Financial Report Second Quarter 2018

Transcription

1 Financial Report Second Quarter

2 Management s Discussion and Analysis August 9, 2018 This Management s Discussion and Analysis ( MD&A ) of financial condition and results of operations for Eagle Energy Inc. ( Eagle ), dated August 9, 2018, should be read in conjunction with Eagle s unaudited condensed consolidated interim financial statements and accompanying notes for the three months and six months ended ( Interim Financial Statements ) and Eagle s audited consolidated financial statements and accompanying notes and related MD&A for the year ended December 31, 2017 and Eagle s Annual Information Form dated March 20, 2018 ( AIF ), which are available online under Eagle s issuer profile at and on Eagle s website at The Interim Financial Statements have been prepared in accordance with International Financial Reporting Standards ( IFRS ). Items included in the financial statements of Eagle and each of its subsidiaries are measured using the currency of the primary economic environment in which the entity operates (the functional currency ). The Interim Financial Statements are presented in Canadian dollars, which is the functional and presentation currency of Eagle. Figures within this MD&A are presented in Canadian dollars unless otherwise indicated. The foreign exchange rate at was $US 1.00 equal to $CA 1.32 (December 31, $US 1.00 equal to $CA 1.25), and the average foreign exchange rate for the six months ended was $US 1.00 equal to $CA 1.28 (for the six months ended - $US 1.00 equal to $CA 1.33). Throughout this MD&A, Eagle and its subsidiaries are collectively referred to as Eagle for purposes of convenience. In addition, references to the results of operations refer to operations of Eagle s subsidiaries in the U.S. and in Canada. This MD&A contains information that is forward-looking and refers to non-ifrs financial measures. Investors should read the Note about Forward-Looking Statements and Non-IFRS Financial Measures sections at the end of this MD&A. Financial data other than non-ifrs financial measures has been prepared in accordance with IFRS. Overview of Eagle Eagle Energy Inc. ( Eagle ) is an Alberta corporation. Its common shares are widely held and listed for trading on the Toronto Stock Exchange under the symbol EGL. Eagle is engaged in the acquisition, exploration and production of petroleum and natural gas reserves in Alberta, Canada and Texas, United States. This MD&A discusses Eagle s operating segments in the United States and Canada, in addition to its Corporate segment. The United States segment relates to Eagle s assets in Texas and the Canadian segment relates to Eagle s 1

3 assets in Alberta. The Corporate segment includes expenditures related to Eagle s hedging program, public company, and other expenses incurred in the overall financing and administration of Eagle. Highlights for the ended Field netback improved by 28% on a per barrel of oil equivalent ( boe ) basis (from $22.94 to $29.26 per boe) when compared to the second quarter of General and administrative expenses to the end of June 2018, excluding one-time costs associated with the Salt Flat disposition, are 34% lower than Long term debt at the end of the second quarter is 34% lower than at 2017 year end ($US 38.5 million compared to $US 58.2 million). Sale of Twining Assets On July 20, 2018, and further to Eagle s previously announced strategy of reducing debt and interest charges, Eagle announced that it has signed an agreement to sell its entire interest in its oil and gas properties near Twining, Alberta to a third party for cash consideration of $13,820,000 before customary post-closing adjustments (the Sale ). The Sale is expected to close on or about August 28, Eagle intends to use the net proceeds from the Sale to reduce outstanding debt under its secured term loan and to further fund its North Texas development program. The Sale will reduce leverage, increase corporate field netback per boe and lower Eagle s corporate decline rate Outlook This outlook section is intended to provide shareholders with information about Eagle s expectations for This information constitutes forward-looking information. Readers should note the assumptions, risks and discussions under Note about Forward-Looking Statements at the end of this MD&A. Readers are cautioned that the information may not be appropriate for any other purpose. For 2018, Eagle plans to: Continue to focus on drilling wells on its North Texas property with its opportunities for meaningful growth and high netbacks. Eagle holds over 25,000 net acres on contiguous leases held in six different areas across Hardeman County that are prospective for horizontal development. Eagle plans to spud its third horizontal well in the third quarter of 2018 approximately one mile from the location of its initial horizontal well, a well which has exceeded production expectations. North Texas oil sells at par to WTI, while many producers in the Permian face negative WTI differentials. Continue to reduce debt and corporate costs, including interest costs, in order to better position Eagle to capitalize the North Texas development program. Alternatives for funding growth include asset sales. The February 2018 Salt Flat disposition and the July 2018 announced Sale are steps towards achieving Eagle s overall goals. Eagle has reduced its term loan by 34% from the end of 2017 to the end of June 2018 (from $US 58.2 million to $US 38.5 million) and intends to use the net proceeds from the Sale closing in August 2018 to further reduce debt. On a go-forward basis, lower debt leads to reduced monthly interest costs. Continue to reduce general and administrative expenses by focusing on efficiencies and cost reduction. General and administrative expenses to the end of June 2018, excluding one-time costs associated with the Salt Flat disposition, are 34% lower than

