition of petroleum and natural gas assets in the Peace River area of Alberta, for total cash consideration of $14.9 million, net of adjustments. The transactions were accounted for as business combinations using the acquisition method whereby the net assets acquired and the liabilities assumed were recorded at fair value. The acquisitions were financed by way of the Company’s revolving credit facility. Acquisition related costs, which relate to professional fees, are charged to finance expenses in the Statement of Net Income (Loss). Petrus obtained resource tax pools equal to the total net assets acquired of $14.9 million. Neither deferred tax nor goodwill was recorded in conjunction with the acquisition. The following table summarizes the net assets acquired pursuant to the acquisition: Fair value of net assets acquired $000s Exploration and evaluation assets Petroleum and natural gas properties and equipment Decommissioning obligations Total net assets acquired 10,864 7,703 (3,695) 14,872 From the date of acquisition to December 31, 2014, the assets contributed approximately $0.7 million of revenue and $0.4 million of operating income. If the acquisition had taken place at January 1, 2014, the proforma incremental revenue and operating income (defined as revenue, net of royalties, less operating and transportations costs) of the Company for the twelve months ended December 31, 2014 would have been approximately $2.4 million and Page | 32 $1.6 million, respectively. The proforma information is not necessarily indicative of the results of operations that would have resulted had the acquisitions been effective ono the dates indicated, or future results. 5. ACQUISITIONS AND DISPOSITIONS b. Corporate acquisitions and dispositions (i) Arriva Energy Inc. On September 8, 2014 Petrus acquired all of the issued and outstanding shares of Arriva Energy Inc. (“Arriva”) at a price of $2.05 per share. As consideration Petrus paid $103 million in cash by way of its revolving credit facility. Transaction costs of $0.2 million were charged to general & administrative expenses. Arriva was a privately held entity with oil and natural gas operations in the Ferrier area of Alberta, Canada. Petrus acquired the business in order to establish a core operating area in this geographic location as well as to provide accretive, liquids rich natural gas weighted petroleum and natural gas assets to Petrus. Results from Arriva operations are included in the Company’s consolidated financial statements from the closing date of the transaction. Petrus obtained the tax base of the identifiable assets and liabilities of Arriva at pre-acquisition amounts and obtained tax basis for the cost of the shares acquired. No goodwill was recorded in connection with the acquisition. The temporary differences gave rise to an $18.5 million deferred tax liability. The acquisition has been accounted for using the acquisition method based on fair values. The deferred tax liability is based upon information available at the time and may be subject to change in a future period: Fair value of net assets acquired $000s Accounts receivable Other current assets Current liabilities Petroleum and natural gas properties and equipment Exploration and evaluation assets Bank debt Decommissioning obligations Deferred income tax liability Risk management liability Total net assets acquired Cash consideration Excess of net assets acquired over consideration 593 1,520 (1,042) 113,908 8,809 — (2,330) (18,450) (8) 103,000 103,000 — From the date of acquisition to December 31, 2014, the acquisition contributed approximately $5.7 million of revenue and $3.7 million of operating income. If the acquisition had taken place at January 1, 2014, the proforma incremental revenue and operating income defined as revenue, net of royalties, less operating and transportations costs of the Company for the twelve months ended December 31, 2014 would have been approximately $15.0 million and $10.1 million, respectively. The proforma information is not necessarily indicative of the results of operations that would have resulted had the acquisitions been effective on the dates indicated, or future results. Page | 33 (ii) Ravenwood Energy Corp. On October 8, 2014 Petrus acquired all of the issued and outstanding common shares of Ravenwood for $195 million, inclusive of debt and transaction costs. Ravenwood was a privately held entity with oil and natural gas operations in the Thorsby and Pembina areas of Alberta, Canada and was controlled by a shareholder of Petrus. Petrus acquired the business in order to establish a core operating area in this geographic location as well as to provide accretive, oil weighted petroleum and natural gas assets to Petrus. Transaction costs of $0.4 million were incurred in conjunction with the acquisition and relate to professional service fees. These