Financial Report Third Quarter 2018

Transcription

1 Financial Report Third Quarter

2 EAGLE THIRD QUARTER REPORT Management s Discussion and Analysis November 8, This Management s Discussion and Analysis ( MD&A ) of financial condition and results of operations for Eagle Energy Inc. ( Eagle ), dated November 8,, should be read in conjunction with Eagle s unaudited condensed consolidated interim financial statements and accompanying notes for the three months and nine 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, ( 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 1.29 (December 31, $US 1.00 equal to $CA 1.25), and the average foreign exchange rate for the nine months ended was $US 1.00 equal to $CA 1.29 (for the nine months ended $US 1.00 equal to $CA 1.31). 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 United States 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 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 EAGLE THIRD QUARTER REPORT 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 Closed the sale of the Twining properties in Alberta on August 28 for cash proceeds of $CA 13.3 million and used $US 8.1 million of the proceeds to reduce long term debt, with the remaining proceeds allocated to further fund the North Texas drilling program. Reduced long term debt during the quarter by 21% (from $US 38.5 million to $US 30.4 million) for a total reduction in long term debt since 2017 year-end of 48% (from $US 58.2 million to $US 30.4 million). Improved field netback by 57% on a per barrel of oil equivalent ( boe ) basis (from $17.85 to $28.10 per boe) when compared to the third quarter of General and administrative expenses to the end of September, excluding one-time costs associated with the Salt Flat and Twining dispositions, are $1.5 million, or 22% lower than the 2017 comparative period. Operations Update During the quarter, Eagle drilled and cased a third horizontal well in North Texas at a location approximately one mile from its initial horizontal well. This was Eagle s first use of a new technology that enabled it to drill approximately 4,000 feet of horizontal lateral and place the entire horizontal section within the productive interval. Eagle entered into a fixed price financial swap for 650 barrels of oil per day at a West Texas Intermediate ( WTI ) price of $US per barrel for the months of October through December. 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, Eagle plans to: Continue to focus on drilling wells on its North Texas property with its opportunities for meaningful growth and high netbacks. Continue to reduce debt and corporate costs, including interest costs, in order to better position Eagle to capitalize the North Texas development program. Continue to reduce general and administrative expenses by focusing on efficiencies and cost reduction. Consolidated Results of Operations Production Working interest (boe/d) 1,854 3,529 (47) 2,246 3,613 (38) Royalty interest (boe/d) (53) (31) Total (boe/d) 1,958 3,749 (48) 2,394 3,827 (37) For the three months ended, the oil weighting (80% oil, 8% natural gas liquids ( NGLs ) and 12% natural gas) has decreased slightly compared to the same period in 2017 (82% oil, 4% NGLs and 14% natural gas) due to property dispositions. For the nine months ended, the oil weighting (78% oil, 6% NGLs), 2

4 EAGLE THIRD QUARTER REPORT 16% natural gas) has decreased when compared to the 2017 period (83% oil, 4% NGLs and 13% natural gas) primarily due to the February Salt Flat property disposition. Working interest production decreased for the three and nine month periods due to property dispositions being partially offset by additional production from wells drilled in Eagle s North Texas area. Royalty interest volumes decreased for the three and nine month periods due to natural declines and a prior period adjustment. Average Daily Production by Product Type Working Interest Oil (bbl/d) 1,527 3,027 (50) 1,830 3,138 (42) Natural gas (Mcf/d) 1,465 2,276 (36) 1,891 2,198 (14) NGLs (bbl/d) (33) (7) Oil equivalent sales volumes 6:1) 1,854 3,529 (47) 2,246 3,613 (38) Royalty Interest Oil (bbl/d) (8) (19) Natural gas (Mcf/d) (60) 771 (108) (52) NGLs (bbl/d) Oil equivalent sales volumes 6:1) (53) (31) Total Oil (bbl/d) 1,572 3,075 (49) 1,873 3,191 (41) Natural gas (Mcf/d) 1,406 3,047 (54) 2,246 2,934 (23) NGLs (bbl/d) (8) Oil equivalent sales volumes 1,958 3,749 (48) 2,394 3,827 (37) 3