4 Consolidated Results of Operations Production Working interest (boe/d) 2,123 3,766 (44) 2,446 3,656 (33) Royalty interest (boe/d) (31) (19) Total (boe/d) 2,262 3,966 (43) 2,617 3,867 (32) The oil weighting (81% oil, 5% natural gas liquids ( NGLs ), 14% natural gas) has decreased when compared to the 2017 periods (84% oil, 4% NGLs and 12% natural gas) due to the February 2018 Salt Flat disposition. Working interest production decreased for the three and six-month periods due to this disposition, but natural declines were offset by additional production from wells drilled in Eagle s Twining and North Texas areas in Average Daily Production by Product Type Working Interest Oil (bbl/d) 1,707 3,287 (48) 1,984 3,194 (38) Natural gas (Mcf/d) 1,940 2,239 (13) 2,108 2,158 (2) NGLs (bbl/d) (12) Oil equivalent sales volumes 6:1) 2,123 3,766 (44) 2,446 3,656 (33) Royalty Interest Oil (bbl/d) (26) (24) Natural gas (Mcf/d) (38) (21) NGLs (bbl/d) (12) (6) Oil equivalent sales volumes 6:1) (31) (19) Total Oil (bbl/d) 1,746 3,340 (48) 2,026 3,249 (38) Natural gas (Mcf/d) 2,357 2,915 (19) 2,673 2,877 (7) NGLs (bbl/d) (12) Oil equivalent sales volumes 2,262 3,966 (43) 2,617 3,867 (32) 3

5 Revenue $000 s Working Interest Revenue Oil 11,620 16,928 (31) 25,607 33,509 (24) Natural gas (51) 781 1,155 (32) NGLs Other (58) (50) Royalty Interest Revenue 12,378 18,049 (31) 27,444 35,723 (23) Oil Natural gas (92) (61) NGLs Other Total Revenue (6) (11) Oil 11,882 17,155 (31) 26,123 34,010 (23) Natural gas (57) 890 1,434 (38) NGLs , Other (58) (50) 12,793 18,489 (31) 28,327 36,711 (23) Product Prices Realized Prices Oil ($/bbl) Natural gas ($/Mcf) (48) (33) NGLs ($/bbl) Other ($/bbl) (25) (25) Revenue ($/boe) Benchmark prices WTI crude oil ($US/bbl) Exchange rate ($CA/$US) (4) (4) Edmonton Par crude oil ($CA/bbl) NYMEX Gas ($US/Mcf) (10) (8) AECO natural gas ($CA/Mcf) (57) (41) Eagle s revenue for the three and six months ended was 93% derived from oil, similar to the three and six months ended. When compared to the 2017 periods, realized oil prices in Canadian dollars for the three and six months ended increased due to a higher benchmark West Texas Intermediate ( WTI ) crude oil price. The realized price increase is lower than the WTI increase due to differentials in Canadian crude oil and a higher proportion of production coming from Canada. 4

6 For Eagle s U.S. properties, there is a quality differential between the benchmark $US WTI price and the $US price realized by Eagle. Eagle enters into field marketing contracts to obtain predictable pricing. Management monitors pricing regularly and endeavours to maximize realized sales prices while minimizing counterparty risk. For the North Texas properties, field marketing contracts are on a month-to-month term using WTI as a reference price and holding all other field pricing adjustments fixed while letting the Argus P+ differential to float. For the Dixonville properties in Canada, the entire differential to WTI, including quality and transportation, has narrowed from the first quarter of 2018 to be a discount of approximately $CA per barrel in the second quarter of 2018 ($CA per barrel in the second quarter of 2017). For the first quarter of 2018, Dixonville differentials were $CA per barrel. For the Twining properties in Canada, the entire differential to WTI, including quality and transportation, has narrowed from the first quarter of 2018 to be a discount of approximately $CA per barrel in the second quarter of 2018 ($CA per barrel in the second quarter of 2017). For the first quarter of 2018, differentials for Twining were $CA per barrel. The above prices do not include realized gains or losses from financial commodity contracts, which amounted to a loss of $1.2 million ($5.97/boe) for the three months ended and $1.8 million ($3.89/boe) for the six months ended. See Realized and Unrealized Risk Management Loss (Gain). Royalties Total royalties ($000 s) (1) 2,565 4,322 (41) 5,638 8,326 (32) $/boe (2) Royalty rate on working interest sales 21% 24% (13) 21% 23% (12) Notes: (1) There are no royalty expenses associated with royalty interest volumes. (2) Total $/boe amounts are calculated using total working interest and royalty interest volumes. The overall royalty rate for the three and six months ended was lower than the prior year comparative periods as the relative production from U.S. properties decreased due to the February 2018 Salt Flat disposition. As well, the average royalty rate at Salt Flat was higher than at North Texas. Canadian production for the second quarter of 2018 is 74% of corporate production (56% in the second quarter of 2017), and since Canadian properties had an average royalty rate of 19% in the second quarter of 2018 (18% in the second quarter of 2017), the corporate royalty rate has dropped. For the U.S. properties, the average royalty rate was 23% for the second quarter of 2018 (28% for the second quarter of 2017). For the six months ended, Canadian production accounts for 66% of total production (52% for the six months ended ). Canadian properties had an average royalty rate of 17% in the first half of 2018 while the U.S. properties had an average royalty rate of 24% in the first half of The sliding scale nature of royalties paid on Canadian properties affects the royalty rate. Crown royalty rates in Alberta depend on four components: (i) production volumes; (ii) Alberta PAR commodity prices; (iii) product density; and (iv) if wells qualify for royalty holidays. Alberta PAR commodity prices reflect market prices. Royalty rates for Eagle s U.S. properties do not fluctuate with underlying commodity prices and production rates. 5