transaction costs were recorded in the Statement of Net Income (Loss) as general & administrative 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. The acquisition was financed by way of a Term Loan (note 8) as well as proceeds from the Company’s equity issuances (note 11). The acquisition has been accounted for using the acquisition method based on the information available at the date of these financial statements. The amounts may be subject to change in a future period: Fair value of net assets acquired $000s Cash Accounts receivable Other current assets Risk management asset Current liabilities Petroleum and natural gas properties and equipment Exploration and evaluation assets Bank debt Decommissioning obligations Deferred income tax liability Risk management liability Total net assets acquired Cash consideration Excess of net assets acquired over consideration 30,703 7,177 1,191 177 (22,429) 226,524 12,706 (28,249) (20,169) (11,825) (806) 195,000 195,000 — From the date of acquisition to December 31, 2014, the acquisition contributed approximately $13 million of revenue and $8.9 million of operating income. If the acquisition had taken place at January 1, 2014, the proforma incremental revenue and operating income defined as revenue, net of royalties, less operating and transportations costs of the Company for the twelve months ended December 31, 2014 would have been approximately $55.2 million and $43.7 million, respectively. The proforma information is not necessarily indicative of the results of operations that would have resulted had the acquisitions been effective ono the dates indicated, or future results. 6. EXPLORATION AND EVALUATION ASSETS The components of the Company’s Exploration and Evaluation assets are as follows: $000s Balance, December 31, 2012 Additions Capitalized G&A and share-based compensation Transfers to property, plant and equipment Balance, December 31, 2013 Additions Property acquisitions (note 5) Corporate acquisitions (note 5) Exploration and evaluation expense Capitalized G&A and share-based compensation Transfers to property, plant and equipment Balance, December 31, 2014 45,791 4,442 1,220 (924) 50,529 5,753 16,310 21,514 (1,158) 1,272 (147) 94,073 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. For the year ended December 31, 2014 the Company incurred $1.2 million of exploration and evaluation expense in the Statement of Net Income (Loss) and Comprehensive Income (Loss) which relates to expiring undeveloped land in non-core properties (2013 - $Nil). During the year ended December 31, 2014 the Company capitalized $1.3 million (2013 - $1.2 million) of general & administrative expenses (“G&A”) directly attributable to exploration activities. Included in this amount is non-cash share-based compensation of $0.3 million (2013 - $0.5 million). Page | 34 7. PROPERTY, PLANT AND EQUIPMENT $000s Balance, December 31, 2012 Cash additions Acquisitions (dispositions) Capitalized G&A and share-based compensation Transfers from exploration and evaluation assets Depletion & depreciation Change in decommissioning provision Balance, December 31, 2013 Additions Property acquisitions (note 5) Property (dispositions) (note 5) Corporate acquisitions (note 5) Capitalized G&A and share-based compensation Transfers from exploration and evaluation assets Depletion & depreciation Increase in decommissioning provision (note 11) Impairment loss Balance, December 31, 2014 Cost Accumulated DD&A Net book value 120,701 52,169 (1,901) 1,220 924 — 2,778 175,891 107,662 17,675 (2,880) 317,935 1,272 147 — 43,492 — 661,194 (8,715) — 200 — — (17,163) — (25,678) — — 816 — — — (36,850) — (104,762) (166,474) 111,985 52,169 (1,701) 1,220 925 (17,163) 2,778 150,213 107,662 17,675 (2,064) 317,935 1,272 147 (36,850) 43,492 (104,762) 494,720 Estimated future development costs of $199.4 million (2013 - $58.8 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, 2014 the Company capitalized $1.3 million (2013 - $1.2 million) of general & administrative expenses (“G&A”) directly attributable to development activities. Included in this amount is non-cash share-based compensation of $0.3 million (2013 - $0.5 million). At December 31, 2014, the Company recorded property, plant and equipment impairments of $104.8 million, resulting from a decline in oil and natural gas price forecasts on each of its four CGUs (Central Alberta - $60.3 million; Ferrier - $26.1 million; Peace River - $13.6 million; and Foothills - $4.8 million). The recoverable amounts of the Company’s CGUs were estimated at fair value less costs to sell, based on the net present value of pre-tax cash flows from oil and natural gas reserves, using reserve values estimated by independent reserve evaluators. The recoverable amount for each of the Company’s four CGUs was as follows: Central Alberta - $155.2 million; Ferrier - $100.2 