5 EAGLE THIRD QUARTER REPORT Revenue $000 s Working Interest Revenue Oil 10,476 14,551 (28) 36,081 48,060 (25) Natural gas (62) 945 1,592 (41) NGLs (3) 1, Other (41) (48) Royalty Interest Revenue 11,082 15,518 (29) 38,525 51,241 (25) Oil Natural gas 4 99 (96) (70) NGLs Other Total Revenue ,288 1,385 (7) Oil 10,746 14,755 (27) 36,868 48,765 (24) Natural gas (69) 1,058 1,970 (46) NGLs ,538 1, Other (41) (48) 11,486 15,915 (28) 39,813 52,626 (24) Product Prices Realized Prices Oil ($/bbl) Natural gas ($/Mcf) (32) (30) NGLs ($/bbl) Other ($/bbl) (17) Revenue ($/boe) Benchmark prices WTI crude oil ($US/bbl) Exchange rate ($CA/$US) (2) Edmonton Par crude oil ($CA/bbl) NYMEX Gas ($US/Mcf) (3) (7) AECO natural gas ($CA/Mcf) (20) (36) Eagle s revenue for the three and nine months ended was 93% derived from oil, similar to the three and nine months ended When compared to the 2017 periods, realized oil prices in Canadian dollars for the three and nine months ended increased due to a higher benchmark WTI crude oil price. The realized price increase is lower than the WTI increase for the three and nine months ended due to price differentials for Canadian crude oil and a higher proportion of production coming from Canada. 4

6 EAGLE THIRD QUARTER REPORT 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 more 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 widened from the second quarter of to be a discount of approximately $CA per barrel in the third quarter of ($CA 9.09 per barrel in the third quarter of 2017). For the second quarter of, Dixonville differentials were $CA per barrel. For the Twining properties in Canada, which were sold on August 28,, the entire differential to WTI, including quality and transportation, has narrowed from the second quarter of to be a discount of approximately $CA per barrel in the third quarter of ($CA per barrel in the third quarter of 2017). For the second quarter of, differentials for Twining were $CA per barrel. The above prices do not include realized gains or losses from financial commodity contracts, which were nil for the three months ended and a loss of $1.8 million for the nine months ended. See Realized and Unrealized Risk Management Loss (Gain). Royalties Total royalties ($000 s) (1) 2,476 3,456 (28) 8,114 11,782 (31) $/boe (2) Royalty rate on working interest sales 22% 22% - 21% 23% (8) 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. For the three months ended, the overall royalty rate was the same as the prior year comparative period. Canadian production for the third quarter of is 73% of corporate production (50% in the third quarter of 2017). Canadian properties had an average royalty rate of 20% in the third quarter of compared to 14% in the third quarter of 2017, primarily due to higher oil prices. The U.S. properties had an average royalty rate of 23% for the third quarter of (28% for the third quarter of 2017). For the nine months ended, the overall royalty rate decreased to 21% from 23% in the prior year comparative period. The decrease in the overall royalty rate is due to the higher proportion of production from the Canadian properties, which average a lower rate than the U.S. properties. For the nine months ended, Canadian production accounts for 68% of total production (53% for the nine months ended 2017). Canadian properties had an average royalty rate of 18% for the nine months ended (16% for the nine months ended 2017), while the U.S. properties had an average royalty rate of 24% in nine months ended (27% for the nine months ended 2017). 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 EAGLE THIRD QUARTER REPORT Operating and Transportation and Marketing Expenses Total operating expenses ($000 s) (1) Operating expenses 3,509 5,836 (40) 11,775 17,883 (34) Transportation and marketing expenses (6) 1,486 1,468 1 ($/boe) (2) 3,946 6,301 (37) 13,261 19,351 (31) 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 three months ended, the 20% increase in per boe operating expenses is primarily due to an additional $175,000 related to the Dixonville plant turnaround that must be completed once every five years. As well, per boe operating expenses are relatively higher in Dixonville and North Texas than in Salt Flat, which was disposed of in February. For the three months ended, operating expenses (inclusive of transportation and marketing expenses) of $3.9 million are 37% lower than the three months ended 2017 due to the 48% decrease in production as a result of the dispositions of Salt Flat and Twining assets. For the nine months ended, the 9% increase in per boe operating expenses on a year-over-year basis is due to the Dixonville plant turnaround, well workovers in Dixonville and North Texas and the disposition of Salt Flat, which had relatively lower operating costs. For the nine months ended, operating expenses (inclusive of transportation and marketing expenses) of $13.3 million are comprised primarily of oil transportation (9%), fuel (8%), power (8%), field salaries (6%) and chemicals (6%). For the nine months ended 2017, operating expenses (inclusive of transportation and marketing expenses) of $19.4 million were comprised primarily of power (19%), field salaries (7%), chemicals (7%), oil transportation (7%) and fuel (5%). The year-over-year decrease of 31% in total operating expenses, inclusive of transportation, is primarily due to the 37% decrease in production as a result of the dispositions of the Salt Flat and Twining assets. Field Netback $000 s $/boe $000 s $/boe $000 s $/boe $000 s $/boe Revenue 11, , , , Royalties (2,476) (13.74) (3,456) (10.02) (8,114) (12.41) (11,782) (11.28) Operating expenses (3,509) (19.48) (5,836) (16.92) (11,775) (18.01) (17,883) (17.12) Transportation and marketing expenses (437) (2.43) (465) (1.35) (1,486) (2.27) (1,468) (1.41) Field netback 5, , , , Sales volumes (boe/d) 1,958 3,749 2,394 3,827 6

