DELPHI ENERGY CORP. REPORTS SECOND QUARTER 2018 RESULTS

DELPHI ENERGY CORP. REPORTS SECOND QUARTER 2018 RESULTS CALGARY, ALBERTA August 8, 2018 Delphi Energy Corp. ( Delphi or the Company ) is pleased to announce its financial and operational results for the quarter ended June 30, 2018. Second Quarter 2018 Highlights Produced 10,623 barrels of oil equivalent per day ( boe/d ) in the second quarter of 2018, a twelve percent increase from the 9,515 boe/d in the first quarter of 2018; Tied-in and brought on production three (1.95 net) Montney wells in Bigstone; Commissioned amine processing facility (65 percent working interest) allowing up to 17 million cubic feet per day ( mmcf/d ) of gross raw Montney natural gas to be sweetened prior to routing it through the Bigstone sweet natural gas plant (25 percent working interest) for final processing; Increased field condensate production by 16 percent to 2,858 barrels per day ( bbls/d ) and natural gas liquids by eleven percent to 1,575 bbls/d in comparison to the first quarter of 2018; Increased natural gas liquids and field condensate yields to 119 barrels per million cubic feet ( bbls/mmcf ), up nine percent from the 109 bbls/mmcf in the comparative quarter of 2017. Field and plant condensate yields are 87 bbls/mmcf, or 73 percent of the 119 bbls/mmcf; Field condensate and natural gas liquids accounted for 73 percent of crude oil and natural gas revenues and 42 percent of production; Realized a natural gas price, before risk management contracts and including marketing income, of $3.26 per thousand cubic feet ( mcf ) compared to an AECO price of $1.18 per mcf as a result of selling approximately 75 percent of our natural gas in Chicago, Illinois, via full-path transportation arrangements and generating marketing income from excess firm Alliance transportation; Cash netbacks per boe increased by 29 percent over the comparative quarter resulting in adjusted funds flow of $14.7 million, a 111 percent increase over the second quarter of 2017. Cash netbacks per boe increased 14 percent compared to the first quarter of 2018 resulting in a 29 percent increase in adjusted funds flow over the first quarter of 2018; and As a result of Delphi s lenders annual review of the Company s senior credit facility, the Company received an increase in the borrowing base of its credit facilities to $105.0 million. 1

FINANCIAL AND OPERATIONAL HIGHLIGHTS Financial ($ thousands, except per share) 2018 2017 % Change 2018 2017 % Change Crude Oil and natural gas revenues 36,394 20,162 81 69,069 45,833 51 Net earnings (loss) (5,834) 4,520 (229) (10,300) 12,676 (181) Per share basic and diluted (0.03) 0.03 (200) (0.06) 0.08 (175) Adjusted funds flow (1) 14,697 6,964 111 26,125 14,934 75 Per share basic and diluted (1) 0.08 0.04 100 0.14 0.09 56 Net debt (1) 155,402 90,638 71 155,402 90,638 71 Capital expenditures, net of dispositions 3,410 22,554 (85) 44,575 52,611 (15) Weighted average shares (000s) Basic 185,547 164,591 13 185,547 160,712 15 Diluted 185,547 165,612 12 185,547 162,171 14 Operating (boe conversion 6:1 basis) Production Field condensate (bbls/d) 2,858 1,540 86 2,666 1,738 53 Natural gas liquids (bbls/d) 1,575 1,019 55 1,497 1,160 29 Natural gas (mcf/d) 37,141 23,551 58 35,453 26,628 33 Total (boe/d) 10,623 6,484 64 10,072 7,336 37 Average realized sales prices, before financial instruments and marketing income (1) Field condensate ($/bbl) 77.24 59.74 29 73.89 60.39 22 Natural gas liquids ($/bbl) 44.74 27.02 66 44.36 29.92 48 Natural gas ($/mcf) 2.89 4.31 (33) 3.29 4.24 (22) Netbacks ($/boe) Crude oil and natural gas revenues 37.65 34.17 10 37.89 34.52 10 Marketing income (1) 1.30 1.72 (24) 1.28 0.77 66 Realized loss on financial instruments (3.41) 0.77 (543) (3.16) - - Revenue, after realized financial instruments 35.54 36.66 (3) 36.01 35.29 2 Royalties (1.30) (1.49) (13) (2.12) (2.48) (15) Operating expense (9.04) (11.15) (19) (9.25) (9.85) (6) Transportation expense (5.16) (6.03) (14) (5.30) (5.81) (9) Operating netback (1) 20.04 17.99 11 19.34 17.15 13 General and administrative expenses (1.41) (2.56) (45) (1.51) (2.80) (46) Interest (3.25) (3.63) (10) (3.31) (3.11) 6 Settlement of unutilized take-or-pay contract (0.18) - - (0.19) - - Cash netback (1) 15.20 11.80 29 14.33 11.24 27 (1) Refer to non-gaap measures 2