milliion; Peace River - $59.7 million; and Foothills - $120.8 million. In calculating the net present values of cash flows from oil and natural gas reserves, the Company used a pre-tax discount rate of 12% and the following forward commodity price estimates: 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 Remainder (1) Source: Sproule Canadian price forecasts ($CDN/bbl) for Canadian Light Sweet Crude Foreign Exchange Rate Oil (CDN$/bbl)(1) 0.850 0.870 0.870 0.870 0.870 0.870 0.870 0.870 0.870 0.870 0.870 0.870 70.35 87.36 98.28 99.75 101.25 103.85 105.40 106.99 108.59 110.22 111.87 +1.5%/yr AECO Gas (CDN$/mcf) 3.32 3.71 3.90 4.47 5.05 5.13 5.22 5.31 5.40 5.49 5.58 1.5%/yr As at December 31, 2014, a one percent change in pre-tax discount rate is estimated to change the impairment by approximately $19.2 million; a $1.00/Bbl change in the price of oil is estimated to change the impairment by approximately $4.6 million; and a $0.10/mcf change in the price of natural gas is estimated to change the impairment by approximately $8.4 million. Page | 35 8. DEBT (a) Revolving Credit Facility On July 31, 2014 the Company syndicated its existing credit facility to five institutions and structured a $100 million, committed, secured 364-day revolving plus one year term-out facility. It was comprised of a $20 million operating facility, as well as an $80 million syndicated demand facility. The facilities bear interest at Canadian bank prime, or at the Company’s option, Canadian bankers’ acceptances, plus applicable margin and stamping fee. The stamping fees range, depending on Petrus’ debt to EBITDA (which is: earnings before interest, taxes, depreciation and amortization as defined in the banking agreement), between 100 bps and 250 bps on Canadian bank prime borrowings and between 200 bps and 350 bps on Canadian dollar bankers’ acceptances. The undrawn portion of the facilities, are subject to a standby fee in the range of 50 bps to 87.50 bps. Concurrent with the closing of the acquisition of Arriva Energy Inc., Petrus obtained commitment from its syndicated lenders to increase its demand credit facility from $80 million to $120 million for a total combined credit facility, inclusive of the $20 million operating facility, of $140 million. Concurrent with the closing of the acquisition of the Ravenwood Energy Corporation, Petrus obtained commitment from its syndicated lenders to increase its demand credit facility from $120 million to $180 million for a total combined credit facility, inclusive of the $20 million operating facility, of $200 million. At December 31, 2014, the Company had no outstanding letters of credit against the facility (December 31, 2013; Nil) and had drawn $100 million against the facility (December 31, 2013; $23.4 million). The amount of the credit facility is subject to a borrowing base review performed on a semi-annual basis by the lender, based primarily on reserves and commodity prices estimated by the lenders as well as other factors. A decrease in the borrowing base could result in a reduction to the available credit facility. The next scheduled review of the borrowing base is to take place on May 31, 2015. The Company has provided collateral by way of a $600 million debenture over all of the present and after acquired property of the Company. The facilities carry a financial covenant which limits the Company’s ability to borrow amounts greater than the facility limit as well as: (a) a financial covenant of PV10 to Net Secured Debt Ratio being less than 1.25 to 1.00 whereby Net Secured Debt (as defined by the banking agreement) means all amounts owing under the Credit Facility and any other secured debt of Petrus on a consolidated basis, minus restricted cash and cash equivalents and “PV10” means the discounted net present value (at a discount rate of 10%) of Petrus’ proved reserves, as adjusted for commodity swaps then in effect and (b) certain financial covenants only when any indebtedness under the second lien term facility remain outstanding which are: a. b. c. The Working Capital Ratio will not be less than 1.00 to 1.00; The Proved Asset Coverage Ratio will not be less than 1.25 to 1.00; and The PDP Asset Coverage Ratio will not be less than 1.00 to 1.00. Under the facility agreement, for purposes of the Working Capital Ratio, current assets are the current assets under IFRS plus any undrawn availability under the Revolving Credit Facility, less any non-cash amount required to be included in current assets as the result of the application of IFRS including non-cash commodity and interest rate hedges assets and liabilities. Current liabilities are the current liabilities under IFRS, excluding (a) non-cash obligations under IFRS including non-cash commodity and interest rate hedges assets and liabilities, and (b) the current portion of long-term debt, including the term loan debt. At