8 EAGLE THIRD QUARTER REPORT For the three months ended, Eagle averaged revenue of $63.75 per boe and realized a field netback of $28.10 per boe compared to revenue of $46.14 per boe and field netback of $17.85 per boe in the three months ended 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, operating and transportation expenses. For the nine months ended, Eagle averaged revenue of $60.91 per boe and realized a field netback of $28.22 per boe compared to revenue of $50.37 per boe and a field netback of $20.56 per boe for the nine months ended Field netback per boe is higher year-over-year due to increased commodity prices partially offset by higher per boe royalty, operating and transportation expenses. Field netback for the nine months of includes $1.7 million from Salt Flat for the period prior to the February disposition and $2.8 million from Twining for the period prior to the August disposition (for the nine months ended 2017, field netback included $7.2 million from Salt Flat and $3.0 million from Twining). Field netback is a Non-IFRS financial measure. See Non-IFRS Financial Measures. Administrative Expenses ($000 s) Administrative expenses 1,884 1, ,204 6,664 (22) Costs associated with the dispositions , Total administrative expenses 2,323 1, ,730 6,664 1 $/boe For the nine months ended, total administrative expenses are level with the prior year comparative period but include $1.1 million of one-time costs associated with the disposition of Salt Flat and $0.4 million of one-time costs associated with the Twining disposition. Without these one-time costs, administrative expenses were $7.96 per boe and 22% below the prior period due to cost saving initiatives implemented over the year. Staff and related employment costs and office costs account for 64% and 10%, respectively, of administrative expenses for the nine months ended (nine months ended % and 18%, respectively). For the three months ended, administrative expenses are 43% above the prior year comparative period but include $0.4 million of one-time costs associated with the disposition of Twining in August. Without these one-time costs, administrative expenses increased by 16% and were $10.46 per boe. Staffing costs and office costs each increased by $0.1 million when compared to the same period in Realized and Unrealized Risk Management Loss (Gain) As at, Eagle had no financial contracts outstanding. On October 1,, Eagle entered into the following financial contract: Volume Measure Beginning Term Floor $US Ceiling $US Oil Fixed Price NYMEX (1) 650 bbls/d Oct-18 Dec Notes: (1) Represents a fixed price financial swap transaction with a set forward sale price (WTI reference prices). 7