FINANCIAL HIGHLIGHTS FOR THE QUARTER ENDED JUNE 30, 2018 Having finished the drilling and completion operations for the 2017/2018 winter program in the first quarter, Delphi carried out a modest capital program in the second quarter, spending $3.4 million to tie-in three (1.95 net) wells and undertake various infrastructure projects. Capital spending in the first six months of 2018 amounted to $44.6 million. Average production was 10,623 boe/d for the quarter. Field condensate production was 2,858 bbls/d, accounting for 27 percent of production on a boe basis (compared to 24 percent in the second quarter of 2017) and 55 percent of crude oil and natural gas revenues. Total liquids (field condensate and NGL) production in the second quarter accounted for 42 percent of total production and 73 percent of crude oil and natural gas revenues. Quarterly crude oil and natural gas revenues were $36.4 million, an increase of 11 percent over the first quarter of 2018 due to increased production and higher condensate and NGL realized prices. A net hedging loss of $3.3 million was realized in the second quarter of which $3.7 million was due to WTI swaps on 2,500 bbls/d contracted at an average price of C$71.20 per barrel, offset by gains on natural gas hedges. The contracted volumes of WTI hedges decline to 2,100 bbls/d in the second half of 2018, 1,000 bbls/d in the first half of 2019, 600 bbls/d in the second half of 2019 and nil thereafter while the average contracted price increases to C$72.41 per barrel, C$73.29 per barrel and $72.29 per barrel, respectively. Adjusted funds flow increased 29 percent from the first quarter of 2018 to $14.7 million or $0.08 per basic and diluted share. Prior to hedging losses, adjusted funds flow was $18.0 million, equivalent to $72.0 million on an annualized basis which provides approximately $25.0 million of free cash flow above annual capital required to maintain production at current levels. The operating netback before hedging was $23.45 per boe while the corresponding cash netback before hedging was $18.61 per boe. After a hedging loss of $3.41 per boe, the operating and cash netbacks were $20.04 and $15.20 per boe, respectively. Bank debt at the end of the quarter was $69.7 million and outstanding letters of credit were $7.4 million, leaving $27.9 million available to be drawn on the Company s senior bank credit facility. Total debt including working capital deficiency, senior secured notes, and the unused take-or-pay contract liability at the end of the quarter was $155.4 million, $11.0 million lower than at the end of the first quarter. Capital spending, production and adjusted funds flow were all within the guidance provided by the Company on March 7, 2018 for the first six months of 2018 and on May 9, 2018 for the second quarter of 2018. NATURAL GAS TRANSPORTATION AND MARKETING Delphi has a total of 57 mmcf/d of firm and priority interruptible service on the Alliance pipeline system and 24 mmcf/d of firm service on the NGTL pipeline system. The proportion of natural gas sold in Chicago via Alliance decreased in the second quarter due to commissioning of the newly completed amine sweetening plant, as these volumes are sent for further processing at the Bigstone sweet gas plant which is currently only connected to NGTL. The Bigstone sweet gas plant will be connected to Alliance upon reactivation of the lateral pipeline, which is expected to occur in 2019. The net impact on adjusted funds flow is expected to be positive as the lower realized natural gas price is offset by lower operating costs, lower transportation costs and higher marketing income from the increase in excess Alliance service. Delphi generated $1.3 million ($1.30 per boe) of marketing income in the quarter from the excess service it holds on Alliance through a combination of temporary assignment to other shippers at a premium over cost or through the purchase of natural gas in Alberta or British Columbia for sale in Chicago. In the second quarter, the Company shipped 27.9 mmcf/d of natural gas on Alliance for sale in the Chicago market at an average realized price of $3.39 per mcf and 9.2 mmcf/d of natural gas on NGTL for sale in Alberta at an average realized price of $1.32 per mcf, resulting in a combined average realized price of $2.89 per mcf. The combined average realized price including hedging gain and marketing income was $3.39 per mcf compared to an average AECO price of $1.18. 3

HEDGING Commodity Hedges Q3 2018 Q4 2018 2019 Natural gas (mcf/d) 21.0 17.4 10.2 Average hedge price (C$/mcf) (2) 3.62 3.64 3.46 Crude oil (bbl/d) 2,100 2,100 798 Average hedge price (C$/bbl) 72.41 72.41 72.91 (1) Assumes an FX of 1.327 CAD per USD for the second half of 2018 and 2019. (2) Includes the impact of NYMEX HH natural gas Chicago basis hedges. OPERATIONS UPDATE In the second quarter, Delphi brought on three horizontal Montney wells, including the 15-19-59-23W5 ( 15-19 ) and 16-10-60-24W5 ( 16-10 ) West Bigstone wells. The most recent well to be brought on production was the 16-10 well through the 100 percent Company owned Negus sweet gas plant. Over the first 90 full days on production (IP90), the well flowed at an average rate of 3.7 mmcf/d of raw gas and 613 bbls/d of 42 degree API field condensate (177 bbls/mmcf of sales gas). Total sales production rate for 16-10 over this time period was approximately 1,226 boe/d including current estimated plant natural gas liquid ( NGL ) yield of 10 bbls/mmcf of sales gas. A new enhanced oil recovery ( EOR ) surfactant was trialed on a number of western wells including the 15-19 and 16-10 wells. The EOR surfactant is specifically designed to enhance oil/condensate production. Over the first 90 days of production the 15-19 and 16-10 wells recovered 54,500 bbls and 55,200 bbls of field condensate respectively, and continue to exceed offsetting well production performance. Delphi is also shifting its well designs to larger casing sizes allowing higher pump rates and decreased frac cycle time. The 16-10 well was the first to utilize a 5.5 frac string. Its estimated this reduced the frac cycle time by approximately 1.5 days while also providing a more effective stimulation through increased fracture complexity. A 60,000 cubic metre water storage hub is currently under construction, to enable efficient West Bigstone pad development and decrease water management costs. This will enable large scale 24 hour frac operations on future multiwell pads, while also providing security of water. In combination with the recently announced fluid disposal agreement with Catapult, full cycle water management costs and logistics will be reduced and simplified going forward. Delphi is also investigating a number of new water treatment technologies which may allow for re-use and recycling of frac flow-back fluid. During the second quarter, the Company commissioned the Phase I Amine processing facility and commenced delivering sweetened Montney gas on May 9 th to the under-utilized 85 mmcf/d Bigstone sweet natural gas plant (Delphi 25 percent working interest) for final processing. The new facility, capable of sweetening up to 17 mmcf/d of gross raw Montney natural gas, will enable reduced operating costs on that production stream by approximately $0.80 per mcf. Corporately, operating cost savings of approximately $0.70 per boe are forecast. The amine facility is part of the Company s long term strategy to diversify its processing options, which now include the SemCAMS K3 (sour), Repsol Edson (sour), Delphi Bigstone (sweet), and Delphi Negus (sweet) processing facilities. Given the current production volumes trending above budget, the Company reaffirms its full year 2018 production guidance of 10,000 to 10,200 boe/d, released on July 18, 2018. Delphi notes that the SemCAMS operated K3 natural gas plant was taken offline for 6 days due to unscheduled repairs near the end of July. Second half 2018 production guidance is tightened from the range of 10,000 to 10,400 boe/d previously released, to 10,000 to 10,200 boe/d as a result of this unscheduled outage. The Company has commenced its second half drilling program with the fifth and sixth wells of the 2018 program at 16-31- 59-23W5 and 13-18-60-22W5. Both these wells are close offsets to successful wells brought on production in the first half of 2018. Subsequent drills in the second half of 2018 are offsets to recent successful results at West Bigstone, at 16-10 and 15-19. INCENTIVE STOCK OPTIONS On June 20, 2018, the Board of Directors of the Company approved the granting of incentive stock options under its stock option plan to its employees, officers and directors to acquire up to an aggregate of 2,705,000 common shares of the Company at an exercise price of $0.89 per share. This grant follows the expiry of 815,002 options and 1,760,000 options on March 30, 2018 and April 25, 2018 respectively. 4

