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Birchcliff Energy Ltd. Announces Unaudited 2019 Year-End and Fourth Quarter Results and 2019 Reserves Highlights


CALGARY – Birchcliff Energy Ltd. (“Birchcliff” or the “Corporation”) (TSX: BIR) is pleased to announce its unaudited 2019 year-end and fourth quarter financial and operational results and highlights from its independent reserves evaluations effective December 31, 2019.

Jeff Tonken, President and Chief Executive Officer of Birchcliff commented: “2019 was an excellent year for Birchcliff. We executed on our capital plan, achieving record annual average production of 77,977 boe/d and record low annual operating costs of $3.09 per/boe, both of which were in-line with or better than our 2019 guidance. Our annual average production in 2019 increased by 1% from 2018 and our operating costs decreased by 12% from 2018, reflecting the significant efforts by our team to continue to sustainably grow our production while bringing down per unit costs in order to remain one of industry’s lowest-cost producers. Birchcliff delivered $334.5 million of adjusted funds flow and $78.1 million of free funds flow in 2019, in spite of a challenging commodity price environment. In addition, we successfully added profitable production with positive recycle ratios in 2019.”

2019 Year-End Highlights

  • Generated $78.1 million of free funds flow in 2019, an increase from $13.3 million in 2018.
  • Achieved record annual average production of 77,977 boe/d, a 1% increase from 2018.
  • Liquids accounted for approximately 22% of Birchcliff’s total production in 2019 as compared to approximately 20% in 2018, with total liquids production increasing by 14% from 2018.
  • Delivered $334.5 million of adjusted funds flow, or $1.26 per basic common share, each a 7% increase from 2018.
  • Recorded a net loss to common shareholders of $59.6 million, or $0.22 per basic common share, as compared to net income to common shareholders of $98.0 million and $0.37 per basic common share in 2018.
  • Achieved record low annual operating expense of $3.09/boe, a 12% decrease from 2018.
  • Realized an operating netback of $13.07/boe, a 3% decrease from 2018.
  • Successfully executed the Corporation’s 2019 capital program, drilling a total of 30 (30.0 net) wells and bringing 33 (33.0 net) wells on production. F&D capital expenditures were $256.4 million in 2019.
  • Total capital expenditures were $300.2 million in 2019, which included the $39 million acquisition of 18 gross (15.1 net) contiguous sections of Montney land located between Birchcliff’s existing Pouce Coupe and Gordondale properties (the “Acquisition”). Birchcliff drilled 8 (8.0 net) wells and completed and brought on production 6 (6.0 net) successful condensate-rich natural gas wells on the acquired lands in 2019.
  • Paid $27.9 million in common share dividends in 2019.

Q4 2019 Highlights

  • Achieved quarterly average production of 77,962 boe/d, a 2% increase from Q4 2018.
  • Liquids accounted for approximately 22% of Birchcliff’s total production in Q4 2019 as compared to approximately 21% in Q4 2018, with total liquids production increasing by 9% from Q4 2018.
  • Delivered $80.9 million of adjusted funds flow, or $0.30 per basic common share, a 1% decrease and a 3% decrease, respectively, from Q4 2018.
  • Generated $24.1 million of free funds flow in Q4 2019, a decrease from $29.2 million in Q4 2018.
  • Recorded a net loss to common shareholders of $19.0 million, or $0.07 per basic common share, as compared to net income to common shareholders of $70.9 million and $0.27 per basic common share in Q4 2018.
  • Achieved operating expense of $3.06/boe, a 13% decrease from Q4 2018.
  • Realized an operating netback of $14.25/boe, a 6% increase from Q4 2018.
  • Total capital expenditures of $58.1 million. During the quarter, Birchcliff drilled 7 (7.0 net) wells.