9 EAGLE THIRD QUARTER REPORT $000 s Realized (gain) loss - (547) - 1, Unrealized loss (gain) - 1,987 - (628) (6,104) (90) Net loss (gain) - 1,440-1,214 (5,210) (123) 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, Eagle had 1,000 barrels of oil per day hedged at an average WTI price of $US No hedges were in place for the third quarter of. 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. During the third quarter of 2017, Eagle had 1,625 barrels of oil per day hedged at an average WTI price of $US The unrealized gain for the nine months ended is the reversal of the estimated unrealized 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. Finance Expense Finance expense ($000 s) 1,645 2,188 (25) 5,376 5,905 (9) Finance expense associated with the partial prepayment of long-term debt , Total finance expense 2,621 2, ,465 5, $/boe For the three and nine 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 13.15% and 12.76% respectively (11.38% and 10.36% for the comparable periods in 2017). Total year-to-date finance expense includes $4.1 million of one-time costs associated with the Twining ($1.0 million) and Salt Flat ($3.1 million) dispositions and partial debt prepayment. Excluding these costs, finance expense is $5.45 per boe, 4% less than the 2017 rate of $5.65 per boe. For the three months ended and 2017, 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, excluding one-time finance costs associated with the repayment of the term loan, decreased by 25% over the comparative prior period due to lower debt outstanding being partially offset by a slightly higher interest rate. For the three months ended, Eagle used a portion of the net proceeds from the Twining disposition to reduce its term loan by 21% (from $US 38.5 million to $US 30.4 million). For the nine months ended, Eagle used a portion of the net proceeds from the Twining and Salt Flat dispositions to reduce its term loan by 48% (from $US 58.2 million to $US 30.4 million). Eagle has in place a loan agreement with a U.S. based lender who 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 EAGLE THIRD QUARTER REPORT 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) 5, , , , Cash settled award payments (9) (0.01) Administrative expenses - cash (2,323) (12.89) (1,623) (4.71) (6,730) (10.30) (6,664) (6.38) Realized risk management gain (loss) (1,842) (2.82) (894) (0.86) Finance expense - cash (1,484) (8.24) (1,736) (5.03) (6,581) (10.07) (4,718) (4.52) Interest income Income tax expense (1) - Amortization of leasehold inducement (2) - Realized foreign exchange gain (2) , 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 nine months ended includes one-time disposition costs of $3.4 million incurred in the first quarter and relating to the Salt Flat disposition and $0.7 million in the third quarter and related to the Twining 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 22 - Oil production +100 bbls/d Currency (2) $CA weaken by $ Interest rate +1% LIBOR (115) - Notes: (1) Per share figures are based on 43,846,973 weighted average basic shares outstanding for the three months ended. (2) Price and currency sensitivities are calculated using an average third quarter production rate of total working interest and royalty sales volumes of 1,958 boe/d. 9

11 EAGLE THIRD QUARTER REPORT Depreciation, Depletion and Amortization ($000 s) Depreciation, depletion and amortization 1,869 4,847 (61) 7,400 15,198 (51) Impairment expense , Total 1,869 4,847 (61) 21,013 15, Depreciation, depletion and amortization ($/boe) (26) (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 38% lower in the for the nine months ended than it was in the nine months ended The depletion, depreciation, and amortization provision for the three and nine 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, a slight decrease in carrying value and reserves due to recording depletion in prior period maintained a depletion rate similar to the third quarter of 2017 ($6.37 per boe in the third quarter of and $6.28 per boe in the third quarter of 2017). For the nine months ended, the depletion rate was $6.44 per boe compared to $6.38 per boe for the nine months ended For the Twining properties, a decrease in the carrying value at June 30,, due to an impairment related to the property disposition, resulted in a lower per boe rate of $10.74 for the three months ended, compared to $13.32 for the three months ended For the nine months ended, the increase in carrying value during 2017 due to the 2017 drilling program and higher reserves and future development costs, resulted in a higher depletion base for the first nine months of, and therefore a higher depletion rate of $13.85 per boe in the nine months ended compared to $13.38 per boe in the comparative period of 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 $19.05 per boe in the third quarter of compared to $19.49 per boe for the third quarter of For the nine months ended, the depletion rate was $18.59 per boe compared to $20.27 per boe for the nine months ended For the nine 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, 2017, as well as a $14.9 million impairment related to the disposition of Twining. At, Eagle assessed each of its remaining CGUs and determined that there were no indicators of impairment. 10

12 EAGLE THIRD QUARTER REPORT Foreign Exchange (Gain) Loss $000 s Net gain arising on settlement of foreign currency transactions arising out of operating activities (2) - (119) (2) Foreign exchange gain on repayment of U.S. denominated debt (350) - (1,855) - Realized gain on foreign exchange (352) - (1,974) (2) Foreign exchange (gain) loss on U.S. denominated debt (399) (2,601) 3,345 (4,880) Foreign exchange loss (gain) on Canadian denominated intercompany loan 845 3,243 (2,114) 6,077 Foreign exchange loss on U.S. denominated risk management liability Unrealized loss on foreign exchange ,272 1,197 Foreign exchange loss (gain), net (702) 1,195 The net 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 gains in the statement of (loss) earnings. The unrealized foreign exchange (gain) loss 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 months ended, an unrealized gain of $0.4 million is shown due to a decrease in the period-end foreign exchange rate since the June 30, balance sheet date. For the nine months ended, an unrealized loss of $3.3 million is shown due to an increase in the period-end foreign exchange rate since December 31, When the balance of the U.S. denominated debt changes due to a repayment, as it did in February and August when proceeds from the Salt Flat and Twining dispositions 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. Due to the decrease in the foreign exchange rate from the March 2017 inception of the loan to the February and August repayments, the three months ended show a realized gain of $0.4 million due to the $US 8.1 million term loan repayment in August, and for the nine months ended, a total realized gain of $1.9 million is shown due to the $US 19.7 million term loan repayment in February and $8.1 million repayment in August. The $0.8 million unrealized foreign exchange loss and the $2.1 million unrealized foreign exchange gain on the Canadian denominated intercompany loan for the three and nine 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 nine month period ended were as follows: $000 s Exploration and evaluation - (83) - 3,152 Intangible drilling and completions 5,531 3,537 11,919 13,381 Well equipment and facilities ,040 1,613 Other Total 5,625 3,563 12,961 18,171 11