7 Operating Expenses Total operating expenses ($000 s) (1) Operating expenses 3,716 5,349 (31) 8,266 12,047 (31) Transportation and marketing expenses (9) 1,049 1,003 5 ($/boe) (2) 4,206 5,885 (29) 9,315 13,050 (29) Operating expenses Transportation and marketing expenses Notes: (1) There are no operating costs associated with royalty interest volumes. (2) Total $/boe amounts are calculated using total working interest and royalty interest volumes For the six months ended, operating expenses (inclusive of transportation and marketing expenses) of $9.3 million are comprised primarily of oil transportation (9%), fuel (8%), power (8%), field salaries (6%) and chemicals (6%). For the six months ended, operating expenses (inclusive of transportation and marketing expenses) of $13.1 million were comprised primarily of power (20%), field salaries (7%), chemicals (7%), oil transportation (6%) and fuel (5%). The quarter-over-quarter and year-over-year decrease in total operating costs is primarily due to the disposition of Salt Flat. For the six months ended, the 5% increase in per boe operating expenses on a year-over-year basis is due to higher well servicing activity in Dixonville. For the three months ended, the 25% increase in per boe operating expenses is due to higher well servicing activity in Dixonville and well work overs in North Texas. Field Netback $000 s $/boe $000 s $/boe $000 s $/boe $000 s $/boe Revenue 12, , , , Royalties (2,565) (12.46) (4,322) (11.98) (5,638) (11.90) (8,326) (11.90) Operating expenses (3,716) (18.05) (5,349) (14.82) (8,266) (17.45) (12,047) (17.22) Transportation and marketing expenses (490) (2.38) (536) (1.49) (1,049) (2.22) (1,003) (1.43) Field netback 6, , , , Sales volumes (boe/d) 2,262 3,966 2,617 3,867 During the second quarter of 2018, Eagle averaged revenue of $62.15 per boe and realized a field netback of $29.26 per boe compared to revenue of $51.23 per boe and field netback of $22.94 per boe in the second quarter of Field netback per boe is higher on a quarter-over-quarter basis due to increased commodity prices being only partially offset by increased per boe royalties and operating costs. For the six months ended, Eagle averaged revenue of $59.83 per boe and realized a field netback of $28.26 per boe compared to revenue of $52.46 per boe and a field netback of $21.91 per boe for the six months ended. Field netback per boe is higher year-over-year due to increased commodity prices partially offset by higher per boe operating expenses. Field netback for the first half of 2018 includes $1.7 million from Salt Flat for the period prior to the February 2018 disposition (for the first half of 2017, field netback included $7.2 million from Salt Flat). Field netback is a Non-IFRS financial measure. See Non-IFRS Financial Measures. 6

8 Administrative Expenses ($000 s) Administrative expenses 1,511 2,654 (43) 3,320 5,041 (34) Costs associated with the disposition , Total administrative expenses 1,511 2,654 (43) 4,407 5,041 (13) $/boe Administrative expenses for the three months ended are 43% below the prior year comparative period. Staffing costs, office costs and investor relations costs each decreased by $0.1 million when compared to the same period in As well, administrative expenses for the three months ended June 2017 included $0.7 million of fees associated with the 2017 annual general meeting and proxy solicitation. Administrative expenses for the six months ended are 13% below the prior year comparative period and include $1.1 million of one-time costs associated with the disposition of Salt Flat. Without the one-time costs, administrative expenses per boe would be $7.19/boe. Staff and related employment costs and office costs accounted for 65% and 11% respectively, of administrative expenses for the six months ended (six months ended 65% and 21%, respectively). Realized and Unrealized Risk Management Loss (Gain) The following contracts were in place for the six months ended : Volume Measure Beginning Term Floor $US Ceiling $US Oil Fixed Price NYMEX (1) 1,000 bbls/d Jan-18 Mar NYMEX (1) 1,000 bbls/d Apr-18 Jun Notes: (1) Represents a fixed price financial swap transaction with a set forward sale price (WTI reference prices). $000 s Realized loss (gain) 1,229 (488) (352) 1,842 1, Unrealized gain (844) (2,191) (61) (628) (8,091) (92) Net loss (gain) 385 (2,679) (114) 1,214 (6,650) (118) The net value of the contracts is dependent upon current and forward commodity pricing, and the price of the contract relative to the benchmark oil price at each balance sheet date and at the time of settlement. Eagle is required to calculate and record, using a mark-to-market valuation, the fair value of the remaining term of the contracts at the end of each reporting period, hence the change in value of the unrealized portion of the commodity contracts. During the first and second quarter of 2018, Eagle had 1,000 barrels of oil per day hedged at an average WTI price of $US During the second quarter of 2017, Eagle had 1,625 barrels of oil per day hedged at an average WTI price of $US In the first quarter of 2017, upon unwinding a contract with one of Eagle s previous bank lenders, Eagle incurred a realized loss of $1.6 million. The unrealized gain for the six months ended is the reversal of the estimated unrealized 2018 loss that was recorded as a liability at December 31, As of, there are no outstanding commodity price contracts, and therefore no risk management asset or liability on the balance sheet. 7

9 Finance Expense Finance expense ($000 s) 1,792 2,285 (22) 3,731 3,717 - Finance expense associated with the partial prepayment of long-term debt , Total finance expense 1,792 2,285 (22) 6,844 3, $/boe For the three and six months ended, the effective interest rates, excluding the one-time finance costs associated with the prepayment of the term loan, but including amortization costs associated with securing the term loan, were 13.16% and 13.81% respectively (11.46% and 9.89% for the comparable periods in 2017). For the three months ended and, funds borrowed are denominated in U.S. dollars and have a coupon rate of LIBOR plus 8% (with LIBOR having a floor of 1%). For the three months ended, finance expense decreased by 22% over the comparative prior period due to lower debt outstanding being partially offset by a slightly higher interest rate. Eagle used part of the net proceeds from the Salt Flat disposition to reduce its term loan by 34% (from $US 58.2 million to $US 38.5 million). Total year-to-date finance expense includes $3.1 million of one-time costs associated with the Salt Flat disposition and partial debt prepayment. Excluding these costs, finance expense is $5.64 per boe, comparable to During the first quarter of 2017, and in anticipation of the withdrawal of support from certain members of Eagle s existing syndicate of Canadian bank lenders who had indicated a desire to reduce their exposure to the junior energy lending market, Eagle retired all amounts drawn under its previous bank credit facility that was maturing on May 27, 2017 and entered into a new four year secured term loan (see Liquidity and Capital Resources ). Eagle s current lender is an SEC-registered investment adviser headquartered in San Francisco and affords Eagle a partner that has the capacity to provide additional financing. 8