OUTLOOK Delphi expects to drill and complete four (2.60 net) wells in the second half of 2018 spending approximately 75 to 85 percent of the planned expenditures on the new wells, with the remaining capital focused on infrastructure and production optimization projects. The Company expects operating and cash netbacks to continue to grow as the Company follows up on recent liquids-rich, successful delineation wells in West Bigstone and realizes the full benefit of recent infrastructure investments, transitioning the Company to a growth model principally financed through adjusted funds flow. The Company looks forward to providing an update on its ongoing drilling program as information becomes available. 5

MANAGEMENT S DISCUSSION AND ANALYSIS (All tabular amounts are stated in thousands of dollars, except per unit amounts) Delphi Energy Corp. ( Delphi or the Company ) is an oil and gas company based in Calgary, Alberta, focused on the exploration, development, and production of crude oil, natural gas and natural gas liquids from properties located in Western Canada. Delphi s operations are concentrated in the Deep Basin of Northwest Alberta. The Company s common shares, senior secured notes, and warrants are listed on the Toronto Stock Exchange ( TSX ) under the symbol DEE, DEE.NT, and DEE.WT, respectively. Additional information about Delphi is available on the Canadian Securities Administrators System for Electronic Distribution and Retrieval (SEDAR) at www.sedar.com and at the Company s website at www.delphienergy.ca. Management s discussion and analysis ( MD&A ) has been prepared by management and reviewed and approved by the Board of Directors of Delphi Energy Corp. The discussion and analysis has been prepared as of August 7, 2018. The discussion and analysis is a review of the financial position and results of operations of the Company. Its focus is primarily a comparison of the financial performance for the three and six months ended June 30, 2018 and 2017 and should be read in conjunction with the unaudited condensed consolidated interim financial statements and accompanying notes for the three and six months ended June 30, 2018 and 2017 and the audited consolidated financial statements and accompanying notes for the year ended December 31, 2017 and the related MD&A. The unaudited condensed consolidated interim financial statements have been prepared in accordance with International Accounting Standard ( IAS ) 34, Interim Financial Reporting. The reporting currency is the Canadian dollar. SECOND QUARTER 2018 ACCOMPLISHMENTS Produced 10,623 barrels of oil equivalent per day ( boe/d ) in the second quarter of 2018, a 64 percent increase from 6,484 boe/d in the comparative quarter of 2017 and a twelve percent increase from the 9,515 boe/d in the first quarter of 2018; Tied-in and brought on production three (1.95 net) Montney wells in Bigstone; Commissioned its amine processing facility (65 percent working interest) allowing up to 17 million cubic feet per day ( mmcf/d ) of gross raw Montney natural gas to be sweetened prior to routing it through its 25 percent owned Bigstone sweet natural gas plant for final processing; Increased field condensate production by 86 percent to 2,858 barrels per day ( bbls/d ) and natural gas liquids by 55 percent to 1,575 bbls/d in comparison to the second quarter of 2017. In comparison to the first quarter of 2018, field condensate production increased by 16 percent and natural gas liquids increased by eleven percent; Increased natural gas liquids and field condensate yields to 119 barrels per million cubic feet ( bbls/mmcf ), up nine percent from the 109 bbls/mmcf in the comparative quarter of 2017. Field and plant condensate yields are 87 bbls/mmcf, or 73 percent of the 119 bbls/mmcf; Field condensate and natural gas liquids accounted for 73 percent of crude oil and natural gas revenues and 42 percent of production; Realized a natural gas price, before risk management contracts and including marketing income, of $3.26 per thousand cubic feet ( mcf ) compared to an AECO price of $1.18 per mcf as a result of selling approximately 75 percent of our natural gas in Chicago, Illinois, via full-path transportation arrangements and generating marketing income from excess firm Alliance transportation; Added $1.30 per barrel of oil equivalent ( boe ) to cash netback from marketing income generated from excess firm Alliance transportation service; Cash netbacks per boe increased by 29 percent over the comparative quarter resulting in adjusted funds flow of $14.7 million, a 111 percent increase over the second quarter of 2017. Cash netbacks per boe increased 14 percent compared to the first quarter of 2018 resulting in a 29 percent increase in adjusted funds flow over the first quarter of 2018; and As a result of Delphi s lenders annual review of the Company s senior credit facility, Delphi received an increase in the borrowing base of its credit facilities to $105.0 million. 6

FINANCIAL AND OPERATIONAL HIGHLIGHTS Financial ($ thousands, except per share) 2018 2017 % Change 2018 2017 % Change Crude oil and natural gas revenues 36,394 20,162 81 69,069 45,833 51 Net earnings (loss) (5,834) 4,520 (229) (10,300) 12,676 (181) Per share basic and diluted (0.03) 0.03 (200) (0.06) 0.08 (175) Adjusted funds flow (1) 14,697 6,964 111 26,125 14,934 75 Per share basic and diluted (1) 0.08 0.04 100 0.14 0.09 56 Net debt (1) 155,402 90,638 71 155,402 90,638 71 Capital expenditures, net of dispositions 3,410 22,554 (85) 44,575 52,611 (15) Weighted average shares (000s) Basic 185,547 164,591 13 185,547 160,712 15 Diluted 185,547 165,612 12 185,547 162,171 14 Operating (boe conversion 6:1 basis) Production Field condensate (bbls/d) 2,858 1,540 86 2,666 1,738 53 Natural gas liquids (bbls/d) 1,575 1,019 55 1,497 1,160 29 Natural gas (mcf/d) 37,141 23,551 58 35,453 26,628 33 Total (boe/d) 10,623 6,484 64 10,072 7,336 37 Average realized sales prices, before financial instruments and marketing income (1) Field condensate ($/bbl) 77.24 59.74 29 73.89 60.39 22 Natural gas liquids ($/bbl) 44.74 27.02 66 44.36 29.92 48 Natural gas ($/mcf) 2.89 4.31 (33) 3.29 4.24 (22) Netbacks ($/boe) Crude oil and natural gas revenues 37.65 34.17 10 37.89 34.52 10 Marketing income (1) 1.30 1.72 (24) 1.28 0.77 66 Realized loss on financial instruments (3.41) 0.77 (543) (3.16) - - Revenue, after realized financial instruments 35.54 36.66 (3) 36.01 35.29 2 Royalties (1.30) (1.49) (13) (2.12) (2.48) (15) Operating expense (9.04) (11.15) (19) (9.25) (9.85) (6) Transportation expense (5.16) (6.03) (14) (5.30) (5.81) (9) Operating netback (1) 20.04 17.99 11 19.34 17.15 13 General and administrative expenses (1.41) (2.56) (45) (1.51) (2.80) (46) Interest (3.25) (3.63) (10) (3.31) (3.11) 6 Settlement of unutilized take-or-pay contract (0.18) - - (0.19) - - Cash netback (1) 15.20 11.80 29 14.33 11.24 27 (1) Refer to non GAAP measures 7

