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Birchcliff Energy Ltd. Announces Unaudited 2017 Year-End and Fourth Quarter Results, 2017 Reserves Highlights and 2018 Capital Program

CALGARY, Alberta, Feb 14, 2018 (GLOBE NEWSWIRE via COMTEX) --

Birchcliff Energy Ltd. ("Birchcliff") (TSX:BIR) is pleased to announce its unaudited 2017 year-end and fourth quarter financial and operational results, highlights from its independent reserves evaluations effective December 31, 2017 and its 2018 capital expenditure program. Birchcliff is also pleased to provide an operational overview and update.

Message to Shareholders

Birchcliff achieved record quarterly average production of 80,103 boe/d and funds flow from operations of $97.0 million in the fourth quarter of 2017 and record annual average production of 67,963 boe/d and funds flow from operations of $317.7 million in 2017. We sold high-cost producing properties and replaced the production with the drill bit, adding low-cost oil and natural gas production in Gordondale and Pouce Coupe. In addition, we brought our 80 MMcf/d Phase V expansion of our Pouce Coupe gas plant on-stream in the third quarter of 2017. As a result, our per boe operating costs in the fourth quarter of 2017 were 10% lower than the third quarter of 2017 and 17% lower than the second quarter of 2017. Our production per share was up 31% in the fourth quarter of 2017 as compared to the fourth quarter of 2016. We were successful at adding profitable production with positive recycle ratios. Our proved developed producing reserves at December 31, 2017 increased to 197,955.1 Mboe from 165,507.0 Mboe at December 31, 2016, reflecting our drilling success and production additions. Lastly, we began paying a quarterly dividend to our common shareholders in 2017 at an annual rate of $0.10 per share. We accomplished all of the foregoing while keeping our total debt flat at approximately $598 million.

In light of current economic conditions and what we believe to be a disconnect between the value of our business and our stock price, we are dedicated to strict capital discipline and are in a position to generate free funds flow from operations in 2018 while also providing strong annual average production growth. Our board of directors has approved a capital expenditure budget of $255 million for 2018 which targets an annual average production rate of 76,000 boe/d to 78,000 boe/d in 2018 (approximately 20% oil and NGLs). We expect that our 2018 capital expenditures will be less than our funds flow from operations during 2018. Our 2018 capital program is designed to maintain a prudent pace of development, protect our balance sheet and provide for the payment of a sustainable quarterly dividend to our shareholders. Of the $255 million budgeted for 2018, approximately $149.9 million has been allocated for drilling and development and $66.9 million for facilities and infrastructure. Our drilling program will focus on drilling liquids-rich natural gas and oil wells and our low-decline, low-cost producing assets are expected to generate a profitable return at a low commodity price.

We have executed on our business plan despite poor economic conditions. We are positioning Birchcliff for future growth while we protect our balance sheet. We thank all of our stakeholders and our staff for their support.

2017 Fourth Quarter Highlights

Highlights of the fourth quarter of 2017 include the following:

-- Record quarterly average production of 80,103 boe/d, a 32% increase from 60,750 boe/d in the fourth quarter of 2016. Production consisted of approximately 80% natural gas, 7% light oil and 13% NGLs as compared to 79% natural gas, 8% light oil and 13% NGLs in the fourth quarter of 2016.

-- Quarterly funds flow from operations of $97.0 million, or $0.36 per basic common share, a 35% increase and a 33% increase, respectively, from $71.8 million and $0.27 per basic common share in the fourth quarter of 2016.

-- Birchcliff recorded net income to common shareholders of $24.8 million ($0.09 per basic common share), as compared to net income to common shareholders of $11.1 million ($0.04 per basic common share) in the fourth quarter of 2016.

-- Operating costs of $3.86/boe, a 15% decrease from $4.54/boe in the fourth quarter of 2016.

-- General and administrative expense of $1.28/boe, an 8% increase from $1.19/boe in the fourth quarter of 2016.

-- Interest expense of $0.97/boe, a 31% decrease from $1.40/boe in the fourth quarter of 2016.

-- Net capital expenditures of $18.7 million.

-- Birchcliff drilled a total of 2 (2.0 net) wells in the fourth quarter of 2017, both of which were Montney/Doig horizontal natural gas wells in the Pouce Coupe area.

-- In addition to Birchcliff's oil drilling at Gordondale, Birchcliff recently drilled a four-well pad at Pouce Coupe which came on-stream in November 2017. This pad has shown strong production rates on an IP60 day basis. The four well average IP60 production rate was 1,280 boe/d (6.2 MMcf/d of raw natural gas, 239 bbls/d of 54° API condensate (condensate gas ratio of approximately 38 bbls/MMcf)) with an average flowing casing pressure on day 60 of 11.6 MPa.

For further information, please see "2017 Unaudited Fourth Quarter Financial and Operational Results" in this press release.

2017 Year-End Highlights

Highlights of the year ended December 31, 2017 include the following:

-- Record annual average production 67,963 boe/d, a 38% increase from 49,236 boe/d in 2016. Production consisted of approximately 79% natural gas, 9% light oil and 12% NGLs as compared to 83% natural gas, 8% light oil and 9% NGLs in 2016.

-- Funds flow from operations of $317.7 million, or $1.20 per basic common share, a 115% increase and a 62% increase, respectively, from $147.4 million and $0.74 per basic common share in 2016.

-- Birchcliff recorded a net loss to common shareholders of $51.0 million ($0.19 per basic common share), as compared to the net loss to common shareholders of $28.3 million ($0.14 per basic common share) in 2016. Included in the net loss for 2017 is an after-tax book loss of $132.3 million resulting from the sale of Birchcliff's Worsley Charlie Lake Light Oil Pool which closed on August 31, 2017.

-- Operating costs of $4.45/boe, a 6% increase from $4.18/boe in 2016.

-- General and administrative expense of $1.07/boe, a 10% decrease from $1.19/boe in 2016.

-- Interest expense of $1.14/boe, a 32% decrease from $1.68/boe in 2016.

-- Net capital expenditures of $276.1 million and total capital expenditures of $416.8 million in 2017.

-- Total debt at December 31, 2017 was $598.2 million, as compared to $600.0 million at December 31, 2016.

-- Birchcliff drilled a total of 54 (54.0 net) wells in 2017, consisting of 16 (16.0 net) Montney horizontal oil and natural gas wells in the Gordondale area, 37 (37.0 net) Montney/Doig horizontal natural gas wells in the Pouce Coupe area and 1 (1.0 net) Montney/Doig vertical science and technology well in the Pouce Coupe area. Birchcliff brought a total of 61 (61.0 net) wells on production during 2017.

-- The 80 MMcf/d Phase V expansion of Birchcliff's 100% owned and operated natural gas processing plant in Pouce Coupe (the "Pouce Coupe Gas Plant") was successfully brought on-stream in the third quarter of 2017, increasing the total processing capacity of the plant to 260 MMcf/d from 180 MMcf/d.