13 EAGLE THIRD QUARTER REPORT Capital expenditures in the third quarter of $5.6 million were primarily to drill, complete and tie-in Eagle s third North Texas horizontal well ($5.5 million) and on land in North Texas ($0.1 million). Capital expenditures of $13.0 million for the nine months ended consisted primarily of $12.6 million in the U.S. for drilling and completion costs for three North Texas wells, tie-in costs for two wells, workovers, and acreage acquisitions. Summary of Quarterly Results ($000 s except for boe/d and per share amounts) Q3/ Q2/ Q1/ Q4/2017 Q3/2017 Q2/2017 Q1/2017 Q4/2016 Sales volumes boe/d 1,958 2,262 2,974 3,804 3,749 3,966 3,767 3,803 Revenue, net of royalties 9,010 10,228 12,461 14,725 12,459 14,167 14,218 13,891 per boe Operating, transportation and marketing expenses 3,946 4,206 5,109 6,864 6,301 5,885 7,165 6,799 per boe Field netback (1) 5,064 6,022 7,352 7,861 6,158 8,282 7,053 7,092 per boe Funds flow from operations 1,622 (2) 1,932 1,718 (3) 3,488 3,346 4,272 1,589 3,901 per boe per share basic per share diluted (Loss) earnings (1,887) (15,093) (2,568) (14,293) (4,711) 675 1,303 30,508 per share basic (0.04) (0.34) (0.06) (0.34) (0.11) per share - diluted (0.04) (0.34) (0.06) (0.34) (0.11) Cash dividends declared per issued share Current assets 13,270 10,920 14,941 13,869 11,122 11,847 18,819 9,302 Current liabilities 9,686 5,762 7,528 13,715 8,042 6,599 11,474 74,758 Total assets 141, , , , , , , ,199 Total non-current liabilities 51,886 62,427 70,870 94,312 92,367 97, ,359 26,202 Shareholders equity 79,692 81,709 96,479 99, , , , ,239 Shares issued 44,244 43,750 43,750 43,302 43,302 42,857 42,857 42,452 (1) Field netback is a Non-IFRS financial measure. See Advisories Non-IFRS Financial Measures. (2) Includes one-time disposition costs of $0.7 million relating to the Twining disposition. (3) 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 Salt Flat disposition and the August Twining disposition being only partially offset by additional production from wells drilled in Eagle s North Texas area. Third quarter field netback on a per boe basis decreased 4% from the second quarter of due to slightly higher realized commodity prices offset by higher royalties and increased operating costs, primarily due to the turnaround on the Dixonville plant. Third quarter funds flow from operations decreased 16% from the second quarter of due to lower field netbacks and higher third quarter administrative and financing expenses due to one-time Twining disposition costs. 12

14 EAGLE THIRD QUARTER REPORT Total non-current liabilities decreased as a result of a repayment of $10.5 million ($US 8.1 million at the period end exchange rate) from the proceeds of the Twining disposition. 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. Third quarter funds flow from operations was 16% lower than the second quarter of, yet the third quarter loss was 87% less than the second quarter of due to a non-cash impairment expense booked in the second quarter relating to the Twining oil and gas properties based on the sale agreement dated 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) 454 1,642 (72) 656 1,730 (62) Natural gas (Mcf/d) (4) NGLs (bbl/d) Oil equivalent sales volumes 6:1) 530 1,714 (69) 757 1,798 (58) Royalty interest Oil (bbl/d) Natural gas (Mcf/d) NGLs (bbl/d) Oil equivalent sales volumes 6:1) Total Oil (bbl/d) 454 1,642 (72) 656 1,730 (62) Natural gas (Mcf/d) (4) NGLs (bbl/d) Oil equivalent sales volumes 6:1) 530 1,714 (69) 757 1,798 (58) 13