10 Funds Flow from Operations The following table summarizes funds flow from operations on an absolute and on a per boe basis: $000 s $/boe $000 s $/boe $000 s $/boe $000 s $/boe Field netback (1) 6, , , , Cash settled award payments (9) (0.01) Administrative expenses - cash (1,511) (7.34) (2,654) (7.35) (4,407) (9.31) (5,041) (7.20) Realized risk management (loss) gain (1,229) (5.97) (1,842) (3.89) (1,441) (2.06) Finance expense - cash (1,331) (6.47) (1,845) (5.11) (5,097) (10.76) (2,982) (4.26) Income tax expense - - (1) (1) - Amortization of leasehold inducement (2) - Realized foreign exchange (loss) gain (2) (19) (0.09) , Funds flow from operations (3) 1, , , , Note: (1) Field netback is a non-ifrs financial measure. See Non-IFRS Financial Measures. (2) This represents settled foreign currency transactions related to operating activities. (3) Funds flow from operations for the six months ended includes one-time disposition costs of $3.4 million incurred in the first quarter and relating to the Salt Flat disposition Sensitivities Eagle s results and ability to generate sufficient amounts of cash to fund ongoing operations are affected by external market factors such as fluctuations in the prices of crude oil and natural gas as well as movements in foreign-exchange rates and interest rates. Changes in production also affect funds flow. Sensitivities to these factors are summarized below. Quarterly impact on Funds flow from operations ($000 s) Funds flow from operations / share (1) Gas price (2) $US 0.10/mcf Henry HUB 25 - Oil price (2) $US 1.00/bbl WTI Gas production Mcf/d 73 - Oil production +100 bbls/d Currency (2) $CA weaken by $ Interest rate +1% LIBOR (127) - Notes: (1) Per share figures are based on 43,750,488 weighted average basic shares outstanding for the three months ended. (2) Price and currency sensitivities are calculated using an average second quarter production rate of total working interest and royalty sales volumes of 2,262 boe/d. 9

11 Depreciation, Depletion and Amortization ($000 s) Depreciation, depletion and amortization 2,311 5,405 (57) 5,531 10,351 (47) Impairment expense 15, , Total 17,399 5, ,144 10, Depreciation, depletion and amortization ($/boe) (25) (21) On an overall corporate level, the year-to-date per boe depletion rate decreased by 21%. When this lower rate is combined with lower year-to-date production, depreciation, depletion and amortization expense was 47% lower in the first half of The depletion, depreciation, and amortization provision for the three and six months ended was based on proved plus probable reserves, including the future development costs associated with those reserves, as outlined in the year-end 2017 reserves evaluation report prepared by Eagle s independent reserves evaluators. For the Dixonville properties, the combination of a decrease in carrying value due to an impairment charge at December 31, 2017, along with a corresponding decrease in reserves, resulted in a depletion rate similar to the second quarter of 2017 ($6.45 per boe in the second quarter of 2018 and $6.48 per boe in the second quarter of 2017). For the six months ended, the depletion rate was $6.47 per boe compared to $6.42 per boe for the six months ended. For the Twining properties, an increase in carrying value due to an impairment reversal at 2017 year-end resulted in a higher depletion rate of $14.80 per boe in the second quarter of 2018 compared to $13.45 per boe in the second quarter of For the six months ended, the depletion rate was $14.89 per boe compared to $13.41 per boe for the six months ended. For the North Texas properties, an increase in carrying value due to an impairment reversal at 2017 year-end, along with an increase in reserves, resulted in a lower depletion rate of $18.33 per boe in the second quarter of 2018 compared to $20.85 per boe for the second quarter of For the six months ended, the depletion rate was $18.40 per boe compared to $20.66 per boe for the six months ended. For the six months ended, Eagle recognized a $1.3 million impairment recovery related to the disposition of Salt Flat for which an impairment of $12.4 million was recognized as at December 31, At, Eagle recognized a $14.9 million impairment on its oil and gas properties in relation to Twining. The Twining impairment was to record the fair value of the property, using the fair market less costs to sell model, based on the sale agreement signed on July 19, At, Eagle assessed each of its remaining CGUs and determined that there were no indicators of impairment. 10