-- During 2017, Birchcliff completed asset sales for total proceeds of approximately $148 million (before adjustments), including the disposition of its Worsley Charlie Lake Light Oil Pool for total proceeds of approximately $100 million (before adjustments) ($90 million in cash; $10 million in securities) which closed in the third quarter of 2017.

-- During 2017, Birchcliff reduced its exposure to pricing at AECO and diversified the natural gas markets it sells to. Birchcliff entered into agreements for the firm service transportation of an aggregate of 175,000 GJ/d (approximately 152 MMcf/d) of natural gas on TCPL's Canadian Mainline for a 10-year term, whereby natural gas is transported to the Dawn trading hub located in Southern Ontario. The first tranche of this service (120,000 GJ/d) became available to Birchcliff on November 1, 2017, with additional tranches becoming available on November 1, 2018 (35,000 GJ/d) and November 1, 2019 (20,000 GJ/d).

-- Birchcliff began paying a quarterly dividend to its common shareholders during 2017 in the amount of $0.10 per share per year ($0.025 per share per quarter).

For further information, please see "2017 Unaudited Year-End Financial and Operational Results" in this press release.

2018 Capital Expenditure Program and 2018 Guidance

-- Birchcliff's board of directors has approved a capital expenditure budget for 2018 of $255 million. Approximately $149.9 million has been allocated for drilling and development, $66.9 million for facilities and infrastructure and $17.1 million for sustaining and optimization.

-- Highlights of Birchcliff's 2018 capital expenditure program (the "2018 Capital Program") include the following: <p>-- The program contemplates the drilling, completing, equipping and bringing on production of a total of 27 (27.0 net) wells during 2018 and targets an annual average production rate for 2018 in the range of 76,000 to 78,000 boe/d.

-- The program contemplates the drilling, completing, equipping and bringing on production of a total of 27 (27.0 net) wells during 2018 and targets an annual average production rate for 2018 in the range of 76,000 to 78,000 boe/d.

-- The 2018 Capital Program is expected to be fully funded from Birchcliff's 2018 funds flow from operations, based on the assumptions contained herein.

-- A continued focus on oil and NGLs production and field delineation of the Montney D1 and D2 intervals in Gordondale and further exploration and delineation of liquids-rich trends in the Montney D1, D2 and C intervals in Pouce Coupe.

-- A continued commitment to science and technology to drive operational excellence and further Birchcliff's learnings on field development planning.

-- Completion of the 80 MMcf/d Phase VI expansion of the Pouce Coupe Gas Plant and other strategic infrastructure projects to provide for future growth. Approximately $25.7 million has been allocated towards the completion of Phase VI which is expected to come on-stream in October 2018. In addition, Phases V and VI of the plant are being re-configured to allow for shallow-cut capability to remove propane plus ("C3+") liquids from the natural gas stream.

For further information, please see "2018 Capital Program" and "Outlook and Guidance".

2017 Year-End Reserves Highlights

-- The following table summarizes the estimates of Birchcliff's gross reserves at December 31, 2017 and December 31, 2016, as estimated by Birchcliff's independent qualified reserves evaluators using the forecast price and cost assumptions in effect at the applicable reserves evaluation date:

Reserves Category          December 31, 2017 December 31, 2016 Change from
                           (Mboe)            (Mboe)            December 31, 2016
Proved Developed Producing 197,955.1         165,507.0         20%
Total Proved               664,480.5         548,523.8         21%
Probable                   308,034.8         331,940.0         (7%)
Total Proved Plus Probable 972,515.3         880,463.8         10%

-- Birchcliff added 65,974.3 Mboe of proved developed producing reserves during 2017, a 40% increase from December 31, 2016, after excluding the effects of acquisitions and dispositions and adding back 2017 actual production of 24,806.3 Mboe.

-- Birchcliff added 2.7 boe of proved developed producing reserves for each boe that was produced in 2017, after excluding the effects of acquisitions and dispositions and adding back 2017 actual production.

-- The increases in the proved and proved plus probable reserves volumes is primarily attributable to: (i) the success of Birchcliff's 2017 drilling program which resulted in more potential future drilling locations to which reserves were assigned; and (ii) positive technical revisions as a result of improved well performance. Birchcliff achieved increases in its proved and proved plus probable reserves at December 31, 2017, notwithstanding the various dispositions completed during 2017 and economic factors resulting from a lower commodity price forecast.

-- The estimated net present value at December 31, 2017 (before taxes, discounted at 10%) was $1.9 billion for Birchcliff's proved developed producing reserves ($1.9 billion at December 31, 2016) and $5.1 billion ($5.8 billion at December 31, 2016) for its proved plus probable reserves, notwithstanding a lower commodity price forecast and the various dispositions Birchcliff completed during 2017.

-- Reserves life index of 7.0 years on a proved developed producing basis, 23.6 years on a proved basis and 34.6 years on a proved plus probable basis, based on a forecast production rate of 77,000 boe/d (which represents the mid-point of Birchcliff's annual average production guidance range for 2018).

-- The following table sets forth Birchcliff's reserves per common share:

Reserves Per Common Share  December 31, 2017          December 31, 2016          Increase from
                           (boe/1,000 shares)         (boe/1,000 shares)         December 31, 2016
Proved Developed Producing 744.8                      626.8                      19%
Total Proved               2,500.0                    2,077.4                    20%
Total Proved Plus Probable 3,658.9                    3,334.6                    10%
(1) Please see "Advisories - Oil and Gas Metrics" for a description of the methodology used to calculate reserves per common share.

For further information, please see "2017 Year-End Reserves" in this press release.

2017 F&D Costs, FD&A Costs and Recycle Ratios

-- The following table sets forth Birchcliff's 2017 F&D and FD&A costs for proved developed producing, proved and proved plus probable reserves:

Excluding FDC ($/boe)                2017
F&D - Proved Developed Producing  $6.29
F&D - Proved                      $2.53
F&D - Proved Plus Probable        $2.54
FD&A - Proved Developed Producing $4.79
FD&A - Proved                     $1.95
FD&A - Proved Plus Probable       $2.35
Including FDC ($/boe)
F&D - Proved                      $8.14
F&D - Proved Plus Probable        $7.27
FD&A - Proved                     $7.16
FD&A- Proved Plus Probable        $5.37

-- The following table sets forth Birchcliff's 2017 operating netback and funds flow netback recycle ratios for proved developed producing, proved and proved plus probable reserves:

                                  Operating Netback Funds Flow Netback
                                  Recycle Ratio     Recycle Ratio
Excluding FDC
F&D - Proved Developed Producing  2.2               2.0
FD&A - Proved Developed Producing 2.9               2.7
F&D - Proved                      5.5               5.1
FD&A - Proved                     7.2               6.6
F&D - Proved Plus Probable        5.5               5.0
FD&A - Proved Plus Probable       6.0               5.5
Including FDC
F&D - Proved                      1.7               1.6
FD&A - Proved                     2.0               1.8
F&D - Proved Plus Probable        1.9               1.8
FD&A - Proved Plus Probable       2.6               2.4

This press release contains forward-looking information within the meaning of applicable securities laws. Such forward-looking information is based upon certain expectations and assumptions and actual results may differ materially from those expressed or implied by such forward-looking information. For further information regarding the forward-looking information contained herein, please see "Advisories - Forward-Looking Information". In addition, this press release contains references to "funds flow from operations", "funds flow per common share", "free funds flow from operations", "operating netback", "estimated operating netback", "funds flow netback", "operating margin", "total cash costs", "adjusted working capital deficit" and "total debt", which do not have standardized meanings prescribed by GAAP. For further information regarding these non-GAAP measures, including reconciliations to the most directly comparable GAAP measure where applicable, please see "Non-GAAP Measures". All financial and operating information for the fourth quarter and year ended December 31, 2017 is unaudited. See "Advisories - Unaudited Information".