December 31, 2014 the Company was in compliance with financial covenants under the revolving credit facility. (b) Term Loan Concurrent with the closing of the acquisition of Ravenwood Energy Corp., Petrus closed a $90 million second lien term loan facility with Macquarie Bank Limited (the "Macquarie Facility"). The Term Loan matures and is repayable in full 24 months following funding (October 1, 2016). Interest is due and payable monthly and accrues at a per annum rate of (three-month) the Canadian Dealer offered Rate (CDOR) plus 700 basis points. The Term Loan is subject to three financial covenants: (1) the same financial covenant of PV10 to Net Secured Debt Ratio being less than 1.25 to 1.00 as the Credit Facilities; (2) a covenant that Petrus may not, as of the effective date of each annual independent engineering reserve report and each internally prepared semi-annual internally prepared reserve report, permit the PDP to Net Secured Debt Ratio to be less than 1.00 to 1.00 where “PDP” means the present value (discounted at 10.0%) of future net revenues attributable to Petrus’ PDP reserves and (3) Petrus' working capital ratio (current assets to current liabilities will not be less than 1.0 to 1.0. Under the agreement, current assets are the current assets under IFRS plus any undrawn availability under the Revolving Credit Facility, less any non- cash amount required to be included in current assets as the result of the application of IFRS including non-cash commodity and interest rate hedges assets and liabilities. Current liabilities are the current liabilities under IFRS, excluding (a) non-cash obligations under IFRS including non-cash commodity and interest rate hedges assets and liabilities, and (b) the current portion of long-term debt, including the term loan debt. The Term Loan is secured with a $250 million second lien priority interest on the same collateral as the Credit Facilities and requires a certain level of production volume to be hedged in 2015 and 2016. At December 31, 2014 the Company was in compliance with all covenants of the term loan. 9. 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 2.33 percent and an inflation rate of 2 percent (December 31, 2013; 3 percent and 2 percent, respectively). Changes in estimates in 2014 are due to the decrease in discount rate from 3 percent to 2.33 percent and changes in estimated well life, (change in Page | 36 estimates in 2013 due to changes in estimated costs for abandonments and reclamations). The Company has estimated the net present value of the decommissioning obligations to be $58.6 million as at December 31, 2014 ($15.6 million at December 31, 2013). The undiscounted, uninflated total future liability at December 31, 2014 is $61.8 million ($19.7 million at December 31, 2013). The payments are expected to be incurred over the operating lives of the assets. The following table reconciles the decommissioning liability: $000s Balance, December 31, 2012 Dispositions Liabilities incurred Change in estimates Accretion expense Balance, December 31, 2013 Property acquisitions (note 5) Corporate acquisitions (note 5) Liabilities incurred Liabilities settled Change in estimates Accretion expense Balance, December 31, 2014 10. FINANCIAL RISK MANAGEMENT 12,396 (80) 749 2,109 373 15,547 7,086 22,498 7,009 (1,096) 6,899 691 58,634 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, 2014: Natural Gas Contract Period Jan. 1, 2015 to Mar. 31, 2015 Jan. 1, 2015 to Mar. 31, 2015 Jan. 1, 2015 to Mar. 31, 2015 Jan. 1, 2015 to Mar. 31, 2015 Jan. 1, 2015 to Mar. 31, 2015 Jan. 1, 2015 to Mar. 31, 2015 Jan. 1, 2015 to Mar. 31, 2015 Jan. 1, 2015 to Mar. 31, 2015 Jan. 1, 2015 to Dec. 31, 2015 Jan. 1, 2015 to Dec. 31, 2015 Jan. 1, 2015 to Mar. 31, 2015 Apr. 1, 2015 to Oct. 31, 2015 Nov. 1, 2015 to Mar. 31, 2016 Crude Oil Contract Period Jan. 1, 2015 to Dec. 31, 2015 Jan. 1, 2015 to Dec. 31,2015 Jan. 1, 2015 to Mar. 31, 2015 Apr. 1, 2015 to Dec. 31, 2015 Apr. 1, 2015 to Dec. 31, 2015 Electric Power Contract Period Jan. 1, 2015 to Dec. 31, 2015 Risk Management Asset and Liability $000s At December 31, 2013 Commodity derivatives $000s At December 31, 2014 Commodity derivatives Type Fixed price Fixed price Fixed price Fixed price Fixed price Fixed price Fixed price Fixed price Costless Collar Fixed price Fixed price Fixed price Fixed price Daily Volume Price (CAD$/GJ) 2,000 GJ 2,000 GJ 1,000 GJ 1,000 GJ 1,000 GJ 500 GJ 1,000 GJ 1,000 GJ 5,000 GJ 4,000 GJ 3,000 GJ 3,000 GJ 6,000 GJ $3.75/GJ $3.81/GJ $3.84/GJ $4.04/GJ $4.10/GJ $4.18/GJ $4.43/GJ $4.83/GJ $3.50 – 3.63/GJ $3.49/GJ $4.17/GJ $3.35/GJ $3.74/GJ Type Daily Volume Price ($/Bbl) Fixed price Fixed Price Fixed Price Fixed Price Fixed Price 200 Bbl 100 Bbl 500 Bbl 250 Bbl 250 Bbl WTI $CAD100.00/Bbl WTI $CAD 95.50/Bbl WTI $95.00-104.50/Bbl WTI $97.80/Bbl WTI $92.50-103.50/Bbl Type Annual Volume