2018 DRILLING AND COMPLETIONS OPERATIONS Well Location Gross Net Drilled Completed On-stream 100/15-19-059-23W5 1.0 0.65 Q4 2017 Q4 2017 Q1 2018 102/14-10-059-23W5 1.0 0.65 Q4 2017 Q1 2018 Q1 2018 102/16-07-060-23W5 1.0 0.65 Q4 2017 Q1 2018 Q1 2018 100/16-11-060-23W5 1.0 0.65 Q1 2018 Q1 2018 Q1 2018 100/16-19-059-23W5 1.0 0.65 Q1 2018 Q1 2018 Q2 2018 102/14-18-060-22W5 1.0 0.65 Q1 2018 Q1 2018 Q2 2018 100/16-10-060-24W5 1.0 0.65 Q1 2018 Q1 2018 Q2 2018 Total on-stream 7.0 4.55 Success rate (%) 100 100 In the first six months of 2018, Delphi drilled four (2.60 net) wells in the Montney formation at Bigstone. In comparison, Delphi drilled eight (5.10 net) wells in the first six months of 2017 which were also focused on the Bigstone Montney formation. CAPITAL EXPENDITURES 2018 2017 % Change 2018 2017 % Change Land 27 38 (29) 42 2,126 (98) Drilling, completions and equipping (109) 21,167 (101) 32,342 44,102 (27) Facilities 2,884 668 332 11,072 5,001 121 Capitalized expenses 580 674 (14) 1,135 1,411 (20) Other 28 78 (64) 54 88 (39) Capital invested 3,410 22,625 (85) 44,645 52,728 (15) Disposition of properties - (71) - (70) (117) (40) Total capital 3,410 22, 554 (85) 44,575 52,611 (15) Delphi s capital program during the second quarter of 2018 was focused on the completion and commissioning of its amine processing facility and infrastructure required to bring three (1.95 net) wells on-stream, which were completed during the first quarter of 2018. Delphi installed a battery and chemical natural gas sweetening unit at its 16-10-60-24W5 ( 16-10 ) well at West Bigstone, which is the first Montney well to be tied-in at the Company s 100 percent owned Negus sweet gas plant in West Bigstone. In the first half of 2018, Delphi invested $44.6 million, of which 72 percent was on drilling and completion operations. Delphi drilled four (2.60 net) wells and performed completion operations on six (3.90 net) wells in its Bigstone area. Two (1.30 net) of the wells completed were drilled in the fourth quarter of 2017. Approximately 25 percent of the capital invested was directed to facilities including the construction of the Company s amine processing facility and infrastructure required to bring seven (4.55 net) wells on-stream. One (0.65 net) of the wells brought on-stream in 2018 was completed during the fourth quarter of 2017. The amine processing facility is capable of sweetening up to 17 mmcf/d of gross raw Montney natural gas prior to routing it through its 25 percent owned Bigstone sweet natural gas plant for final processing and shipment through the Nova Gas Transmission system ( NGTL ). As of June 30, 2018, Delphi has a working interest in a total of 118.5 gross (78.4 net) sections of undeveloped land as part of 168.5 gross (110.6 net) sections of total land prospective for liquids-rich natural gas in the Montney formation, situated at its core area of Bigstone. 8

PRODUCTION 2018 2017 % Change 2018 2017 % Change Field condensate (bbls/d) 2,858 1,540 86 2,666 1,738 53 Ethane (bbls/d) 15 5 200 11 5 120 Propane (bbls/d) 739 473 56 694 527 32 Butane (bbls/d) 463 331 40 447 367 22 Pentanes & plant condensate (bbls/d) 358 210 70 345 261 32 Total field condensate and natural gas liquids (bbls/d) 4,433 2,559 73 4,163 2,898 44 Natural gas (mcf/d) 37,141 23,551 58 35,453 26,628 33 Total (boe/d) 10,623 6,484 64 10,072 7,336 37 Production volumes in the second quarter of 2018 averaged 10,623 boe/d, a 64 percent increase over the comparative quarter in 2017 and a twelve percent increase over the 9,515 boe/d in the first quarter of 2018. Production in the second quarter of 2017 was curtailed by approximately 2,500 boe/d due to a turnaround at SemCAMS K3 natural gas processing facility and a concurrent turnaround at Delphi s 7-11-60-23W5 compression and dehydration facility ( 7-11 ). Delphi brought three (1.95 net) wells on-stream during the quarter, two (1.30 net) in April and one (0.65 net) in May. Production was adversely impacted by approximately 400 boe/d due to the shut-in of a third party compressor for the majority of the quarter. Delphi s natural gas liquids and field condensate yields have increased from 109 bbls/mmcf in the second quarter of 2017 to 119 bbls/mmcf in the second quarter of 2018. Field and plant condensate yields have increased from 74 bbls/mmcf to 87 bbls/mmcf. Production volumes in the first half of 2018 averaged 10,072 boe/d, a 37 percent increase over the comparative period. Delphi has brought seven (4.55 net) wells on-stream during the first six months of 2018. In the first six months of 2018, Montney production was approximately 92 percent of the Company s total production, up from 89 percent in the first six months of 2017. Delphi s production portfolio for the second quarter of 2018 was weighted 27 percent to field condensate, 15 percent to natural gas liquids and 58 percent to natural gas on a boe basis. This compares to a production portfolio for the comparative quarter in 2017 that was weighted 24 percent to field condensate, 16 percent to natural gas liquids and 60 percent to natural gas on a boe basis. 9