2017 UNAUDITED FINANCIAL AND OPERATIONAL HIGHLIGHTS

                                                    Three months ended  Twelve months ended
                                                    December 31,        December 31,
                                                    2017      2016      2017      2016
OPERATING
Average daily production
Light oil - (bbls)                                  5,283     4,656     6,004     3,729
Natural gas - (Mcf)                                 385,280   289,587   320,927   247,373
NGLs - (bbls)                                       10,607    7,830     8,471     4,279
Total - boe                                         80,103    60,750    67,963    49,236
Average sales price ($ CDN)
Light oil - (per bbl)                               68.58     60.75     61.42     51.40
Natural gas - (per Mcf)                             2.64      3.31      2.72      2.41
NGLs - (per bbl)                                    40.08     29.50     33.39     31.23
Total - boe                                         22.54     24.23     22.44     18.73
NETBACK AND COST ($/boe)
Petroleum and natural gas revenue                   22.55     24.24     22.45     18.73
Royalty expense                                     (1.26   ) (1.82   ) (1.16   ) (1.16     )
Operating expense                                   (3.86   ) (4.54   ) (4.45   ) (4.18     )
Transportation and marketing expense                (3.52   ) (2.42   ) (2.87   ) (2.38     )
Operating netback                                   13.91     15.46     13.97     11.01
General & administrative expense, net               (1.28   ) (1.19   ) (1.07   ) (1.19     )
Interest expense                                    (0.97   ) (1.40   ) (1.14   ) (1.68     )
Realized gain (loss) on financial instruments       1.46      (0.02   ) 1.03      0.04
Interest Income                                     0.04      -         0.02      -
Funds flow netback                                  13.16     12.85     12.81     8.18
Stock-based compensation expense, net               (0.13   ) (0.12   ) (0.16   ) (0.14     )
Depletion and depreciation expense                  (7.86   ) (7.73   ) (7.48   ) (8.29     )
Accretion expense                                   (0.08   ) (0.15   ) (0.12   ) (0.14     )
Amortization of deferred financing fees             (0.05   ) (0.06   ) (0.06   ) (0.06     )
Gain (loss) on sale of assets                       1.86      0.17      (7.50   ) (0.53     )
Unrealized gain (loss) on financial instruments     (1.86   ) (1.72   ) 0.22      (0.52     )
Dividends on Series C preferred shares              (0.12   ) (0.16   ) (0.14   ) (0.19     )
Income tax recovery (expense)                       (1.42   ) (0.92   ) 0.54      0.34
Net income (loss)                                   3.50      2.16      (1.89   ) (1.35     )
Dividends on Series A preferred shares              (0.14   ) (0.18   ) (0.17   ) (0.22     )
Net income (loss) to common shareholders            3.36      1.98      (2.06   ) (1.57     )
FINANCIAL
Petroleum and natural gas revenue ($000s)           166,149   135,457   556,942   337,586
Funds flow from operations ($000s)                  97,008    71,806    317,680   147,443
Per common share - basic ($)                        0.36      0.27      1.20      0.74
Per common share - diluted ($)                      0.36      0.27      1.19      0.73
Net income (loss) ($000s)                           25,820    12,085    (46,980 ) (24,335   )
Net income (loss) to common shareholders ($000s)    24,773    11,085    (51,027 ) (28,335   )
Per common share - basic ($)                        0.09      0.04      (0.19   ) (0.14     )
Per common share - diluted ($)                      0.09      0.04      (0.19   ) (0.14     )
Common shares outstanding (000s)
End of period - basic                               265,797   264,042   265,797   264,042
End of period - diluted                             282,895   279,881   282,895   279,881
Weighted average common shares for period - basic   265,792   263,396   265,182   199,581
Weighted average common shares for period - diluted 267,619   268,974   267,873   202,686
Dividends on common shares ($000s)                  6,644     -         26,522    -
Dividends on Series A preferred shares ($000s)      1,047     1,000     4,047     4,000
Dividends on Series C preferred shares ($000s)      875       875       3,500     3,500
Capital expenditures, net ($000s)                   18,669    62,482    276,125   762,030
Revolving term credit facilities ($000s)            587,126   572,517   587,126   572,517
Adjusted working capital deficit ($000s)            11,067    27,495    11,067    27,495
Total debt ($000s)                                  598,193   600,012   598,193   600,012

2017 UNAUDITED FOURTH QUARTER FINANCIAL AND OPERATIONAL RESULTS

2017 Q4 Production

We achieved record quarterly average production of 80,103 boe/d, which is slightly above the high end of our previous guidance range of 79,000 to 80,000 boe/d. This quarterly average production represents a 23% increase from 65,276 boe/d in the third quarter of 2017 and a 32% increase from 60,750 boe/d in the fourth quarter of 2016. The increase in production is primarily attributable to the success of our 2017 capital program which resulted in incremental production from new horizontal oil wells being brought on production in Gordondale, as well as from new horizontal natural gas wells being brought on production in Pouce Coupe in connection with the start-up of Phase V of the Pouce Coupe Gas Plant.

Production consisted of approximately 80% natural gas, 7% light oil and 13% NGLs in the fourth quarter of 2017, which is in line with our previous guidance of 80% natural gas and 20% oil and NGLs. This compares to 79% natural gas, 8% light oil and 13% NGLs in the fourth quarter of 2016.

2017 Q4 Funds Flow From Operations and Net Income

Funds flow from operations was $97.0 million, or $0.36 per basic common share, a 51% increase and a 50% increase, respectively, from $64.4 million and $0.24 per basic common share in the third quarter of 2017, and a 35% increase and a 33% increase, respectively, from $71.8 million and $0.27 per basic common share in the fourth quarter of 2016. The increase in funds flow from operations from the third quarter of 2017 was largely due to a higher average corporate realized commodity sales price and higher corporate production, partially offset by higher general and administrative expense and increased royalties, operating and transportation and marketing expenses resulting from higher production in the fourth quarter of 2017. The increase in funds flow from operations from the fourth quarter of 2016 was largely due to higher corporate production, a realized cash gain on financial commodity price risk management contracts and lower royalty expense, partially offset by a lower average corporate realized commodity sales price, higher general and administrative expense and increased operating and transportation and marketing expenses primarily resulting from higher production in the fourth quarter of 2017.