Price (CAD) Fixed price 12,264 MW $50.00/MWH Current Asset Current Liability 26 26 2,287 2,287 Current Asset Current Liability 14,609 14,609 197 197 Page | 37 Earnings Impact of Realized and Unrealized Gains (Losses) on Commodity Financial Instruments $000s Realized loss Unrealized gain (loss) Year ended Dec. 31, 2014 Year ended Dec. 31, 2013 (918) 17,311 16,393 (1,311) (1,495) (2,806) 11. SHARE CAPITAL Authorized The authorized share capital consists of an unlimited number of common voting shares without par value. Issued and Outstanding Common shares $000s except share amounts Balance, December 31, 2012 Common shares issued under private placement (a) Flow-through shares issued, net of premium (a) Tax effect of share issue costs Common shares issued under private placement (b) Balance, December 31, 2013 Common shares issued under private placement (c) Flow-through shares issued, net of premium (c) Common shares issued under private placement (d) Flow-through shares issued, net of premium (d) Common shares issued under private placement (e) Common shares issued under private placement (f) Share issue costs Tax effect of share issue costs Balance, December 31, 2014 Number of Shares Amount 86,275,633 52,655 34,024 — 14,286 86,376,598 15,256,000 115,000 17,784,724 200,000 20,725,276 135,000 — — 140,592,598 144,119 105 68 18 29 144,339 49,582 374 71,139 800 82,901 540 (4,759) 1,190 346,106 Share Issuances (a) 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 $0.2 million. Of the issuance price, $0.40 per share or $0.01 million was determined to be the premium on the flow-through shares. The issuance was made pursuant to an Exempt Offering which provided employees and key consultants an opportunity to purchase common and flow-through shares of the Company. The common shares issued are subject to a restricted hold period which expired on August 27, 2013. (b) On August 19, 2013 the Company issued 14,286 common shares at a price of $2.00 per share for gross proceeds of $0.03 million. The issuance was made pursuant to an Exempt Offering which provided employees and key consultants an opportunity to purchase common and flow- through shares of the Company. The common shares issued are subject to a restricted hold period which expired on December 19, 2013. (c) On June 2, 2014 the Company issued 15,256,000 common shares at a price of $3.25 per share and 115,000 flow-through shares at a price of $3.90 per share for total gross proceeds of $50.0 million. Of the issuance price, $0.65 per share or $0.1 million was determined to be the premium on the flow-through shares. The common shares issued were subject to a restricted hold period which expired on October 3, 2014. (d) On September 5, 2014 the Company issued 17,784,724 common shares at a price of $4.00 per share and 200,000 flow-through shares at a price of $4.80 per share for total gross proceeds of $72.1 million. Of the issuance price, $0.80 per share or $0.2 million was determined to be the premium on the flow-through shares. The common shares issued are subject to a restricted hold period which expired on January 6, 2015. (e) On September 23, 2014 the Company issued 20,725,276 common shares at a price of $4.00 per share for total gross proceeds of $82.9 million. The common shares issued are subject to a restricted hold period which expired on January 24, 2015. (f) On October 15, 2014 the Company issued 135,000 common shares at a price of $4.00 per share for total gross proceeds of $0.5 million. The common shares issued are subject to a restricted hold period which expired on February 15, 2015. SHARE-BASED COMPENSATION Performance Warrants The Company has issued performance warrants to employees, consultants and directors of the Company. Performance warrants were granted and vest based on three criteria, time (one third vest per year), market (one third vest as certain share price hurdles are achieved) and employment or service. The warrants expire five years from the date of issuance. Upon exercise of the warrants the Company may settle the obligation by issuing common shares of the Company. The shares to be offered consist of common shares of the Company`s authorized but unissued common shares. The aggregate number of shares issuable upon the exercise of all warrants granted shall not exceed 20% of the 32,113,016 issued and outstanding shares as at April 30, 2012. At December 31, 2014, 6,407,603 (December 31, 2013; 6,422,603) performance warrants were issued and outstanding. Page | 38 Balance, December 31, 2012 Forfeited or expired Granted Balance, December 31, 2013 Forfeited or expired Balance, December 31, 2014 Exercisable, December 31, 2014 Number of warrants outstanding Weighted Average Exercise Price ($) 6,422,603 (417,000) 417,000 6,422,603 (15,000) 6,407,603 3,799,564 $2.00 $2.00 $2.25 $2.02 $2.00 $2.02 $2.01 The following tables summarize