2019 Reserves, F&D Costs and Recycle Ratio Highlights

  • The following table summarizes the estimates of Birchcliff’s gross reserves at December 31, 2019 and December 31, 2018, as estimated by Birchcliff’s independent qualified reserves evaluators using the forecast price and cost assumptions in effect as at the effective dates of the applicable reserves evaluations:
Reserves Category December 31, 2019
(Mboe)
December 31, 2018
(Mboe)
Change from
December 31, 2018
Proved Developed Producing 206,922.4 203,631.0 2%
Total Proved 709,061.2 689,674.1 3%
Probable 323,133.5 312,396.0 3%
Total Proved Plus Probable 1,032,194.7 1,002,070.1 3%
  • Birchcliff’s proved developed producing reserves increased by 29,649.3 Mboe during 2019, before including the effects of acquisitions and dispositions and adding back 2019 actual production of 28,461.6 Mboe.
  • Birchcliff’s proved developed producing reserves increased by 1.04 boe for each boe that was produced in 2019, before including the effects of acquisitions and dispositions and adding back 2019 actual production.
  • Birchcliff’s NGLs reserves, which include condensate, increased by 29% on a proved basis and 24% on a proved plus probable basis, as a result of its focus on extracting more high-value liquids in 2019.
  • Birchcliff’s total light and medium crude oil and NGLs weighting of its proved developed producing, proved and proved plus probable reserves increased to 20%, 16% and 17% of total boes, respectively.
  • The estimated net present value at December 31, 2019 (before taxes, discounted at 10%) was $1.9 billion for Birchcliff’s proved developed producing reserves (December 31, 2018: $2.3 billion), $4.1 billion for its proved reserves (December 31, 2018: $4.7 billion) and $5.3 billion for its proved plus probable reserves (December 31, 2018: $6.1 billion).
  • Reserves life index of 7.0 years on a proved developed producing basis, 24.0 years on a proved basis and 34.9 years on a proved plus probable basis, based on a forecast production rate of 81,000 boe/d (which represents the mid-point of Birchcliff’s annual average production guidance range for 2020).
  • During 2019, Birchcliff’s F&D capital expenditures were $256.4 million and its FD&A capital expenditures were $297.8 million. The following table sets forth Birchcliff’s F&D costs and FD&A costs per boe for 2019, 2018 and 2017, excluding and including FDC:
Excluding FDC ($/boe)(1) 2019 2018 2017 3-Year Average
  F&D – Proved Developed Producing $8.65 $8.75 $6.29 $7.48
  F&D – Proved $5.13 $5.56 $2.53 $3.63
  F&D – Proved Plus Probable $3.55 $5.57 $2.54 $3.36
  FD&A – Proved Developed Producing $9.38 $8.75 $4.79 $7.07
  FD&A – Proved $6.22 $5.55 $1.95 $3.59
  FD&A – Proved Plus Probable $5.08 $5.13 $2.35 $3.72
 Including FDC ($/boe)(1) 2019(2) 2018(3) 2017(4) 3-Year Average
  F&D – Proved $7.84 $0.64 $8.14 $6.57
  F&D – Proved Plus Probable $6.22 $1.27 $7.27 $5.89
  FD&A – Proved $8.71 $0.45 $7.16 $5.98
  FD&A – Proved Plus Probable $7.25 $1.47 $5.37 $4.88

(1) See “Advisories – Oil and Gas Metrics” for a description of the methodology used to calculate F&D and FD&A costs.
(2) Reflects the 2019 increase in FDC from 2018 of $118.8 million on a proved basis and $127.0 million on a proved plus probable basis.
(3) Reflects the 2018 decrease in FDC from 2017 of $272.2 million on a proved basis and $211.2 million on a proved plus probable basis.
(4) Reflects the 2017 increase in FDC from 2016 of $732.9 million on a proved basis and $352.9 million on a proved plus probable basis.

  • Birchcliff had positive recycle ratios for its proved developed producing reserves, notwithstanding that its F&D capital expenditures included $57 million of facilities and infrastructure and drilling and development capital spent in 2019, which did not result in the addition of proved developed producing reserves at year-end 2019.
  • The following table sets forth Birchcliff’s recycle ratios for its operating and adjusted funds flow netbacks for 2019 and 2018, excluding and including FDC:
  Operating Netback
Recycle Ratio(1)(2)
Adjusted Funds Flow
Netback Recycle Ratio
(1)(3)
2019 2018 2019 2018
Excluding FDC    
  F&D – Proved Developed Producing 1.5 1.5 1.4 1.3
  FD&A – Proved Developed Producing 1.4 1.5 1.3 1.3
  F&D – Proved 2.5 2.4 2.3 2.0
  FD&A – Proved 2.1 2.4 1.9 2.0
  F&D – Proved Plus Probable 3.7 2.4 3.3 2.0
  FD&A – Proved Plus Probable 2.6 2.6 2.3 2.2
Including FDC
  F&D – Proved 1.7 21.2 1.5 17.4
  FD&A – Proved 1.5 30.3 1.3 24.9
  F&D – Proved Plus Probable 2.1 10.7 1.9 8.8
  FD&A – Proved Plus Probable 1.8 9.2 1.6 7.6

(1) See “Advisories – Oil and Gas Metrics” for a description of the methodology used to calculate recycle ratios.
(2) Birchcliff’s operating netback was $13.07/boe in 2019, as compared to $13.52/boe in 2018.
(3) Birchcliff’s adjusted funds flow netback was $11.75/boe in 2019, as compared to $11.12/boe in 2018.