We had net income of $25.8 million, as compared to the net loss of $120.7 million in the third quarter of 2017 and net income of $12.1 million in the fourth quarter of 2016. We recorded net income to common shareholders of $24.8 million ($0.09 per basic common share), as compared to the net loss to common shareholders of $121.7 million ($0.46 per basic common share) in the third quarter of 2017 and net income to common shareholders of $11.1 million ($0.04 per basic common share) in the fourth quarter of 2016. The change from the net loss in the third quarter of 2017 to net income in the fourth quarter of 2017 is primarily attributable to the after-tax book loss of $132.3 million on the sale of our Worsley Charlie Lake Light Oil Pool which was recorded in the third quarter of 2017 (see "2017 Unaudited Year-End Financial Operational Results - Acquisitions and Dispositions"). The increase in net income as compared to the fourth quarter of 2016 is primarily due to an increase in funds flow from operations, an after-tax gain of $10.0 million on the sale of our Progress Charlie Lake assets (see "- Acquisitions and Dispositions") and partially offset by higher depletion expense resulting from higher production in the fourth quarter of 2017.

2017 Q4 Operating Costs, Transportation and Marketing Expense and General and Administrative Expense

Operating costs were $3.86/boe, which is in line with our previous guidance of less than $4.00/boe. This represents a 10% decrease from $4.27/boe in the third quarter of 2017 and a 15% decrease from $4.54/boe in the fourth quarter of 2016. The decrease in operating costs per boe from the comparative quarters was largely due to an increased percentage of incremental production additions brought on production to Phase V of the Pouce Coupe Gas Plant, the sale of our higher-cost Worsley Charlie Lake Light Oil Pool and various cost reductions and infrastructure optimization initiatives implemented by Birchcliff throughout 2017.

Transportation and marketing expense was $3.52/boe, a 33% increase from $2.65/boe in the third quarter of 2017 and a 45% increase from $2.42/boe in the fourth quarter of 2016. The increase from the comparative quarters was primarily due to firm service transportation tolls for natural gas transported to Dawn between November 1, 2017 and December 31, 2017. See "Update on Hedging and Market Diversification" for further information.

General and administrative expense was $1.28/boe, a 56% increase from $0.82/boe in the third quarter of 2017 and an 8% increase from $1.19/boe in the fourth quarter of 2016. The increase from the comparative quarters was primarily due to the additional staff needed to manage the increases in production, reserves and land base associated with our assets in Pouce Coupe and Gordondale and higher general business expenditures.

2017 Q4 Capital Expenditures

Total F&D capital in the fourth quarter of 2017 (which excludes acquisitions, dispositions and administrative assets) was $49.3 million. Of these capital expenditures, approximately $35.5 million was spent on drilling and completions and $9.7 million on facilities and infrastructure.

2017 Q4 Drilling

During the fourth quarter of 2017, we drilled 2 (2.0 net) wells, both of which were Montney/Doig horizontal natural gas wells in the Pouce Coupe area. For further information regarding our drilling activities during 2017, please see "Operations Overview and Update" in this press release.

2017 UNAUDITED YEAR-END FINANCIAL AND OPERATIONAL RESULTS

2017 Production

We achieved record annual average production in 2017 of 67,963 boe/d, which is on the high end of our previous guidance range of 67,000 to 68,000 boe/d. This annual average production represents a 38% increase from our 2016 annual average production of 49,236 boe/d. The increase in production is primarily attributable to the success of our 2017 capital program which resulted in incremental production from new horizontal oil wells being brought on production in Gordondale, as well as from new horizontal natural gas wells being brought on production in Pouce Coupe in connection with the start-up of Phase V of the Pouce Coupe Gas Plant.

Production consisted of approximately 79% natural gas, 9% light oil and 12% NGLs in 2017, which is in line with our previous guidance of 79% natural gas and 21% oil/NGLs. This compares to 83% natural gas, 8% light oil and 9% NGLs in 2016.

2017 Market Diversification and Commodity Prices

During 2017, we entered into agreements with TCPL for the firm service transportation of an aggregate of 175,000 GJ/d (approximately 152 MMcf/d) of natural gas on TCPL's Canadian Mainline for a 10-year term, whereby natural gas is transported to the Dawn trading hub located in Southern Ontario. The first tranche of this service (120,000 GJ/d) became available to Birchcliff on November 1, 2017, with additional tranches becoming available later in 2018 and in 2019. In addition, we entered into additional arrangements during 2017 with third party marketers to sell and deliver natural gas into the Alliance pipeline system. See "Update on Hedging and Market Diversification".

During 2017, the average benchmark price for WTI oil was US$50.95/bbl, up 18% from US$43.32/bbl during 2016, and the average benchmark price for natural gas sold at AECO stayed flat at $2.16/MMBtu as compared to 2016. The average benchmark price for natural gas sold at Dawn from November 1, 2017 to December 31, 2017 was $3.82/MMBtu. Our average corporate realized commodity sales price during 2017 was $22.44/boe, a 20% increase from $18.73/boe during 2016. At December 31, 2017, approximately 29% of our natural gas production was being sold at the Dawn price, 13% was being sold into the Alliance pipeline system and 58% of was being sold at AECO. After taking into account our oil and NGLs production, approximately 47% of our total corporate production at December 31, 2017 was exposed to AECO pricing, with the remaining 53% of corporate production not exposed to AECO pricing.

2017 Funds Flow From Operations and Net Loss

Funds flow from operations in 2017 was $317.7 million, or $1.20 per basic common share, a 115% increase and a 62% increase, respectively, from $147.4 million and $0.74 per basic common share in 2016. The increase from 2016 was largely due to a higher average corporate realized commodity sales price, higher corporate production, a realized cash gain on financial commodity price risk management contracts and lower interest costs, partially offset by higher royalties, operating and transportation and marketing expenses primarily resulting from higher production during 2017.

We had a net loss of $47.0 million in 2017, as compared to the net loss of $24.3 million in 2016. We recorded a net loss to common shareholders of $51.0 million ($0.19 per basic common share) in 2017, as compared to the net loss to common shareholders of $28.3 million ($0.14 per basic common share) in 2016. The increases in the net losses from 2016 were mainly attributable to an after-tax book loss of $132.3 million resulting from the sale of our Worsley Charlie Lake Light Oil Pool, higher depletion and stock-based compensation costs and an unrealized mark-to-market loss on financial commodity price risk management contracts, partially offset by higher funds flow from operations in 2017.