15 EAGLE THIRD QUARTER REPORT Field Netback ($000 s) Revenue 3,992 9,025 (56) 15,775 29,947 (47) Royalties (937) (2,478) (62) (3,728) (8,235) (55) Operating expenses (968) (2,701) (64) (3,241) (8,940) (64) Transportation and marketing expenses (62) (19) 226 (242) (75) 223 Field netback 2,025 3,827 (47) 8,564 12,697 (33) ($/boe) Revenue Royalties (19.21) (15.72) 22 (18.05) (16.77) 8 Operating expenses (19.85) (17.13) 16 (15.69) (18.21) (14) Transportation and marketing expenses (1.27) (0.12) 959 (1.17) (0.15) 681 Field netback Capital Activity Capital expenditures ($000 s) 5,601 3, ,645 10, Wells drilled (rig -released) Gross Net Wells brought on-stream Gross (50) Net (50) On February 8,, 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 third quarter was primarily from Sunoco Logistics Partners L.P. ( Sunoco ) and amounted to $3.5 million (88%). For the third quarter of 2017, revenue of $6.3 million (69%) was from Texican Hydrocarbons LLC ( Texican ) and $2.0 million (20%) from Sunoco. Revenue for the nine months ended was primarily from Sunoco and Texican and amounted to $11.1 million (70%) and $3.5 million (22%), respectively. For the nine months ended 2017, revenue of $19.5 million (65%) was from Texican and $6.0 million (20%) from Sunoco. North Texas Property Capital expenditures for North Texas for the three months ended were $5.6 million, with average working interest sales volumes of 493 boe/d. The $5.6 million was primarily spent on drilling and completing the third North Texas horizontal well ($5.4 million) and acquiring North Texas acreage ($0.2 million). Capital expenditures of $12.6 million for the nine months ended were comprised of drilling and completion costs for the three North Texas wells, tie-in costs for one well and acreage acquisitions. 14

16 EAGLE THIRD QUARTER REPORT Canada Production Working interest Oil (bbl/d) 1,073 1,385 (23) 1,173 1,409 (17) Natural gas (Mcf/d) 1,230 2,032 (39) 1,576 1,980 (20) NGLs (bbl/d) (50) (31) Oil equivalent sales volumes 6:1) 1,324 1,816 (27) 1,489 1,816 (18) Royalty interest Oil (bbl/d) (8) (17) Natural gas (Mcf/d) (60) 771 (108) (52) NGLs (bbl/d) Oil equivalent sales volumes 6:1) (53) (30) Total Oil (bbl/d) 1,117 1,433 (22) 1,216 1,461 (17) Natural gas (Mcf/d) 1,170 2,803 (58) 1,930 2,716 (29) NGLs (bbl/d) (14) (13) Oil equivalent sales volumes 6:1) 1,428 2,035 (30) 1,638 2,029 (19) Field Netback ($000 s) Revenue 7,494 6, ,038 22,679 6 Royalties (1,539) (978) 57 (4,386) (3,547) 24 Operating expenses (2,541) (3,135) (19) (8,534) (8,943) (5) Transportation and marketing expenses (375) (446) (16) (1,244) (1,393) (11) Field netback 3,039 2, ,874 8, ($/boe) Revenue Royalties (11.71) (5.22) 124 (9.81) (6.40) 53 Operating expenses (19.34) (16.74) 16 (19.09) (16.15) 18 Transportation and marketing expenses (2.86) (2.38) 20 (2.78) (2.52) 10 Field netback