information about the performance warrants granted since inception: Range of Exercise Price Warrants Outstanding Warrants Exercisable $2.00 - $2.25 Number granted 6,407,603 6,407,603 Weighted average exercise price $2.02 $2.02 Weighted average remaining life (years) Number exercisable 2.09 2.09 3,799,564 3,799,564 Weighted average exercise price $2.01 $2.01 Weighted average remaining life (years) 2.03 2.03 At December 31, 2014 there were 3,799,564 exercisable performance warrants. The weighted average fair value of each warrant granted during the current year was Nil as no warrants were granted (2013 - $0.24). The Black-Scholes pricing model uses the following weighted average assumptions (December 31): Risk free interest rate Expected life (years) Estimated volatility of underlying common shares (%) Estimated forfeiture rate Expected dividend yield (%) 2014 — — — — — 2013 1.23% 5 50% 20% 0% Petrus estimated the volatility of the underlying common shares by analyzing the volatility of peer group private companies with similar corporate structure, oil and gas assets and size. With respect to the market condition inherent in the warrants, Petrus estimated the probability of achieving the condition and applied the probability to each individual vesting tranche in order to fairly estimate the fair value of each warrant. Stock Options The Company has a stock option plan in place whereby it may issue stock options to employees, consultants and directors of the Company. The aggregate number of shares that may be acquired upon exercise of all Options granted pursuant to the plan shall, at any date or time of determination, be equal to ten percent (10%) of the number that is equal to (i) the number of the Company’s basic Common shares then issued and outstanding; minus (ii) a number equal to five (5) times the number of Common Shares that are issuable upon exercise of the then outstanding Performance Warrants minus (iii) a number equal to fifty percent (50%) of the number of Common Shares that have previously been issued upon the exercise of Performance Warrants. The options vest based on time (one third vest per year starting on the date of grant) and expire five years from the date of issuance. At December 31, 2014, 6,155,000 (December 31, 2013; 4,355,000) stock options were outstanding. The summary of stock option activity is presented below: Balance, December 31, 2012 Forfeited or expired Granted Balance, December 31, 2013 Granted Forfeited or expired Balance, December 31, 2014 Exercisable, December 31, 2014 Number of stock options Weighted Average Exercise Price ($) 3,995,000 (224,000) 584,000 4,355,000 1,805,000 (45,000) 6,115,000 2,736,666 $1.75 $1.75 $2.20 $1.84 $3.18 $1.75 $2.21 $1.78 Page | 39 The following tables summarize information about the stock options granted since inception: Range of Exercise Price Stock Options Outstanding Stock Options Exercisable $1.75 - $2.00 $2.01 - $2.75 $2.76 - $4.00 Number granted 3,875,000 1,050,000 1,190,000 6,115,000 Weighted average exercise price $1.76 $2.38 $3.50 $2.21 Weighted average remaining life (years) 2.53 4.09 4.59 3.21 Number exercisable 2,578,333 158,333 — 2,736,666 Weighted average exercise price $1.75 $2.25 — $1.78 Weighted average remaining life (years) 2.47 3.96 — 2.56 The weighted average fair value of each stock option granted of $1.12 (2013 - $0.79) 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 (%) 2014 1.20% - 1.40% 5 50% 20% 0% 2013 1.20% 5 50% 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. The following table summarizes the Company’s share-based compensation costs: $000s Expensed in net income Capitalized to exploration and evaluation assets Capitalized to property, plant and equipment Total share-based compensation 2014 2013 741 371 371 1,483 929 465 465 1,859 12. EARNINGS PER SHARE Earnings per share amounts are calculated by dividing the net income for the period attributable to the common shareholders of the Company by the weighted average number of common shares outstanding during the year. Net income (loss) for the year ($000s) Weighted average number of common shares – basic (000s) Weighted average number of common shares – diluted (000s) Net income per common share – basic Net income per common share – diluted Year ended December 31, 2014 (47,492) 106,719 106,719 (0.45) (0.45) Year ended December 31, 2013 8,141 86,377 87,238 0.09 0.09 In computing earnings per share for the twelve months ended December 31, 2014, 1,609,101 warrants and 2,331,072 stock options were considered however no instruments were added to the calculation as their impact is anti-dilutive. In computing diluted earnings per share for the twelve months ended December 31, 2013, 861,110 stock options were considered however no instruments were added to the calculation as their impact is anti- dilutive. 