12 Foreign Exchange Gain (Loss) $000 s Net loss (gain) arising on settlement of foreign currency transactions arising out of operating activities 19 (2) (117) (2) Foreign exchange gain on repayment of U.S. denominated debt - - (1,505) - Realized loss (gain) on foreign exchange 19 (2) (1,622) (2) Foreign exchange loss (gain) on U.S. denominated debt 953 (2,279) 3,744 (2,279) Foreign exchange (gain) loss on Canadian denominated intercompany loan (1,081) 2,054 (2,959) 2,834 Foreign exchange loss on U.S. denominated risk management liability Unrealized (gain) loss on foreign exchange (128) (225) Foreign exchange (gain) loss, net (109) (227) (796) 553 The net loss (gain) arising on the settlement of foreign currency transactions arising out of operating activities and the gain on repayment of U.S. denominated debt are recorded as realized losses or gains in the statement of (loss) earnings. The unrealized foreign exchange loss (gain) on the U.S. denominated debt (see Loan Agreement under Liquidity and Capital Resources) is a non-cash entry and is a result of the re-evaluation of the U.S. based term loan to the Canadian dollar equivalent amount on each balance sheet date. The change in the Canadian dollar amount is recorded as unrealized in the statement of (loss) earnings. For the three and six months ended, an unrealized loss of $1.0 million and $3.7 million, respectively, is shown due to an increase in the period-end foreign exchange rate. When the balance of the U.S. denominated debt changes due to a repayment, as it did in February 2018, when proceeds from the Salt Flat disposition were used to partially pay down debt, the foreign exchange gain or loss is a realized gain or loss in the statement of (loss) earnings. For the six months ended, a realized gain of $1.5 million is shown due to the $US 18.0 million term loan repayment and the decrease in the foreign exchange rate from the March 2017 inception of the loan to the February 2018 repayment. The $1.1 million and $3.0 million unrealized foreign exchange gain on the Canadian denominated intercompany loan for the three and six months ended respectively, is a non-cash entry and is a result of a U.S. subsidiary holding a Canadian dollar denominated loan issued by its parent. The intercompany loan is eliminated on consolidation, but it is no longer considered part of the net investment in the subsidiary (because amounts have been repaid in the past); thus, any related period-end foreign exchange translation adjustment is recorded in the statement of loss (earnings) as opposed to currency reserves in shareholders equity. Capital Expenditures Capital expenditures during the three and six month period ended were as follows: $000 s Exploration and evaluation - 1,015-3,217 Land Intangible drilling and completions 4,145 1,237 6,388 10,278 Well equipment and facilities ,096 Other Total 5,059 2,786 7,336 14,608 Capital expenditures in the second quarter of $5.0 million were primarily to drill, complete and tie-in Eagle s second North Texas horizontal well ($4.3 million) and to acquire North Texas acreage ($0.2 million). Capital expenditures of 11

13 $7.3 million for the six months ended consisted of $7.0 million in the U.S. for drilling and completion costs for two North Texas wells, tie-in costs for one well and for acreage acquisitions. Summary of Quarterly Results ($000 s except for boe/d and per share amounts) Q2/2018 Q1/2018 Q4/2017 Q3/2017 Q2/2017 Q1/2017 Q4/2016 Q3/2016 Sales volumes boe/d 2,262 2,974 3,804 3,749 3,966 3,767 3,803 4,085 Revenue, net of royalties 10,228 12,461 14,725 12,459 14,167 14,218 13,891 12,854 per boe Operating, transportation and marketing expenses 4,206 5,109 6,864 6,301 5,885 7,165 6,799 6,564 per boe Field netback 6,022 7,352 7,861 6,158 8,282 7,053 7,092 6,290 per boe Funds flow from operations 1,932 1,718 (2) 3,488 3,346 4,272 1,589 3,901 4,582 per boe per share basic per share diluted (Loss) earnings (15,093) (2,568) (14,293) (4,711) 675 1,303 30, per share basic (0.34) (0.06) (0.34) (0.11) per share - diluted (0.34) (0.06) (0.34) (0.11) Cash dividends declared per issued share Current assets 10,920 (1) 14,941 13,869 11,122 11,847 18,819 9,302 9,787 Current liabilities 5,762 (1) 7,528 13,715 8,042 6,599 11,474 74,758 72,387 Total assets 159, , , , , , , ,945 Total non-current liabilities 62,427 70,870 94,312 92,367 97, ,359 26,202 31,690 Shareholders equity 81,709 96,479 99, , , , ,239 86,868 Shares issued 43,750 43,750 43,302 43,302 42,857 42,857 42,452 42,452 (1) Figures exclude amounts related to assets classified as held for sale (2) Includes one-time disposition costs of $3.4 million relating to the Salt Flat disposition. For the three months ended, sales volumes were lower than the previous quarters, primarily due to the effect of the February 2018 Salt Flat disposition being only partially offset by additional production from wells drilled in Eagle s Twining and North Texas areas. Second quarter 2018 field netback on a per boe basis increased 7% from the first quarter of 2018 due to higher commodity prices and narrower oil price differentials on Canadian production. Second quarter 2018 funds flow from operations increased 12% from the first quarter of 2018 due to higher realized prices and lower second quarter administrative and financing expenses because of one-time Salt Flat disposition costs that occurred in the first quarter. A higher realized risk management loss partially offset this increase. Total non-current liabilities decreased as a result of debt repayment from Salt Flat disposition proceeds. 12

14 Changes in (loss) earnings from one quarter to the next often do not move directionally or by the same amount as quarterly changes in funds flow from operations. This is due to items of a non-cash nature that factor into the calculation of (loss) earnings, and those that are required to be fair valued at each quarter end. Second quarter 2018 funds flow from operations was 6% higher than the first quarter of 2018, yet the second quarter 2018 loss was 488% more than the first quarter of 2018 due to a non-cash impairment expense relating to the Twining oil and gas properties based on the sale agreement signed July 19, Segmented Operations Eagle s operating activities relate to the exploration, development and production of petroleum and natural gas resources in the United States and Canada. Costs incurred in the Corporate segment relate to Eagle s hedging program and other expenses incurred in overall financing and administration of Eagle. United States Production Working interest Oil (bbl/d) 494 1,786 (72) 759 1,773 (57) Natural gas (Mcf/d) NGLs (bbl/d) Oil equivalent sales volumes 6:1) 587 1,849 (68) 872 1,840 (53) Royalty interest Oil (bbl/d) Natural gas (Mcf/d) NGLs (bbl/d) Oil equivalent sales volumes 6:1) Total Oil (bbl/d) 494 1,786 (72) 759 1,773 (57) Natural gas (Mcf/d) NGLs (bbl/d) Oil equivalent sales volumes 6:1) 587 1,849 (68) 872 1,840 (53) 13