2017 Operating Costs, Transportation and Marketing Expense and General and Administrative Expense

Operating costs in 2017 were $4.45/boe, a 6% increase from $4.18/boe in 2016. The increase in operating costs per boe from 2016 was largely due to higher operating, processing and service costs associated with our assets in Gordondale (the "Gordondale Assets") which were initially acquired on July 28, 2016, partially offset by incremental production additions brought on production to Phase V of the Pouce Coupe Gas Plant, the sale of our higher-cost Worsley Charlie Lake Light Oil Pool and various cost reductions and infrastructure optimization initiatives implemented by Birchcliff throughout 2017. Our Gordondale Assets have a higher cost structure primarily resulting from increased oil and NGLs production weighting and additional fees incurred to process natural gas from the Gordondale area at AltaGas' owned and operated natural gas processing facility located in Gordondale.

Transportation and marketing expense was $2.87/boe, a 21% increase from $2.38/boe in 2016. The increase was primarily due to firm service transportation tolls for natural gas transported from Empress to Dawn between November 1, 2017 and December 31, 2017. See "Update on Hedging and Market Diversification" for further information.

General and administrative expense in 2017 was $1.07/boe, a 10% decrease from $1.19/boe in 2016. The decrease on a per unit basis is primarily due to an increase in corporate production, partially offset by additional staff needed to manage the increases in production, reserves and land base associated with our assets and higher general business expenditures.

2017 Interest Expense

Interest expense was $1.14/boe, a 32% decrease from $1.68/boe in 2016. The decrease is primarily due to a combination of higher production and a lower average outstanding bank debt drawn in 2017 as compared to 2016.

2017 Pouce Coupe Gas Plant Netbacks

Approximately 60% of our total corporate natural gas production and 49% of our total corporate production was processed at the Pouce Coupe Gas Plant during 2017 as compared to 68% and 59%, respectively, during 2016. These decreases are primarily due to the increased weighting of liquids-rich production from our Gordondale Assets as a percentage of corporate production. The average plant and field operating cost for production processed through the Pouce Coupe Gas Plant for 2017 was $0.34/Mcfe ($2.07/boe) and the estimated operating netback at the Pouce Coupe Gas Plant was $2.19/Mcfe ($13.12/boe), resulting in an operating margin of 72%.

The following table details our average daily production and estimated operating netback for wells producing to the Pouce Coupe Gas Plant:

                                             Twelve months ended          Twelve months ended          Twelve months ended
                                             December 31,                 December 31,                 December 31,
                                             2017                         2016                         2015
Average daily production, net to Birchcliff:
Natural gas (Mcf)                                               193,417                      168,444                      163,641
Oil & NGLs (bbls)                                               1,316                        960                          1,287
Total boe                                                       33,552                       29,034                       28,560
AECO - C daily ($/MMBtu)                     $2.16                        $2.16                        $2.69
Operating netback and cost:                      $/Mcfe         $/boe         $/Mcfe         $/boe         $/Mcfe         $/boe
Petroleum and natural gas revenue                3.04           18.24         2.54           15.21         3.17           19.03
Royalty expense                                  (0.07  )       (0.44   )     (0.06  )       (0.38   )     (0.11  )       (0.63   )
Operating expense                                (0.34  )       (2.07   )     (0.25  )       (1.49   )     (0.31  )       (1.90   )
Transportation and marketing expense             (0.44  )       (2.61   )     (0.33  )       (1.96   )     (0.31  )       (1.88   )
Estimated operating netback                  $2.19          $13.12        $1.90          $11.38        $2.44          $14.62
Operating margin                                 72     %       72      %     75     %       75      %     77     %       77      %

2017 Funds Flow Netback and Total Cash Costs

During 2017, we had funds flow netback of $12.81/boe, a 57% increase from $8.18/boe in 2016. The increase from 2016 was largely due to a higher average corporate realized commodity sales price in 2017 and an increase in per unit realized cash gain on financial commodity price risk management contracts during 2017, partially offset by higher per unit operating and transportation and marketing costs due to higher production.

During 2017, we had total cash costs of $10.69/boe, as compared to $10.59/boe in 2016. The increase was primarily due to the acquisition of the higher-cost liquids-rich Gordondale Assets which occurred partway through 2016, partially offset by the disposition of the higher-cost Worsley Charlie Lake Light Oil Pool which closed in the third quarter of 2017.

2017 Capital Activities and Expenditures

In 2017, we had total capital expenditures of $416.8 million and net capital expenditures of $276.1 million, which is 3% above and 5% above, respectively, our previous guidance of $404 million total capital expenditures and $262 million net capital expenditures. Our capital expenditure activities during 2017 were focused on our Montney/Doig Resource Play in our Gordondale and Pouce Coupe areas. Our total F&D capital during 2017 (which excludes acquisitions, dispositions and administrative assets) was $415.0 million, which consisted of $269.1 million on drilling and completions, $132.4 million on facilities and infrastructure, $3.1 million on land and seismic and $10.4 million on other capital expenditures. Of the $132.4 million spent on facilities and infrastructure: (i) approximately $29.7 million was spent on the Phase V expansion of the Pouce Coupe Gas Plant (which came on-stream in the third quarter of 2017) primarily on field construction; and (ii) approximately $26.7 million was spent on the Phase VI expansion of the Pouce Coupe Gas Plant (expected to come on-stream in October 2018) primarily on engineering, procurement and fabrication.

Drilling and Completions

We drilled a total of 54 (54.0 net) wells during 2017. Of the 54 (54.0 net) wells drilled during 2017, 16 (16.0 net) were Montney horizontal oil and natural gas wells drilled in the Gordondale area, 37 (37.0 net) were Montney/Doig horizontal natural gas wells drilled in the Pouce Coupe area and 1 (1.0 net) was a Montney/Doig vertical science and technology well drilled in the Pouce Coupe area. Of these 54 wells, a total of 51 (51.0 net) wells were brought on production during 2017. Of the remaining 3 wells: (i) 1 Montney D1 horizontal natural gas well was drilled in December 2017 and is expected to be brought on production in the second quarter of 2018; (ii) 1 Montney/Doig well drilled in the Pouce Coupe area encountered operational challenges during the completion operation and is now expected to be brought on production in the third quarter of 2018; and (iii) the Montney/Doig vertical science and technology well is not intended to be a producing well. In addition, our 2017 capital program also included the capital associated with the completion, equipping and tie-in of 10 wells drilled in 2016, all of which were brought on production in the first quarter of 2017. Accordingly, a total of 61 (61.0 net) wells were brought on production during 2017, down from our previous guidance of 62 (62.0 net) wells.

All wells drilled in 2017 were drilled on multi-well pads, which allows us to reduce our per well costs and our environmental footprint. In addition, we actively employ the evolving technology utilized by the industry regarding horizontal well drilling and the related multi-stage fracture stimulation technology. For further information regarding our drilling activities during 2017, please see "Operations Overview and Update" in this press release.

Acquisitions and Dispositions

During 2017, we completed various asset sales for total proceeds of approximately $148 million (before adjustments) ($138 million in cash; $10 million in securities), representing forecast 2017 average production of approximately 3,600 boe/d. The proceeds from these asset sales were initially used to reduce indebtedness under our credit facilities, which was subsequently redrawn as needed to fund our capital expenditure program and for general corporate purposes. In addition, we also completed various minor acquisitions for total consideration of approximately $1.0 million. See also "2017 Land".