17 EAGLE THIRD QUARTER REPORT Capital Activity Capital expenditures ($000 s) 24 (47) (151) 314 7,374 (96) Wells drilled (rig-released) Gross Net Wells brought on-stream Gross Net On August 28,, Eagle disposed of its oil and gas properties located near Twining, Alberta to a third party for cash consideration of $13.8 million before customary post-closing adjustments. Prior to its disposition, Twining produced approximately 505 boe/d. During the third quarter of, capital expenditures were $24,000 in Canada with average working interest plus royalty interest sales volumes of 1,428 boe/d. Revenue for the third quarter was primarily from Trafigura Canada General Partnership ( Trafigura ) in the amount of $7.3 million (98%). For the third quarter of 2017, revenue of $5.9 million (85%) was from Trafigura. Revenue for the nine months ended was primarily from Trafigura in the amount of $14.3 million (86%). For the nine months ended 2017, revenue of $18.8 million (83%) was from Trafigura. Dixonville Properties, Alberta Dixonville continues to perform to expectations with production at expected levels. Differentials in the Dixonville area have widened since the second quarter of, decreasing netbacks in the area. As well, an additional $175,000 of operating costs were incurred in the third quarter of, due to a plant turnaround that must be completed once every five years. Other Properties, Alberta Throughout the nine months ended, production from these non-operated properties has exceeded expectations. Corporate $000 s September 30, September 30, Administrative expenses - cash portion (2,323) (1,623) 43 (6,730) (6,664) 1 Risk management gain (loss) - realized (1,842) (894) 106 Cash settled award payments (9) - Finance expense - cash portion (1,484) (1,736) (15) (6,581) (4,718) 39 Interest income Amortization of leasehold inducements (2) - Income tax recovery (expense) (1) - Realized foreign exchange gain , Total (3,442) (2,812) 22 (13,166) (12,286) 7 16

18 EAGLE THIRD QUARTER REPORT 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 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 Eagle has a loan agreement in place with 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 September 15,, and after giving effect to both the February disposition of Salt Flat and the August disposition of Twining, the lender finalized its borrowing base redetermination and set the borrowing base at $CA 73.5 million (the approximate Canadian dollar equivalent of $US 56.8 million). During the first quarter of, Eagle used a portion of the proceeds of the disposition of Salt Flat to reduce the debt by $CA 23.3 million (the approximate Canadian dollar equivalent of $US 19.7 million) and, in the third quarter of, used a portion of the proceeds of the disposition of Twining to reduce the debt by $CA 10.3 million (the approximate Canadian dollar equivalent of $US 8.1 million). At, Eagle had $US 30.4 million drawn on the $US 56.8 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 of $3.6 million, with $39.4 million (the approximate Canadian dollar equivalent of $US 30.4 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 39,400 73,035 Less deferred financing charges (2,567) (4,957) Debt 36,833 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 March 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 November 8, : Effective Date - March 13, 2017 Term - 4 years 17

19 EAGLE THIRD QUARTER REPORT Maturity Date - March 13, 2021 Borrowing Base - $US 56.8 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 2.11 to 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 2.32 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 dispositions of Salt Flat and Twining 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 As at June 30,, the Asset Coverage Ratio was 2.13 to

20 EAGLE THIRD QUARTER REPORT 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. (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 1.37 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 and Twining 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 dispositions of Salt Flat and Twining have been deemed not to constitute a material disposition. Working Capital At, Eagle had a working capital surplus of $3.6 million, with $39.4 million (the approximate Canadian dollar equivalent of $US 30.4 million) drawn under the loan agreement. Shareholders Equity, Dividends and Outstanding Share Data During the third quarter, 356,504 RSUs and 136,642 PSUs vested and were settled through the issuance of 493,146 common shares from treasury with a value of $246,000. At, Eagle had 44,243,634 shares issued and outstanding (December 31, ,301,986). As at the date of this MD&A, 44,243,634 shares are issued and outstanding and 1,835,240 RSUs and 598,069 PSUs are outstanding (December 31, ,635,668 RSUs and 607,956 PSUs). 19

21 EAGLE THIRD QUARTER REPORT 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, ,587 1,303 Total contractual obligations 3, ,587 1,303 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. At, 53 months and approximately $2.0 million remain. (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, to August 31, 2025, with payments beginning September 1,. Total minimum lease payments during the term of the lease approximate $CA 1.6 million ($US 1.2 million translated at the exchange rate in effect at the balance sheet date of $US 1.00 equal to $CA 1.29). At, 83 months and payments of approximately $CA 1.5 million remain ($US 1.1 million at the exchange rate in effect at the balance sheet date of $US 1.00 equal to $CA 1.29). (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, 37 months and payments totaling approximately $CA 1.0 million remain ($US 0.8 at the exchange rate in effect at the balance sheet date of $US 1.0 equal to $CA 1.29). 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 July 1, to During the period beginning on July 1, 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 third 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,, 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