15 Field Netback ($000 s) Revenue 4,071 10,343 (61) 11,783 20,923 (44) Royalties (894) (2,873) (69) (2,791) (5,758) (52) Operating expenses (668) (2,581) (74) (2,273) (6,239) (64) Transportation and marketing expenses (63) (25) 152 (180) (57) 216 Field netback 2,446 4,864 (50) 6,539 8,869 (26) ($/boe) Revenue Royalties (16.75) (17.07) (2) (17.70) (17.29) 2 Operating expenses (12.52) (15.34) (18) (14.41) (18.73) (23) Transportation and marketing expenses (1.18) (0.14) 743 (1.14) (0.17) 571 Field netback Capital Activity Capital expenditures ($000 s) 4,911 1, ,044 7,170 (2) Wells drilled (rig -released) Gross Net Wells brought on-stream Gross (50) Net (50) On February 8, 2018, Eagle disposed of its oil and gas properties in the Salt Flat field located in Caldwell County, Texas. Prior to its disposition, Salt Flat produced approximately 1,200 boe/d. Revenue for the second quarter was primarily from Sunoco Logistics Partners L.P. ( Sunoco ) and amounted to $3.5 million (87%). For the second quarter of 2017, revenue of $7.1 million (69%) was from Texican Hydrocarbons LLC ( Texican ) and $2.2 million (21%) from Sunoco. Revenue for the six months ended was primarily from Sunoco and Texican and amounted to $7.5 million (63%) and $3.5 million (29%), respectively. For the six months ended, revenue of $13.0 million (62%) was from Texican and $4.0 million (19%) from Sunoco. North Texas Property Capital expenditures for North Texas were $5.0 million, with average working interest sales volumes of 587 boe/d. The $5.0 million was primarily spent on drilling, completing and tie-in of its second North Texas horizontal well ($4.3 million) and acquiring North Texas acreage ($0.2 million). Capital expenditures of $7.0 million for the six months ended June 30, 2018 were comprised of drilling and completion costs for the two North Texas wells, tie-in costs for one well and acreage acquisitions. 14

16 Canada Production Working interest Oil (bbl/d) 1,213 1,501 (19) 1,225 1,421 (14) Natural gas (Mcf/d) 1,649 2,051 (20) 1,752 1,954 (10) NGLs (bbl/d) (35) (17) Oil equivalent sales volumes 6:1) 1,537 1,917 (20) 1,575 1,816 (13) Royalty interest Oil (bbl/d) (26) (24) Natural gas (Mcf/d) (38) (21) NGLs (bbl/d) (11) (5) Oil equivalent sales volumes 6:1) (30) (19) Total Oil (bbl/d) 1,252 1,554 (19) 1,267 1,476 (14) Natural gas (Mcf/d) 2,066 2,727 (24) 2,317 2,673 (13) NGLs (bbl/d) (27) (13) Oil equivalent sales volumes 6:1) 1,675 2,117 (21) 1,745 2,027 (14) Field Netback ($000 s) Revenue 8,722 8, ,544 15,788 5 Royalties (1,671) (1,449) 15 (2,847) (2,568) 11 Operating expenses (3,048) (2,768) 10 (5,993) (5,808) 3 Transportation and marketing expenses (427) (511) (16) (869) (946) (8) Field netback 3,576 3, ,835 6,466 6 ($/boe) Revenue Royalties (10.96) (7.52) 46 (9.01) (7.00) 29 Operating expenses (19.99) (14.37) 39 (18.97) (15.83) 20 Transportation and marketing expenses (2.80) (2.65) 6 (2.75) (2.58) 7 Field netback

17 Capital Activity Capital expenditures ($000 s) (84) 290 7,421 (96) Wells drilled (rig-released) Gross Net Wells brought on-stream Gross Net During the second quarter of 2018, capital expenditures were $0.1 million in Canada with average working interest plus royalty interest sales volumes of 1,675 boe/d. Revenue for the second quarter was primarily from Trafigura Canada General Partnership ( Trafigura ) in the amount of $7.0 million (80%). For the second quarter of 2017, revenue of $6.7 million (82%) was from Trafigura. Revenue for the six months ended was primarily from Trafigura in the amount of $13.3 million (80%). For the six months ended, revenue of $12.9 million (82%) was from Trafigura. Dixonville Properties, Alberta Dixonville continues to perform to expectations with production at expected levels. Differentials in the Dixonville area have narrowed since the first quarter of 2018, increasing netbacks in the area, despite slightly higher than expected operating costs. Twining Properties, Alberta On July 19, 2018, Eagle signed an agreement to sell its entire interest in its oil and natural gas properties near Twining, Alberta to a third party for cash consideration of $13.8 million before customary post-closing adjustments. The sale is expected to close on or about August 28, 2018, subject to customary closing conditions. Other Properties, Alberta Throughout the six months ended, production from these non-operated properties exceeded expectations. During the second quarter, an adjustment relating to 2017 decreased royalty interest production by 109 boe/d. Corporate $000 s Administrative expenses - cash portion (1,511) (2,654) (43) (4,407) (5,041) (13) Risk management gain (loss) - realized (1,229) 488 (352) (1,842) (1,441) 28 Cash settled award payments (9) - Finance expense - cash portion (1,331) (1,845) (28) (5,097) (2,982) 71 Amortization of leasehold inducements (2) - Income tax recovery (expense) - (1) - - (1) - Realized foreign exchange loss (19) 2-1, Total (4,090) (4,010) 2 (9,724) (9,474) 3 16