During 2017, we disposed of the vast majority of our assets on our Charlie Lake Light Oil Resource Play pursuant to various transactions so that we could focus on our Montney/Doig Resource Play. In particular, we completed two significant dispositions on August 31, 2017 and October 2, 2017. On August 31, 2017, we completed the sale of our Worsley Charlie Lake Light Oil Pool for total consideration of approximately $100 million (before adjustments) ($90 million in cash; $10 million in securities of affiliates of the purchaser) (the "Worsley Disposition"). On October 2, 2017, we completed the disposition of our Progress Charlie Lake assets for total cash consideration of $31.7 million (before adjustments) (the "Progress Disposition").

2017 Credit Facilities and Debt

Our extendible revolving credit facilities have an aggregate principal amount of $950 million (the "Credit Facilities") and are comprised of an extendible revolving syndicated term credit facility of $900 million (the "Syndicated Credit Facility") and an extendible revolving working capital facility of $50 million (the "Working Capital Facility"). The maturity date of each of the Syndicated Credit Facility and the Working Capital Facility is May 11, 2020. We may each year, at our option, request an extension to the maturity date of the Syndicated Credit Facility and the Working Capital Facility, or either of them, for an additional period of up to three years from May 11 of the year in which the extension request is made. The Credit Facilities are subject to semi-annual reviews of the borrowing base limit by our syndicate of lenders, which reviews are typically completed in May and November of each year. The Credit Facilities do not contain any financial maintenance covenants.

At December 31, 2017, our long-term bank debt was $587.1 million (December 31, 2016: $572.5 million) from available credit facilities of $950 million (December 31, 2016: $950 million), leaving $343 million of unutilized credit capacity after adjusting for outstanding letters of credit and unamortized interest and fees. Total debt at December 31, 2017 was $598.2 million as compared to $600.0 million at December 31, 2016.

2017 Risk Management

During 2017, we realized a cash gain on financial commodity price risk management contracts of $25.8 million compared to $0.8 million in 2016. We recorded a $5.4 million unrealized gain on financial commodity price risk management contracts in 2017 as compared to a $9.4 million unrealized loss in 2016.

As at December 31, 2017, we had outstanding financial derivative contracts for 4,500 bbls/d of crude oil production from January 1, 2018 to December 31, 2018 at an average WTI price of CDN$71.87. See "Update on Hedging and Market Diversification".

2017 Land

Our land base primarily consists of large contiguous blocks of high working interest acreage located near facilities owned and/or operated by Birchcliff or near third party infrastructure. We were very successful with our strategy of focusing on our Montney/Doig Resource Play and disposing of non-core assets during 2017. Our land activities during 2017 included: (i) the acquisition of 51.5 (54.0 net) sections of Crown and third party lands; and (ii) the disposition of 346.3 (309.8 net) sections, including 191.8 (185.3 net) sections of land pursuant to the Worsley Disposition and 45.5 (35.7 net) sections of land pursuant to the Progress Disposition and including 80.8 (73.8 net) sections of land that expired in 2017. Our undeveloped land base at December 31, 2017 was 262,318.4 (238,705.5 net) acres, or 409.9 (373.0 net) sections, with a 91% average working interest.

2018 CAPITAL PROGRAM

Our board of directors has approved a capital expenditure budget of $255 million. Approximately $149.9 million has been allocated for drilling and development and $66.9 million for facilities and infrastructure. We expect that our 2018 capital expenditures will be less than our funds flow from operations during 2018, based on the assumptions contained herein. Details on the expected capital spending allocation are set forth in the table below:

                                              Gross Wells Net Wells Capital
                                                                    (MM)
Drilling and Development
Pouce Coupe - Montney D1 Horizontal Gas Wells 12          12.0      $66.2
Pouce Coupe -Montney D2 Horizontal Gas Wells  1           1.0       $4.9
Pouce Coupe - Montney C Horizontal Gas Wells  1           1.0       $5.1
Gordondale - Montney D2 Horizontal Oil Wells  8           8.0       $42.2
Gordondale - Montney D1 Horizontal Oil Wells  5           5.0       $26.0
2017 Carry Forward Capital                    -           -         $5.5
Total Drilling and Development                27          27.0      $149.9
Facilities and Infrastructure                                       $66.9
Sustaining and Optimization                                         $17.1
Land and Seismic                                                    $4.6
Other                                                               $16.5
TOTAL CAPITAL                                                       $255.0

Highlights of the 2018 Capital Program

Our 2018 Capital Program reflects our long-term plan to continue the exploration and development of our low-cost natural gas, crude oil and liquids-rich assets on the Montney/Doig Resource Play. The program will direct capital investment to those projects with the most favourable rates of return, including a combination of liquids-rich natural gas, crude oil and natural gas development opportunities and strategic infrastructure for future growth. In particular, the 2018 Capital Program will focus on the drilling of crude oil wells in Gordondale and a combination of liquids-rich and low-cost natural gas wells in Pouce Coupe to take advantage of the recently improved prices for oil and NGLs.

The objectives of the 2018 Capital Program are to maintain a prudent pace of development and focus on rates of return, while also maintaining balance sheet strength and the payment of a sustainable quarterly dividend to our shareholders. The 2018 Capital Program has been designed with financial and operational flexibility with the potential to accelerate or decelerate capital expenditures throughout the year, depending on commodity prices and economic conditions.

Other highlights of the 2018 Capital Program include the following:

-- The program contemplates the drilling, completing, equipping and bringing on production of a total of 27 (27.0 net) wells during 2018 and targets an annual average production rate for 2018 in the range of 76,000 to 78,000 boe/d.

-- The 2018 Capital Program is expected to be fully funded from our 2018 funds flow from operations.

-- A continued focus on oil and NGLs production and field delineation of the Montney D1 and D2 intervals in Gordondale and further exploration and delineation of liquids-rich trends in the Montney D1, D2 and C intervals in Pouce Coupe.

-- A continued commitment to science and technology to drive operational excellence and further our learnings on field development planning.

-- Completion of the Phase VI expansion of the Pouce Coupe Gas Plant and other strategic infrastructure projects to provide for future growth. Approximately $25.7 million will be allocated towards the completion of Phase VI which is expected to come on-stream in October 2018. In addition, Phases V and VI of the plant are being re-configured to allow for shallow-cut capability to remove C3+ liquids from the natural gas stream.

-- Approximately 35% of the 2018 Capital Program is directed towards our Gordondale area and approximately 56% is directed towards our Pouce Coupe area.

Gordondale Area

We plan to invest approximately $90 million in Gordondale during 2018. Key focus areas for Gordondale in 2018 will be the drilling of crude oil wells, the delineation of the Montney D1 and D2 intervals and continuing to improve on our well results and completion techniques through completion system design and fracturing techniques.