13. FINANCE EXPENSES The components of finance expenses are as follows: $000s Cash: Interest Acquisition related expenses Foreign exchange Non cash: Accretion on decommissioning obligations (note 9) Total finance expenses 2014 2013 4,007 233 (235) 691 4,696 739 — 373 1,112 Page | 40 14. CAPITAL MANAGEMENT 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 (refer to Note 8 for restrictions). 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, 2014, financial assets on the balance sheet are comprised of cash, deposits, 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 $23.3 million of accounts receivable outstanding at December 31, 2014 (December 31, 2013; $10.9 million), $16.6 million is owed from 19 parties (December 31, 2013 - $5.0 million from ten parties), and the majority of the balance was received subsequent to year end. The remaining amounts are expected to be collected and no allowance has been recorded. As at December 31, 2014 and December 31, 2013, 90% of Petrus’ accounts receivable were all aged less than 90 days and the Company does not anticipate any significant collection issues. The Company’s risk management assets are with chartered Canadian banks and the Company does not consider the assets to carry material credit risk. 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 balance sheet consist of accounts payable, bank indebtedness, long term debt, 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, 2014, the Company had a $200 million credit facility, of which $100 million was undrawn (December 31, 2013, the Company had a $60 million credit facility of which $36.6 million was undrawn). Petrus anticipates it will continue to have adequate liquidity to fund its financial liabilities through its future funds from operations and available bank debt. The Company is exposed to the risk of reductions to its borrowing base for purposes of the revolving credit facility or term loan. 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 accounts receivable are not exposed to significant interest rate risk. The revolving credit facility and long term debt are exposed to interest rate cash flow risk as the instruments are 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. A 1% change in the Canadian prime interest rate in the twelve months ended December 31, 2014 would have changed income by approximately $1.1 million, which relates to interest expense on the average outstanding revolving credit facility and long term debt during the period, assuming that all other variables remain constant (twelve months ended December 31, 2013 – $0.1 million). The Company considers this risk to be limited. Page | 41 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 twelve months ended December 31, 2014, it is estimated that a $0.25/mcf change in the price of natural gas would have changed net income by $1.9 million (twelve months ended December 31, 2013 - $941,153). For the twelve month period ended December 31, 2014, it is estimated that a $5.00/CDN WTI/bbl change in the price of oil would have changed net income by $4.1 million (twelve months ended December 31, 2013 - $2.6 million). 16. DEFERRED INCOME TAXES $000s 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 Other Deferred tax expense (recovery) Effective tax rate 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 $000s 2014 2013 (66,363) 25% (16,591) 680 352 (416) (15,975) 24.0% 11,131 25% 2,783 465 — (258) 2,990 26.9% 2013 (13,655) 3,887 672 3,887 565 (4,644) (44,507) 14,658 1,449 14,241 (3,603) (17,763) 17,953 (119) (540) 3,009 (4,328) 15,975 (48,805) 10,890 1,316 7,345 159 (29,094) 2013 Change through Statement of Income (Loss) Change through Balance Sheet 2012 The components of the Company’s deferred tax liability at December 31, 2014 and December 31, 2013 are as follows: $000s 2014 Change through Statement of Income (Loss) Change through Balance Sheet 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 The Company had non-capital losses of approximately $56.7 million (2013 - $15.6 million) which may be applied against future income for Canadian tax purposes. These non-capital losses expire in 2024 and onwards. (13,655) 3,887 672 3,887 565 (4,644) (3,168) 78 (260) (14) 374 (2,990) (730) 710 18 — — (2) (9,763) 3,099 913 3,901 191 (1,658) 17. SUPPLEMENTAL CASH FLOW INFORMATION The following table reconciles the changes in non-cash working capital as disclosed in the statements of cash flows: $000s Source (use) in non-cash working capital: Accounts receivable Deposits and prepaid expenses Accounts payable and accrued liabilities Working capital deficiency acquired Operating activities Financing activities Investing activities Page | 42 2014 2013 (12,455) (739) 58,858 (7,239) 38,425 20,834 (881) 18,472 769 287 (10,910) — (9,854) (4,853) — (5,001) 18. OPERATING EXPENSES The Company’s gross operating expenses for 2014 were $20.7 million (December 31, 2013; $12.7 million) which includes $7.9 million of processing, gathering and compression charges (December 31, 2013; $2.9 million). The Company generated processing income recoveries of $2.6 million (December 31, 2013; $0.7 million) which reduced the Company’s reported gross operating expenses to $18.1 million for the year ended December 31, 2014 ($12.0 million for the year ended December 31, 2013). 