18 Liquidity and Capital Resources Generally, four sources of funding are available to Eagle: (1) internally-generated funds flow from operations; (2) debt financing, when appropriate; (3) divestitures; and (4) the issuance of additional shares, if available on favourable terms. To better manage its liquidity risk, Eagle prepares annual capital expenditure budgets which are regularly monitored and updated as considered necessary. Further, Eagle utilizes authorizations for expenditures ( AFEs ) on both operated and non-operated projects to manage capital expenditures. Eagle attempts to match its payment cycle with the collection of its oil and natural gas revenue each month. Loan Agreement On March 13, 2017, Eagle retired all amounts drawn under its $70.0 million authorized bank credit facility that was held with a syndicate of Canadian chartered banks and replaced it with a new four year secured term loan from a U.S.- based lender. At December 31, 2017, Eagle had drawn approximately $73.0 million (the approximate Canadian dollar equivalent of $US 58.2 million) under the loan agreement. Effective March 15, 2018, and after giving effect to the February 2018 disposition of Salt Flat, the lender finalized its borrowing base redetermination and set the borrowing base at $CA 67.9 million (the approximate Canadian dollar equivalent of $US 51.6 million). At, Eagle had $US 38.5 million drawn on the $US 51.6 million borrowing base under the loan agreement with the option to draw by way of a Notice of Borrowing the remaining incremental term loan amount up to the borrowing base prior to March 19, At, Eagle had a working capital surplus, excluding amounts related to assets classified as held for sale, of $5.2 million, with $50.7 million (the approximate Canadian dollar equivalent of $US 38.5 million) drawn under the loan agreement. The details of Eagle s outstanding debt (translated into the approximate Canadian dollar equivalent) were as follows: $000 s December 31, 2017 Amount drawn 50,744 73,035 Less deferred financing charges (3,601) (4,957) Debt 47,143 68,078 At and December 31, 2017 there were no covenant violations. Draws under the loan agreement are subject to quarterly covenant calculations which are directly impacted by commodity prices, foreign exchange rate fluctuations, production levels and drilling results. The amount available under the loan agreement is subject to semiannual borrowing base determinations, which are directly impacted by the future value of the oil and natural gas reserves. The next semi-annual borrowing base redetermination by the lender will be finalized by September 15, Violation of any financial covenant constitutes an immediate event of default under the loan agreement in which the lender may, without notice or demand, do any or all of the following: terminate the loan, declare amounts immediately due and payable; stop advancing money or extending credit; settle or adjust disputes and claims directly with debtors; or make any payments and do any act it considers necessary or reasonable to protect its collateral (including placing a hold on deposit accounts of Eagle and demanding and receiving possession of Eagle s books and records). The following lists the key terms of the loan agreement between Eagle and its lender after giving effect to all amendments and borrowing base redeterminations through to August 9, 2018: Effective Date - March 13, 2017 Term - 4 years Maturity Date - March 13,

19 Borrowing Base - $US 51.6 million Borrowing Base Redeterminations Scheduled borrowing base redeterminations take place semi-annually (using reserve reports with effective dates of June 30 and December 31) and become effective when the new borrowing base notice is received from the lender. Such borrowing base remains in effect until the next borrowing base redetermination. The borrowing base redeterminations are effective for Eagle and its lender on March 15 and September 15 of each year. For purposes of semi-annual borrowing base redeterminations, Eagle will provide its lender with reserve reports with effective dates of June 30 and December 31 each year. Failure of Eagle to provide a semi-annual reserve report constitutes an immediate event of default. Upon receipt by the lender of the semi-annual reserve report (and other reports, data and supplemental information as may be reasonably requested), the lender will evaluate the information and propose a new borrowing base based upon an advance rate of 75% of the proved developed producing reserves value, before tax, discounted at 10% ( PDP PV10 reserves value ). The forward pricing used to calculate the PDP PV10 reserves value is based on 48 months of NYMEX futures contracts and is defined in the loan agreement. In the event that a borrowing base redetermination results in the outstanding principal of the term loan exceeding the borrowing base then in effect ( Term Loan Excess ), then, after receiving a new borrowing base notice of such new or adjusted borrowing base (such date of receipt of notice being the Borrowing Base Notification Date ), Eagle will, no later than twenty (20) business days from the Borrowing Base Notification Date, repay an amount equal to (A) the then applicable Term Loan Excess plus (B) 2% of the aggregate principal amount of any such repayment. If Eagle fails to pay the amount under (B), then that amount bears interest until paid in full at a rate of LIBOR plus 13% per annum. A non-payment by Eagle when and as required of amounts to be paid or repaid would constitute an immediate event of default. Coupon - LIBOR plus 8% (with LIBOR having a floor of 1%) Financial covenants - The four financial covenants in the loan agreement are summarized below. (a) Consolidated Leverage Ratio As at the end of each fiscal quarter, Eagle is to maintain a Consolidated Leverage Ratio of not greater than 3.50 to 1.00 for each quarter ending on or after March 31, As at, the Consolidated Leverage Ratio was 2.51 to 1.0. The Consolidated Leverage Ratio is defined in the loan agreement as the ratio of Consolidated Funded Debt to Consolidated Adjusted EBITDAX (as defined below) for the trailing four fiscal quarters. (b) Consolidated Fixed Charge Ratio As at the end of each fiscal quarter, Eagle is to maintain a Consolidated Fixed Charge Ratio of not less than 1.70 to 1.00 As at, the Consolidated Fixed Charge Ratio was 1.96 to The Consolidated Fixed Charge Ratio for the fiscal quarter is defined in the loan agreement as the ratio that (i) Consolidated Adjusted EBITDAX plus (ii) income tax payments minus (iii) maintenance capital expenditures associated with proved developed producing reserves is to interest expense (each for the fiscal quarter and with one-time interest charges relating to the disposition of the Salt Flat properties being excluded from interest expense). (c) Asset Coverage Ratio As at June 30 and December 31 of each fiscal year, and based on reserve reports internally prepared by Eagle, Eagle is to maintain an Asset Coverage Ratio of not less than to At, the Asset Coverage Ratio was 2.13 to The Asset Coverage Ratio is defined in the loan agreement as the ratio of the PDP PV10 reserves value (using prices quoted on NYMEX and before tax) to the aggregate principal balance outstanding under the term loan. 18