Drilling and Development

We plan to drill 13 (13.0 net) horizontal wells in the Gordondale area, consisting of 8 (8.0 net) Montney D2 horizontal oil wells and 5 (5.0 net) Montney D1 horizontal oil wells, all of which will be drilled on multi-well pads.

Pouce Coupe Area

We plan to invest approximately $142.3 million in Pouce Coupe during 2018. Key focus areas for Pouce Coupe in 2018 will be the drilling of liquids-rich natural gas wells to maximize the recovery of condensate and other liquids, the execution of our multi-well science and technology pad, the exploration of the Montney D2 and C intervals, the completion of the 80 MMcf/d Phase VI expansion of the Pouce Coupe Gas Plant, the addition of shallow-cut capability for Phases V and VI and continuing to improve on our well results and completion techniques.

Drilling and Development

We plan to drill 14 (14.0 net) horizontal wells in our Pouce Coupe area, consisting of 12 (12.0 net) Montney D1 horizontal liquids-rich and low-cost natural gas wells, 1 (1.0 net) Montney D2 horizontal liquids-rich natural gas well and 1 (1.0 net) Montney C horizontal liquids-rich natural gas well, all of which will be drilled on multi-well pads.

Facilities and Infrastructure

We plan to invest $66.9 million in facilities and other strategic infrastructure during 2018, of which approximately $25.7 million will be directed towards the Phase VI expansion of the Pouce Coupe Gas Plant as discussed in further detail below. Once this investment has been made, we expect that our facilities and infrastructure expenditures going forward will decrease significantly until a decision is made to build additional phases of the Pouce Coupe Gas Plant.

Pouce Coupe Gas Plant - Phase VI Expansion and Shallow-Cut Capability

During 2018, we expect to complete the 80 MMcf/d Phase VI expansion of the Pouce Coupe Gas Plant which will increase the processing capacity from 260 MMcf/d to 340 MMcf/d. Field construction commenced in January 2018 and we currently anticipate that Phase VI will be brought on-stream in October 2018. Phase VI will allow for future growth and help us to reduce our operating costs on a per boe basis.

The total estimated cost for the Phase VI expansion is approximately $52.4 million, of which $26.7 million has already been incurred. We estimate that an additional $25.7 million will be required during 2018 to complete construction as the fabrication of the components has been completed and much of the infrastructure that will be utilized by Phase VI was built in connection with Phase V which came on-stream in the third quarter of 2017. In effect, Phase VI is an add-on to Phase V for a relatively low expenditure as the cost of the additional 80 MMcf/d is only $0.655 million per MMcf/d of capacity.

In addition, we are currently in the process of re-configuring Phases V and VI to provide for shallow-cut capability when Phase VI comes on-stream. This shallow-cut capability will allow us to remove from the natural gas stream C3+ liquids. As both phases will include shallow-cut capability, the combined 160 MMcf/d facility is expected to provide approximately 600 bbls/d of C3+ based on the current natural gas stream going through the Pouce Coupe Gas Plant. As we increase our focus on liquids-rich drilling opportunities, this will provide for the efficient processing of liquids-rich natural gas. This addition of shallow-cut capability is only expected to cost an additional $3.0 million which is included in the estimated cost for Phase VI.

Given our 2018 drilling program and expected 2018 production levels, we will have excess capacity at the Pouce Coupe Gas Plant when Phase VI comes on-stream. In order to partially fill Phase VI, we currently plan on diverting some of our natural gas that is currently being processed by third-party processors to Phase VI, which will also help us to reduce our operating costs. We believe that we will be able to fill this excess capacity over time as commodity prices improve and as we target liquids-rich natural gas wells.

Funding of the 2018 Capital Program

The 2018 Capital Program is expected to be fully funded from our 2018 funds flow from operations, based on the assumptions contained herein (see "Outlook and Guidance"). We are focused on maintaining balance sheet strength and we may choose to use any funds flow from operations in excess of our capital expenditures and dividend payments to pay down indebtedness under our Credit Facilities.

2018 Production Guidance

Based on the 2018 Capital Program, we expect our annual average production in 2018 to be in the range of 76,000 to 78,000 boe/d, comprised of approximately 80% natural gas and 20% oil and NGLs. This represents an increase of 12% to 15% from our 2017 annual average production. We believe that our annual average production target for 2018 represents a prudent level of growth over 2017 given current economic conditions. See "Outlook and Guidance".

OUTLOOK AND GUIDANCE

The following table sets forth our guidance and commodity price assumptions for 2018, as well as our 2017 actual unaudited results for comparative purposes:

                                                        2018 Guidance and  2017 Annual
                                                        Assumptions        Actuals
Production
Annual Average Production (boe/d)                       76,000 - 78,000    67,963
% Natural Gas                                           80%                79%
% Oil and NGLs                                          20%                21%
Average Expenses ($/boe)
Royalty                                                 1.20 - 1.40        1.16
Operating                                               3.75 - 4.00        4.45
Transportation and Marketing                            3.80 - 4.10        2.87
Capital Expenditures (MM$)
Estimated Total Capital                                 255.0              416.8
Estimated Drilling and Development Capital              149.9              269.1
Estimated Facilities and Infrastructure Capital         66.9               132.4
Natural Gas Market Exposure
AECO Production as a % of Total Natural Gas Production  66%                58%
Dawn Production as a % of Total Natural Gas Production  30%                29%
Commodity Prices
Average WTI Oil Price (US$/bbl)                         61.00              50.95
Average AECO Price ($/MMBtu)                            1.58               2.16
Average Dawn Price ($/MMBtu)                            3.48               3.82
Average Wellhead Natural Gas Price ($/Mcf)              2.32               2.72

The average wellhead natural gas price for 2018 of $2.32/Mcf is based upon an annual average AECO price of $1.58/MMBtu during 2018 ($2.11/MMBtu during the months of January, February, March, November and December and $1.20/MMBtu during the remaining months of 2018) and an annual Dawn price of $3.48/MMBtu during 2018 ($4.22/MMBtu during the months of January and February and $3.33/MMBtu during the remaining months of 2018).

We are currently reviewing our short and long-term growth opportunities and developing a new five year plan to take into account current economic conditions, the 2018 Capital Program and other recent developments. We expect to release our updated five year plan later in 2018.

UPDATE ON HEDGING AND MARKET DIVERSIFICATION

Hedging

Our current hedging strategy for 2018 is to hedge up to 50% of our 2018 forecast annual average production using a combination of financial derivatives and physical delivery sales contracts, depending on our outlook for commodity prices and the availability of hedges on terms acceptable to Birchcliff. At the date hereof, approximately 6% of our 2018 forecast annual average production is hedged.

With respect to crude oil, we have entered into financial derivative contracts for 4,500 bbls/d of crude oil at an average WTI price of CDN$71.87/bbl for the period from January 1, 2018 to December 31, 2018. This represents approximately 31% of our 2018 forecast annual average oil and NGLs production and approximately 6% of our total 2018 forecast annual average production.