BUSINESS ENVIRONMENT Benchmark Prices and Economic Parameters (1) Natural Gas 2018 2017 % Change 2018 2017 % Change NYMEX (US $/mmbtu) 2.80 3.19 (12) 2.89 3.25 (11) Chicago City Gate MI (US $/mmbtu) 2.58 3.01 (14) 2.91 3.20 (9) Chicago City Gate DI (US $/mmbtu) 2.67 2.92 (9) 2.81 2.95 (5) AECO 5A (CDN $/mcf) 1.18 2.79 (58) 1.63 2.74 (41) AECO 7A (CDN $/mcf) 1.03 2.77 (63) 1.43 2.86 (50) Crude Oil West Texas Intermediate (US $/bbl) 67.88 48.24 41 65.40 50.04 31 Edmonton Light (CDN $/bbl) 80.59 61.95 30 76.39 62.92 21 Condensate to Edmonton Light Differential (CDN $/bbl) 1.20 0.20 500 0.70 0.33 112 Foreign Exchange Canadian to U.S. dollar 0.77 0.74 4 0.78 0.75 4 U.S. to Canadian dollar 1.29 1.34 (4) 1.28 1.33 (4) (1) Prices and exchange rates presented above represent averages for the respective periods. Natural Gas After commissioning of the amine processing facility, Delphi now ships approximately 65 percent of its natural gas production through the Alliance pipeline system into the Chicago market. Chicago City Gate is the primary benchmark for Delphi s natural gas sales in the United States. The remainder of Delphi s natural gas production is sold in Alberta on the NGTL system. The AECO 5A price is the primary benchmark for the Company s natural gas sales in Alberta. The Chicago City Gate benchmark natural gas prices for the three and six months ended June 30, 2018 decreased in comparison to the same periods in 2017 primarily due to increased supply into the Chicago market. The average AECO benchmark natural gas prices weakened compared to the three and six months ended June 30, 2017 primarily due to growing natural gas supplies from Western Canada relative to the limited transportation capabilities to move natural gas out of Western Canada. Natural Gas Liquids Natural gas liquids include ethane, propane, butane, pentane, and plant condensate and are generally priced off light oil and natural gas prices. Ethane prices are correlated to natural gas prices while propane and butane prices trade at a discount to light oil prices depending on supply/demand conditions. Natural gas liquids pricing has generally been supported by improvements in West Texas Intermediate ( WTI ) crude oil prices. Crude Oil All of Delphi s condensate production is delivered and sold in Edmonton, Alberta through Pembina s pipeline systems. The price that Delphi receives for its condensate is primarily driven by the price of WTI, adjusted for changes in foreign exchange rates, transportation costs and quality differentials. The average WTI benchmark price improved 41 percent and 31 percent in the three and six months ended June 30, 2018 compared to the same periods of 2017. The increases were primarily due to a re-balancing of supply and demand for crude oil as well as lower global crude oil inventories. Canadian prices experienced a widening basis differential as well as an increase in the Canadian to U.S. dollar exchange rate. Edmonton Light averaged $80.59 per barrel in the second quarter of 2018 and $76.39 per barrel in the first half of 2018, up 30 percent and 21 percent compared to the same periods in 2017. 10

Canadian/United States Exchange Rate The value of the Canadian dollar against its U.S. counterpart averaged U.S. $0.77 and U.S. $0.78 for the three and six months ended June 30, 2018, a four percent increase in comparison to the same periods in 2017. As a producer of natural gas sold in the United States, an increase in the Canadian dollar has a negative effect on the price received for production. REALIZED SALES PRICES Chicago 2018 2017 % Change 2018 2017 % Change Chicago City Gate MI (Cdn$/mcf) 3.34 4.03 (17) 3.72 4.26 (13) Heating content and marketing ($/mcf) 0.05 0.68 (93) (0.04) 0.35 (111) Realized price before risk management contracts ($/mcf) 3.39 4.71 (28) 3.68 4.61 (20) AECO AECO 5A ($/mcf) 1.18 2.79 (58) 1.63 2.74 (41) Heating content and marketing ($/mcf) 0.14 0.77 (82) (0.05) 0.53 (109) Realized price before risk management contracts ($/mcf) 1.32 3.56 (63) 1.58 3.27 (52) Combined Natural Gas Realized natural gas price before risk management contracts ($/mcf) 2.89 4.31 (33) 3.29 4.24 (22) Realized gain (loss) on financial contracts ($/mcf) 0.13 0.15 (13) (0.02) 0.02 (200) Realized natural gas price ($/mcf) 3.02 4.46 (32) 3.27 4.26 (23) Marketing income ($/mcf) (1) 0.37 0.47 (21) 0.36 0.21 71 Natural gas price including marketing income ($/mcf) 3.39 4.93 (31) 3.63 4.47 (19) Field Condensate Edmonton Light ($/bbl) 80.59 61.95 30 76.39 62.92 21 Condensate to Edmonton Light Differential ($/bbl) 1.20 0.20 500 0.70 0.33 112 Differential ($/bbl) (4.55) (2.41) 89 (3.20) (2.86) 12 Realized price before risk management contracts ($/bbl) 77.24 59.74 29 73.89 60.39 22 Realized loss on financial contracts ($/bbl) (14.39) 1.00 (1,539) (11.60) (0.37) (3,035) Realized field condensate price ($/bbl) 62.85 60.74 3 62.29 60.02 4 Natural Gas Liquids Realized natural gas liquids price ($/bbl) 44.74 27.02 66 44.36 29.92 48 Total realized sales price ($/boe) 34.24 34.94 (2) 34.73 34.50 1 (1) Refer to non GAAP measures. In May of 2018, the Company commissioned its amine processing facility, allowing up to 11 mmcf/d net raw Montney natural gas to be processed at its 25 percent owned Bigstone sweet natural gas plant for final processing and shipment through NGTL. In addition, the Company s 100 percent owned Negus sweet gas plant in West Bigstone is tied into the NGTL system. The remaining Montney natural gas production is processed at sour gas processing facilities that are dually connected to the Alliance pipeline system for shipment into Chicago, Illinois or NGTL. The majority of Delphi s non-core properties are tied-in to NGTL. With its natural gas market and natural gas processing diversification, Delphi now ships approximately 65 percent of its natural gas into the Chicago market with the remainder sold in Alberta. In the three months ended June 30, 2018, approximately 75 percent of its natural gas was shipped on Alliance and sold in the Chicago market with the remainder sold in Alberta. 11