19. GENERAL AND ADMINISTRATIVE EXPENSES The Company’s general and administrative expenses consisted of the following expenditures: $000s Salaries and benefits Subscriptions and licenses Office costs Legal, accounting and consulting Transaction costs Capitalized general and administrative 20. RELATED PARTY TRANSACTIONS 2014 2013 3,604 490 552 1,127 1,021 (1,802) 4,992 1,885 118 674 690 (1,511) 1,856 The Company consider its directors and officers to be key management personnel. The following table outlines transactions with key management personnel: $000s Salaries and wages Short term employee benefits Share based compensation, gross 2014 2013 711 26 472 1,209 881 26 1,435 2,342 Included in share issue costs are fees of $0.3 million which relate to the Company’s September 2014 financing. The fees were paid to a company controlled by a director of Petrus. 21. COMMITMENTS The commitments for which the Company is responsible are as follows: $000s Office equipment lease Corporate office lease Total commitments 22. SUBSEQUENT EVENTS Financial Risk Management Total < 1 year 1-5 years 9 927 935 3 502 505 6 425 431 Subsequent to December 31, 2014 the Company entered into the following financial derivative contracts: Natural Gas Period Hedged Apr. 1, 2015 to Oct. 31, 2015 Nov. 1, 2015 to Mar. 31, 2016 Apr. 1, 2016 to Oct. 31, 2016 Nov. 1, 2016 to Mar. 31, 2017 Apr. 1, 2015 to Oct. 31, 2015 Nov. 1, 2015 to Mar. 31, 2016 Apr. 1, 2016 to Oct. 31, 2016 Nov. 1, 2016 to Mar. 31, 2017 Apr. 1, 2015 to Oct. 31, 2015 Nov. 1, 2015 to Mar. 31, 2016 Apr. 1, 2016 to Oct. 31, 2016 Nov. 1, 2016 to Mar. 31, 2017 Jan. 1, 2016 to Mar. 31, 2016 Apr. 1, 2016 to Oct. 31, 2016 Type Daily Volume Price (CAD$/GJ) 2,000 GJ 2,000 GJ 2,000 GJ 2,000 GJ 4,000 GJ 4,000 GJ 2,000 GJ 2,000 GJ 6,000 GJ 6,000 GJ 6,000 GJ 6,000 GJ 5,000 GJ 5,000 GJ $2.52/GJ $3.03/GJ $2.93/GJ $3.38/GJ $2.46/GJ $2.96/GJ $2.85/GJ $3.31/GJ $2.37/GJ $2.87/GJ $2.75/GJ $3.21/GJ $3.26/GJ $2.91/GJ Fixed price Fixed price Fixed price Fixed price Fixed price Fixed price Fixed price Fixed price Fixed price Fixed price Fixed price Fixed price Fixed price Fixed price Page | 43 Crude Oil Contract Period Apr. 1, 2015 to Jun. 30, 2015 Jul. 1, 2015 to Sep. 31, 2015 Jan. 1, 2016 to Dec. 31, 2016 Type Daily Volume Price ($/Bbl) Costless collar Costless collar Costless collar 2,000 Bbl 2,000 Bbl 700 Bbl WTI $USD45.00-60.10/Bbl WTI $USD45.00-66.00/Bbl WTI $CAD70.00-75.75/Bbl Share Capital On January 26, 2015 the Company granted 365,000 stock options at an exercise price of $3.50. The options vest based on time (one third vest per year) and expire five years from the date of issuance. On February 18, 2015 the Company granted 140,000 stock options at an exercise price of $3.50. The options vest based on time (one third vest per year) and expire five years from the date of issuance. Property Acquisitions and Dispositions On January 1, 2015 Petrus entered into an agreement with an industry partner to acquire petroleum and natural gas assets in the Ferrier/Strachan area of Alberta for cash consideration of $4.4 million. The acquisition closed on January 20, 2015. On January 9, 2015 Petrus entered into an agreement with a third party oil and gas company to acquire petroleum and natural gas assets, to acquire additional assets in the Ferrier/Strachan area of Alberta. Concurrent with the acquisition of these assets, Petrus entered into an agreement with the same industry partner to dispose of petroleum and natural gas assets in the Pembina area of Alberta. Petrus received total net consideration of $3.7 million pertaining to these transactions. Page | 44 CORPORATE INFORMATION OFFICERS Kevin L. Adair, P. Eng. President and Chief Executive Officer DIRECTORS Don T. Gray Chairman Calgary, Alberta SOLICITOR Burnet, Duckworth & Palmer LLP Calgary, Alberta Neil Korchinski, P. Eng. Vice President, Engineering and Chief Operating Officer Kevin L. Adair Calgary, Alberta AUDITOR Ernst & Young LLP Chartered Accountants Calgary, Alberta Cheree Stephenson, CA Vice President, Finance and Chief Financial Officer Patrick Arnell Calgary, Alberta INDEPENDENT RESERVE EVALUATORS Sproule and Associates Calgary, Alberta Peter Verburg Corporate Secretary Donald Cormack Calgary, Alberta Brian Minnehan Irving, Texas Peter Verburg Calgary, Alberta BANKERS TD Securities Calgary, Alberta Macquarie Bank Limited Houston, Texas 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 | 45 

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