With respect to natural gas, we have not entered into any natural gas hedges given the current weak AECO natural gas markets. Given the current strip prices from which to hedge at today, we believe that the downside to AECO has already been priced into the AECO market forward strip and potentially even oversold. Rather than hedge at these current prices, we are continually seeking to diversify away from AECO, but we are doing so prudently, so that we remain profitable in the long-term.

Market Diversification

During 2018, we expect that approximately 34% of our 2018 forecast annual average natural gas production will be sold at prices that are not based on AECO, with 30% being sold at the Dawn daily index price and 4% being marketed via the Alliance pipeline system, as discussed in further detail below. We continue to actively look for further profitable market diversification opportunities. Our market diversification initiatives have helped to reduce our exposure to volatility in commodity prices, including AECO prices which have been extremely volatile in recent months.

During 2017, we entered into agreements with TCPL for the firm service transportation of an aggregate of 175,000 GJ/d (approximately 152 MMcf/d) of natural gas on TCPL's Canadian Mainline for a 10-year term, whereby natural gas is transported from the Empress receipt point in Alberta to the Dawn trading hub located in Southern Ontario. The toll for the Empress to Dawn portion of the service is $0.77/GJ plus fuel. The first tranche of this service (120,000 GJ/d) became available to Birchcliff on November 1, 2017, with additional tranches becoming available on November 1, 2018 (35,000 GJ/d) and November 1, 2019 (20,000 GJ/d). In the fourth quarter of 2017, we entered into agreements with three natural gas marketers whereby we assigned our TCPL service from Empress to Dawn for a one-year term ending November 1, 2018. During this term, the marketers deliver our natural gas to Dawn and pay Birchcliff the Dawn daily index price, less the Empress to Dawn toll and fuel costs. Under these agreements, each marketer has the option to divert the natural gas to a secondary delivery point to optimize the price received for the natural gas. In such instance, Birchcliff will receive between 60% and 80% of the optimized value obtained for the natural gas.

We have sales agreements with a third party marketer to sell and deliver into the Alliance pipeline system: (i) approximately 40 MMcf/d of natural gas under contracts which commenced November 1, 2017 and expire March 31, 2018, 10 MMcf/d of which is sold at Alliance's Trading Pool daily index price and 30 MMcf/d of which is sold at a Chicago index price; and (ii) approximately 5 MMcf/d of natural gas under contracts which commenced April 1, 2017 and expire October 31, 2020, which is sold at Alliance's Trading Pool daily index price.

OPERATIONS OVERVIEW AND UPDATE

Our operations are concentrated within our one core area, the Peace River Arch, which is centred northwest of Grande Prairie, Alberta, adjacent to the Alberta/British Columbia border. Our operations are focused on our established Montney/Doig Resource Play within the Peace River Arch, which is centred approximately 95 kilometres northwest of Grande Prairie, Alberta.

Our strategy is to continue to develop and expand this resource play, while maintaining low capital costs and operating costs. As part of this strategy, we intend to continue to explore and delineate the Montney/Doig Resource Play, both geographically and stratigraphically. The Montney/Doig Resource Play exists in two geological formations, the Montney and the Doig, and we have divided the geologic column in our areas of operation into six drilling intervals from the youngest (top) to the oldest (bottom): (i) the Basal Doig/Upper Montney; (ii) the Montney D4; (iii) the Montney D3; (iv) the Montney D2; (v) the Montney D1; and (vi) the Montney C. At December 31, 2017, we have successfully drilled and cased an aggregate of 348 (342.8 net) Montney/Doig horizontal wells (which includes 87 (81.8 net) wells that were acquired when we initially purchased our Gordondale Assets in 2016), consisting of 75 (73.5 net) wells in the Basal Doig/Upper Montney interval, 12 (12.0 net) wells in the Montney D4 interval, 13 (13.0 net) wells in the Montney D2 interval, 247 (243.3 net) wells in the Montney D1 interval and 1 (1.0 net) well in the Montney C interval.

Gordondale Area

We were active in the Gordondale area during 2017, drilling a total of 16 (16.0 net) Montney horizontal wells (9 Montney D2 oil, 5 Montney D1 oil and 2 Montney D1 liquids-rich natural gas wells), all of which were successful. All of these wells were brought on production in 2017. A large portion of the 2018 Capital Program is directed towards our Gordondale area, including the drilling of 13 (13.0 net) wells (see "2018 Capital Program").

Since we acquired our Gordondale Assets on July 28, 2016, we have drilled, completed and brought on production a total of 22 (22.0 net) wells in Gordondale, consisting of 12 (12.0 net) Montney D2 horizontal oil wells, 5 (5.0 net) Montney D1 horizontal oil wells and 5 (5.0 net) Montney D1 liquids-rich horizontal natural gas wells. When we first acquired our Gordondale Assets, the average production for such assets was approximately 22,000 boe/d at the date of the acquisition. The 22 horizontal wells that we have drilled and brought on production have replaced the natural production declines and have significantly increased the production on our Gordondale Assets (currently approximately 30,000 boe/d).

Update on Gordondale Montney D2 Horizontal Oil Wells

The 12 Montney D2 horizontal wells that we have drilled, completed and brought on production to-date have significantly delineated, de-risked and proven the commerciality of the Montney D2 play. When we initially acquired the Gordondale Assets, only one D2 well had been previously drilled on the play and there was only one offsetting D2 well.

In an effort to continuously improve our well performance and optimize our completions strategy, we have utilized three different completion systems on our Montney D2 wells drilled to-date, including open hole packers, cemented sleeves fracced with coil tubing and plug and perf technology. We continue to evaluate the production results and cost efficiencies of each system in order to optimize field development in Gordondale.

Our Montney D2 horizontal well results are meeting our expectations. In addition, we were able to reduce the average drilling, completion, equipping and tie-in costs of our Montney D2 horizontal wells to approximately $5.3 million during 2017, which is approximately $1 million less than what we had initially budgeted at the time of our acquisition of the Gordondale Assets. This has helped to significantly improve the economics of our Montney D2 wells.

Pouce Coupe Area

We were active in the Pouce Coupe area during 2017, drilling a total of 38 (38.0 net) wells and working towards the expansions of the Pouce Coupe Gas Plant. A large portion of the 2018 Capital Program is directed towards our Pouce Coupe area, including the drilling of 14 (14.0 net) wells and a continued investment in the Pouce Coupe Gas Plant (see "2018 Capital Program"). We are continuing to pursue condensate and other liquids in our Pouce Coupe area in several different Montney/Doig Intervals.

Drilling and Development and IP60 Montney D1 Well Results

During 2017, we drilled a total of 37 (37.0 net) Montney/Doig horizontal natural gas wells in Pouce Coupe (27 Montney D1, 7 Basal Doig/Upper Montney and 3 Montney D4 wells). Of these 37 wells, 36 were brought on production in 2017. In add

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