Delphi generally receives a higher price for its natural gas per mcf due to its high heat content. Differentials for marketing are caused by benchmark price differences between the daily and monthly indices. Delphi sells approximately half of the natural gas volumes that are shipped on the Alliance pipeline system on the monthly index and the other half on the daily index. Substantially all of natural gas volumes shipped on NGTL are sold with reference to AECO 5A index and the remainder with reference to AECO 7A. For the three months and six months ended June 30, 2018, Delphi s realized natural gas price before risk management contracts decreased 33 percent and 22 percent in comparison to the same periods in 2017 primarily due to a decrease in benchmark pricing, an improvement in the Canadian dollar against its U.S. counterpart and an increase of natural gas sales volumes sold in Alberta which sustained lower relative prices. Including risk management contracts and marketing income, Delphi s natural gas price was $3.39 per mcf and $3.63 per mcf for the three and six months ended June 30, 2018. Realized field condensate prices before risk management contracts were 29 percent and 22 percent higher in the three and six months ended June 30, 2018, compared to the same periods in 2017 primarily due to an improvement in benchmark prices. The differential for the Company s field condensate increased in the three and twelve months ended June 30, 2018 principally due to an increase in density of the product. Delphi s realized natural gas liquids price for the three and six months ended June 30, 2018 increased 66 percent and 48 percent compared to the same period in 2017 as a result of improved benchmark prices for all natural gas liquids. RISK MANAGEMENT ACTIVITIES Delphi enters into financial commodity contracts as part of its risk management program to manage commodity price fluctuations designed to protect cash flows through to simple payout on the drilling and completion portion of its capital program. With respect to financial contracts, which are derivative financial instruments, management has elected not to use hedge accounting and consequently records the fair value of its natural gas and crude oil financial contracts on the statement of financial position at each reporting period with the change in the fair value being classified as unrealized gains and losses in the consolidated statement of earnings (loss). Natural Gas Contracts Time Period Type of Contract Quantity Contracted Price ($/unit) Reference January 2017 December 2018 Financial Swap 3,000 mmbtu/d $2.773 U.S. NYMEX April 2017 October 2018 Financial Swap 2,500 mmbtu/d $4.160 Cdn NYMEX January 2018 December 2018 Financial Swap 3,000 mmbtu/d $4.010 Cdn NYMEX January 2018 December 2018 Financial Swap 2,500 mmbtu/d $4.173 Cdn NYMEX January 2018 December 2019 Financial Swap 2,000 mmbtu/d $4.018 Cdn NYMEX January 2018 December 2019 Financial Swap 5,000 mmbtu/d $3.840 Cdn NYMEX February 2018 October 2018 Financial Swap 3,000 mmbtu/d $2.705 U.S. NYMEX January 2019 December 2019 Financial Swap 3,000 mmbtu/d $3.550 Cdn. NYMEX Crude Oil Contracts Time Period Type of Contract Quantity Contracted Price ($/unit) Reference January 2017 December 2019 Financial Swap 300 bbls/d $70.00 Cdn WTI January 2018 December 2018 Financial Swap 250 bbls/d $71.60 Cdn WTI January 2018 December 2018 Financial Swap 250 bbls/d $72.00 Cdn WTI January 2018 December 2018 Financial Swap 300 bbls/d $70.70 Cdn WTI February 2018 December 2018 Financial Swap 500 bbls/d $73.95 Cdn WTI February 2018 December 2018 Financial Swap 500 bbls/d $73.95 Cdn WTI January 2019 June 2019 Financial Swap 400 bbls/d $74.80 Cdn WTI January 2019 December 2019 Financial Swap 300 bbls/d $56.20 U.S. WTI 12

Basis Differential Contracts Delphi ships the majority of its natural gas production through the Alliance pipeline system into the Chicago market. As a result, the Company has entered into Chicago NYMEX basis differential contracts in order to fix the basis on a portion of its natural gas sales in the Chicago market. Time Period Type of Contract Quantity Contracted Differential (U.S. $/unit) January 2018 December 2018 Financial Swap 4,000 mmbtu/d ($0.215) January 2018 December 2018 Financial Swap 4,000 mmbtu/d ($0.208) January 2018 December 2018 Financial Swap 4,000 mmbtu/d ($0.200) January 2018 December 2018 Financial Swap 4,000 mmbtu/d ($0.180) April 2018 March 2019 Financial Swap 4,000 mmbtu/d ($0.235) January 2019 March 2019 Financial - Swap 3,000 mmbtu/d ($0.110) April 2019 October 2019 Financial Swap 7,000 mmbtu/d ($0.400) November 2019 March 2020 Financial Swap 7,000 mmbtu/d ($0.135) April 2019 October 2019 Financial Swap 3,000 mmbtu/d ($0.390) January 2019 March 2019 Financial Swap 3,000 mmbtu/d ($0.105) November 2019 March 2020 Financial Swap 3,000 mmbtu/d ($0.120) January 2019 December 2019 Financial Swap 2,500 mmbtu/d ($0.195) January 2019 December 2019 Financial Swap 2,500 mmbtu/d ($0.190) U.S Forward Exchange Contracts Delphi sells the majority of its natural gas in the Chicago market in U.S. dollars. In order to mitigate the U.S. to Canadian dollar fluctuation, Delphi has entered into the following U.S. dollar forward exchange contracts: Time Period Average Notional U.S. $ Average Exchange Rate (U.S.$ to Cdn$) May 2015 December 2018 250.0 1.2574 January 2018 December 2018 800.0 1.2805 January 2018 December 2018 400.0 1.2820 April 2018 December 2018 100.0 1.2935 January 2019 December 2019 500.0 1.2860 January 2019 December 2019 115.0 1.2965 Fair value of Delphi s risk management contracts The fair value of the financial contracts outstanding as at June 30, 2018 is estimated to be a net liability of $12.1 million. The fair values of these contracts are based on an approximation of the amounts that would have been paid to or received from counterparties to settle the contracts outstanding at the end of the period having regard to forward prices and market values provided by independent sources. Due to the inherent volatility in commodity prices, foreign exchange and interest rates, actual amounts realized may differ from these estimates. For the three and six months ended June 30, 2018, Delphi recorded an unrealized loss on its risk management contracts of $8.1 million and $13.0 million primarily due to an increase in the benchmark price for oil price futures relative to Delphi s fixed contract positions. The unrealized loss recognized for the three months ended June 30, 2018 is the difference between the fair values of the risk management contracts outstanding as at June 30, 2018 and the fair values as at March 31, 2018. The unrealized loss recognized for the six months ended June 30, 2018 is the difference between the fair values of the risk management contracts outstanding as at June 30, 2018 and the fair values as at December 31, 2017. For the three and six months ended June 30, 2018, the risk management contracts resulted in a realized loss of $3.3 million and $5.8 million due to lower average pricing for the Company s crude oil risk management contracts relative to the benchmark commodity prices during the respective periods. 13