20 (d) Consolidated Current Ratio As at the end of each fiscal quarter, Eagle is to maintain a Consolidated Current Ratio of not less than 1.00 to As at, the Consolidated Current Ratio was 1.90 to The Consolidated Current Ratio is defined in the loan agreement as the ratio of Consolidated Current Assets to Consolidated Current Liabilities, but, in each case, excluding any risk management assets or risk management liabilities that are classified as current. Consolidated Adjusted EBITDAX, as defined in the loan agreement means: (a) (b) (c) (d) (e) (f) (g) net income; plus actual cash transaction costs and expenses directly incurred in connection with the disposition of the Salt Flat properties; plus interest expense, accrued taxes, depreciation, depletion, amortization, exploration expense and other non-recurring expenses that do not represent a cash item in such period or any future period; plus or minus gains or losses attributable to write-ups or write-downs of assets; plus or minus unrealized foreign exchange gains or losses; plus or minus non-cash gains, losses or adjustments under Financial Accounting Standards Board (FASB) Statement 133 as a result of changes in the fair market value of derivatives; plus or minus non-cash share-based compensation or recovery amounts. In addition, EBITDAX is calculated after giving effect on a pro-forma basis to any permitted acquisition or disposition (that is also a material disposition ) as if such acquisition or disposition occurred at the beginning of such period, provided that the disposition of Salt Flat has been deemed not to constitute a material disposition. Working Capital At, Eagle had a working capital surplus, excluding amounts relating to assets classified as for sale, of $5.2 million, with $50.7 million (the approximate Canadian dollar equivalent of $US 38.5 million) drawn under the loan agreement. Shareholders Equity, Dividends and Outstanding Share Data During the second quarter, no common shares were issued. At, Eagle had issued 43,750,488 shares (December 31, ,301,986). As at the date of this MD&A, 43,750,488 shares are issued and outstanding and 1,682,323 RSUs and 623,904 PSUs are outstanding (December 31, ,635,668 RSUs and 607,956 PSUs). 19

21 Commitments Eagle has committed to future payments as follows: $000 s Total Less than 1 year 1 3 years Greater than 3 years Operating leases (1) (2) (3) 3, ,615 1,489 Total contractual obligations 3, ,615 1,489 Notes: (1) On January 1, 2013, Eagle entered into a lease for office space in Calgary which originally had an approximate 61 month term from January 8, 2013 to February 7, In May 2016, the lease was amended to extend the lease term and decrease the annual basic rental charge. The new term began August 1, 2016 and terminates February 28, Total minimum lease payments during the term of the lease from August 1, 2016 through February 28, 2023 approximate $3.1 million and include a leasehold improvement allowance up to $0.2 million, with 56 months and approximately $2.1 million remaining at. (2) Eagle entered into an office lease in Houston on September 22, 2017 to replace the lease expiring on December 31, The term of the lease is from February 1, 2018 to August 31, 2025, with payments beginning September 1, Total minimum lease payments during the term of the lease approximate $US 1.2 million. The total minimum lease payments approximate $CA 1.6 million translated at the exchange rate in effect at the balance sheet date of $US 1.00 equal to $CA (3) Eagle entered into five vehicle lease agreements in Texas. The terms of the leases range from August 17, 2016 to October 27, Total minimum lease payments during the term of the lease approximate $US 0.2 million. At, 40 months remain on the leases with approximately $CA 0.1 million remaining at translated at the exchange rate in effect at the balance sheet date of $US 1.00 equal to $CA Non-IFRS Financial Measures Statements throughout this MD&A make reference to the terms field netback, Consolidated Adjusted EBITDAX, Consolidated Leverage Ratio, Consolidated Fixed Charge Ratio, Asset Coverage Ratio and Consolidated Current Ratio, which are non-ifrs financial measures that do not have a standardized meaning prescribed by IFRS and may not be comparable to similar measures presented by other issuers. Field netback is calculated by subtracting royalties, operating expenses, and transportation and marketing expenses from revenues. This method of calculating field netback is in accordance with the standards set out in the Canadian Oil and Gas Evaluation Handbook maintained by the Society of Petroleum Evaluation Engineers (Calgary Chapter). Management believes that field netback provides useful information to investors and management because such a measure reflects the quality of production and the level of profitability. The terms Consolidated Adjusted EBITDAX, Consolidated Leverage Ratio, Consolidated Fixed Charge Ratio, Asset Coverage Ratio and Consolidated Current Ratio are used for purposes of covenant calculations in the Loan Agreement and are calculated as described above under the heading, Liquidity and Capital Resources. No Change in Internal Controls over Financial Reporting during the Period April 1, 2018 to During the period beginning on April 1, 2018 and ended on, there was no change in Eagle s internal controls over financial reporting that has materially affected, or is reasonably likely to materially affect, Eagle s internal controls over financial reporting. It should be noted that Eagle s internal control system, no matter how well designed, can provide only reasonable, but not absolute assurance of detecting, preventing and deterring errors or fraud. Critical Accounting Estimates and Judgments There have been no changes made to Eagle s critical accounting estimates and judgments for the second quarter of Further information about Eagle s critical accounting estimates and judgments can be found in the notes to Eagle s annual audited consolidated financial statements and MD&A for the year ended December 31, Accounting Standards and Interpretations Other than the items below which were adopted effective January 1, 2018, the accounting policies followed in these Interim Financial Statements are consistent with those of the previous financial year, except for income tax expense for an interim period (which is based on an estimated average annual effective income tax rate). 20