REVENUE 2018 2017 % Change 2018 2017 % Change Field condensate 20,088 8,372 140 35,656 18,998 88 Natural gas 9,767 9,236 6 21,130 20,437 3 Natural gas liquids 6,413 2,505 156 12,021 6,282 91 Sulphur 126 49 157 262 116 126 Total 36,394 20,162 81 69,069 45,833 51 Per boe 37.65 34.17 10 37.89 34.52 10 Delphi generated revenue of $36.4 million in the second quarter of 2018, an 81 percent increase over the comparative period in 2017. Revenue in the first six months of 2018 was 51 percent higher in comparison to the first six months of 2017. The increase in revenue is due to higher production volumes, in particular field condensate and natural gas liquids, in combination with an improvement in the average sales price (excluding risk management contracts) for field condensate and natural gas liquids. On a per boe basis, revenue increased for the three and six months ended June 30, 2018 compared to the comparative periods in 2017 as Delphi s field condensate and natural gas liquids production increased in combination with improved pricing for those products. The increase in volumes in the second quarter of 2018 from the second quarter of 2017 contributed $14.2 million of the increase in revenue and the increase in the average combined realized price (excluding risk management contracts) contributed $2.0 million of the increase. For the second quarter of 2018, field condensate and natural gas liquids contributed 73 percent of the total revenue compared to 54 percent in the same period in 2017. The increase in volumes in the first six months of 2018 from the first six months of 2017 contributed $18.8 million of the increase in revenue and the increase in the average combined realized price (excluding risk management contracts) contributed $4.4 million of the increase. For the first half of 2018, field condensate and natural gas liquids contributed 69 percent of the total revenue compared to 55 percent in the same period in 2017. In comparison, revenue in the second quarter of 2018 increased eleven percent from the first quarter of 2018. The twelve percent increase in production volumes contributed to $4.1 million in revenue partially offset by $0.4 million as a result of a lower average combined sales price (excluding risk management contracts). MARKETING Marketing Revenue 2018 2017 % Change 2018 2017 % Change Sale of purchased natural gas 636 - - 1,222 - - Premiums on the assignment of service 1,059 1,016 4 1,938 1,016 91 Total 1,695 1,016 67 3,160 1,016 211 Marketing Expense 2018 2017 % Change 2018 2017 % Change Cost of purchased natural gas 237 - - 476 - - Transportation of purchased natural gas 206 - - 359 - - Total 443 - - 835 - - 14

Marketing Income (1) 2018 2017 % Change 2018 2017 % Change Gain (loss) on marketing of purchased natural gas 193 - - 387 - - Premium on the assignment of service 1,059 1,016 4 1,938 1,016 91 Total 1,252 1,016 23 2,325 1,016 129 Per boe 1.30 1.72 (24) 1.28 0.77 66 (1) Refer to non GAAP measures Delphi has contracted for approximately 45.8 mmcf/d of firm transportation service and 11.4 mmcf/d of priority interruptible service on the Alliance pipeline system from Alberta to Chicago. This service is comprised of various tranches commencing December 2015 through December 2017, with provisions to renew commencing October 2020. In order to mitigate the cost of transportation service in excess of its needs, Delphi either temporarily assigns the excess service to other shippers or purchases natural gas in Alberta or British Columbia for sale in Chicago. Marketing income has increased in the three and six months ended June 30, 2018, as the Company has additional firm capacity on the Alliance pipeline and is shipping additional volumes on NGTL due to the commissioning of its amine processing facility. ROYALTIES 2018 2017 % Change 2018 2017 % Change Crown royalties 1,740 974 79 3,498 2,196 59 Royalty credits (958) (1,170) (18) (1,631) (1,550) 5 Crown royalties net 782 (196) (499) 1,867 646 189 Gross overriding royalties 473 1,075 (56) 2,003 2,641 (24) Total 1,255 879 43 3,870 3,287 18 Per boe 1.30 1.49 (13) 2.12 2.48 (15) 2018 2017 % Change 2018 2017 % Change Crown rate before royalty credits 4.8% 4.8% - 5.1% 4.8% 6 Crown rate net of royalty credits 2.2% (1.0)% (320) 2.7% 1.4% 93 Gross overriding rate 1.3% 5.3% (75) 2.9% 5.7% (49) Average rate 3.4% 4.3% (21) 5.6% 7.1% (21) The royalty rate calculations above exclude gains or losses on risk management activities from revenue as the denominator. For the three and six months ended June 30, 2018, royalties totaled $1.3 million and $3.9 million, respectively, compared to $0.9 million and $3.3 million in the same periods in 2017. Crown royalties increased in the three and six months ended June 30, 2018 as a result of higher production volumes in combination with a higher proportion of field condensate and natural gas liquids production and an increase in benchmark prices for the respective products. All of Delphi s wells in the Montney qualify for Crown incentive programs which have a low initial royalty rate until a threshold return of capital has been reached, as determined by the Crown. Royalty credits, the cost of processing the Crown s share of natural gas production, decreased 18 percent in the three months ended June 30, 2018 compared to the same period in 2017 and increased five percent in the first six months of 2018 over the comparative period in 2017. The three months ended June 30, 2018 and 2017 include $0.2 million and $0.4 million of additional Crown royalty credits related to prior periods as a result of the Crown s annual review of actual capital and operating costs of gas facilities. The Crown royalty credits are largely based on the amortization of historical capital and operating costs of gas facilities and do not fluctuate based on commodity prices. Gross overriding royalties decreased in the three and six months ended June 30, 2018 as overall production from wells encumbered with a gross overriding royalty decreased due to natural declines and an adjustment related to a prior period, partially offset by an increase in benchmark prices. The gross overriding royalty rate decreased 75 percent and 49 percent in the three and six months ended June 30, 2018 compared to the respective periods in 2017 as the majority of additional sales volumes are not encumbered with a gross overriding royalty and due to an adjustment related to a prior period. 15

OPERATING EXPENSES 2018 2017 % Change 2018 2017 % Change Operating costs 9,019 6,877 31 17,330 13,509 28 Processing recoveries (282) (296) (5) (473) (435) 9 Total 8,737 6,581 33 16,857 13,074 29 Per boe 9.04 11.15 (19) 9.25 9.85 (6) Approximately 83 percent of operating expenses consisted of the lifting and processing costs associated with the Company s production from its Montney property in Bigstone. The remaining expenses are associated with the Company s non-core properties. During the three and six months of 2018, operating expenses increased 33 percent and 29 percent, respectively, over the comparative periods in 2017. The increase is due to higher production volumes and higher field activity to support ongoing operations. Production expenses on a boe basis decreased 19 percent and six percent, respectively over the comparative periods, as the Company s additional production volumes are from its Montney property, which has a lower cost structure in comparison to the Company s non-core properties. In comparison, operating expenses in the second quarter of 2018 increased eight percent over the first quarter of 2018. On a per boe basis, production expenses decreased five percent to $9.04 per boe in the second quarter of 2018 from $9.48 per boe in the first quarter of 2018. Although the Company s amine processing facility was not fully commissioned until the second week of May, Delphi is starting to realize the benefit from reduced processing and gathering fees associated with the sweetened Montney natural gas volumes that are being processed at Delphi s 25 percent owned natural gas processing facility. Delphi recovers processing costs on partner production volumes processed at facilities it owns. The processing recoveries represent a reduction of the Company s costs to operate these facilities and hence is deducted in determining operating expenses. Processing recoveries in the three and six months ended June 30, 2018 are comparable to the same periods in 2017. TRANSPORTATION EXPENSES 2018 2017 % Change 2018 2017 % Change Transportation 4,989 3,558 40 9,662 7,715 25 Per boe 5.16 6.03 (14) 5.30 5.81 (9) The Company s transportation expenses consist of shipping its natural gas volumes through the Alliance or NGTL pipeline system, trucking field condensate to sales terminals and shipping its natural gas liquids through the Pembina pipeline system. During the three and six months ended June 30, 2018, transportation expenses increased 40 percent and 25 percent, respectively, over the comparative periods in 2017. The increase is primarily due to higher condensate trucking charges as field condensate production increased 86 percent and 53 percent in the first three and six months ended June 30, 2018 over the comparative periods in 2017. Delphi has committed capacity on the Alliance and NGTL pipeline systems. Delphi mitigates its excess natural gas transportation by assigning it to a third party and collecting a premium for the assignment or by purchasing third party natural gas in Alberta or British Columbia and selling it at Chicago (see Marketing above for further details). Transportation expenses on a boe basis have decreased 14 percent and nine percent in the three and six months ended June 30, 2018 compared to the respective periods in 2017 as production volumes have increased. For the three months ended June 30, 2018, transportation expenses are six percent higher than the $4.7 million of transportation expenses in the first quarter of 2018 as production volumes have increased by twelve percent over the first quarter of 2018. 16

GENERAL AND ADMINISTRATIVE 2018 2017 % Change 2018 2017 % Change Gross expenses 1,944 2,186 (11) 3,896 5,125 (24) Capitalized (580) (674) (14) (1,135) (1,411) (20) General and administrative expenses 1,364 1,512 (10) 2,761 3,714 (26) Per boe 1.41 2.56 (45) 1.51 2.80 (46) General and administrative expenses (after capitalization) for the three and six months ended June 30, 2018 were ten percent and 26 percent lower compared to the same periods in 2017. Gross expenses in 2018 are lower than the comparative periods largely due to employee termination payments in the first quarter of 2017 and reduced office rent in 2018 as the Company moved offices during the third quarter of 2017. Capitalized general and administrative expenses decreased over the comparative period primarily due to reduced expenses. SHARE-BASED COMPENSATION 2018 2017 % Change 2018 2017 % Change Share-based compensation Options 221 392 (44) 504 688 (27) Share-based compensation RSUs - 11 (100) - (46) (100) Capitalized costs (58) (141) (59) (130) (226) (42) Net 163 262 (38) 374 416 (10) Per boe 0.17 0.44 (61) 0.21 0.31 (32) Share-based compensation expense is the amortization over the vesting period of the fair value of stock options and restricted share units ( RSUs ) granted to employees, directors and key consultants of the Company. The fair value of RSUs is based on the Company s closing share price on the last business day immediately preceding the vesting date or the Company s closing share price on the last business day immediately preceding the statement of financial position date. The fair value of all options granted is estimated at the date of grant using the Black-Scholes option pricing model. Share-based compensation expense related to the Company s option plan decreased 44 percent and 27 percent for the three and six months ended June 30, 2018 as compared to the same periods in 2017, respectively. The decrease in the share-based compensation expense related to Delphi s option plan is due to a higher number of outstanding options that are in their second or third year of vesting. Delphi recognizes the expense associated with its options on a graded vesting schedule basis which recognizes the majority of the expense in the first year of vesting. Share-based compensation expense related to the Company s RSUs decreased in the three and six months ended June 30, 2018 in comparison to the same periods in 2017 as the remaining restricted share units fully vested during the third quarter of 2017. Capitalized share-based compensation decreased in the three and six months ended June 30, 2018 compared to the same period in 2017 as a result of no expense related to restricted share units and a reduction in expense related to the Company s option plan. 17