Birchcliff anticipates filing its annual information form and audited financial statements and related management’s discussion and analysis for the year ended December 31, 2019 on March 11, 2020.

This press release contains forward-looking statements within the meaning of applicable securities laws. For further information regarding the forward-looking statements contained herein, see “Advisories – Forward-Looking Statements”. In addition, this press release contains references to “adjusted funds flow”, “adjusted funds flow per basic common share”, “free funds flow”, “operating netback”, “adjusted funds flow netback”, “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, see “Non-GAAP Measures”. This press release also contains metrics commonly used in the oil and natural gas industry, including “netbacks”, “reserves life index”, “recycle ratio”, “reserves replacement”, “F&D costs” and “FD&A costs”, which do not have any standardized meanings. See “Advisories – Oil and Gas Metrics”. All financial and operating information for the fourth quarter and year ended December 31, 2019 is unaudited. See “Advisories – Unaudited Information”. With respect to the disclosure of Birchcliff’s production contained in this press release, see “Advisories – Production”.

2019 UNAUDITED FINANCIAL AND OPERATIONAL HIGHLIGHTS

  Three months ended
December 31,
Twelve months ended
December 31,
  2019 2018(5) 2019 2018(5)
OPERATING
Average production
  Light oil – (bbls/d) 4,435 4,788 4,742 4,873
  Condensate – (bbls/d)(1) 4,906 4,207 5,145 4,072
  NGLs – (bbls/d)(1) 7,814 6,814 7,264 6,123
  Natural gas – (Mcf/d) 364,847 363,596 364,958 372,170
  Total – boe/d 77,962 76,408 77,977 77,096
Average realized sales price (CDN$)(2)
  Light oil – (per bbl) 67.58 41.39 68.29 68.66
  Condensate – (per bbl)(1) 68.80 55.99 68.06 77.36
  NGLs – (per bbl)(1) 16.62 21.60 13.76 22.92
  Natural gas – (per Mcf) 2.81 3.03 2.48 2.45
  Total – per boe 22.97 22.01 21.55 22.08
 
NETBACK AND COST ($/boe)
  Petroleum and natural gas revenue(2) 22.97 22.01 21.56 22.08
  Royalty expense (1.15 ) (0.96 ) (0.96 ) (1.36 )
  Operating expense (3.06 ) (3.51 ) (3.09 ) (3.52 )
  Transportation and other expense (4.51 ) (4.07 ) (4.44 ) (3.68 )
Operating netback ($/boe) 14.25 13.47 13.07 13.52
  G&A expense, net (1.26 ) (1.08 ) (0.94 ) (0.87 )
  Interest expense (0.82 ) (1.06 ) (0.88 ) (0.99 )
  Realized gain (loss) on financial instruments (0.92 ) 0.24 0.48 (0.56 )
  Other income 0.03 0.03 0.02 0.02
Adjusted funds flow netback ($/boe) 11.28 11.60 11.75 11.12
  Depletion and depreciation expense (7.49 ) (7.29 ) (7.50 ) (7.42 )
  Unrealized gain (loss) on financial instruments (6.50 ) 11.02 (6.77 ) 2.28
  Other expenses(3) (0.28 ) (1.21 ) (0.51 ) (0.79 )
  Dividends on preferred shares (0.27 ) (0.26 ) (0.27 ) (0.27 )
  Income tax recovery (expense) 0.61 (3.77 ) 1.21 (1.44 )
Net income (loss) to common shareholders ($/boe) (2.65 ) 10.09 (2.09 ) 3.48
 
FINANCIAL
Petroleum and natural gas revenue ($000s)(2) 164,759 154,720 613,559 621,421
Cash flow from operating activities ($000s) 85,557 92,200 327,066 324,434
Adjusted funds flow ($000s) 80,941 81,517 334,504 312,922
  Per basic common share ($) 0.30 0.31 1.26 1.18
Net income (loss) to common shareholders ($000s) (18,984 ) 70,900 (59,579 ) 98,025
  Per basic common share ($) (0.07 ) 0.27 (0.22 ) 0.37
End of period basic common shares (000s) 265,935 265,911 265,935 265,911
Weighted average basic common shares (000s) 265,935 265,910 265,930 265,852
Dividends on common shares ($000s) 6,981 6,648 27,923 26,586
Dividends on preferred shares ($000s) 1,922 1,922 7,687 7,687
Total capital expenditures ($000s)(4) 58,136 52,886 300,246 298,018
Long-term debt ($000s) 609,177 605,267 609,177 605,267
Total debt ($000s) 632,582 626,454 632,582 626,454

(1) Beginning in Q1 2019, Birchcliff began presenting condensate and NGLs separately. Prior period sales and volumes have been adjusted to conform to this current period presentation. See “Advisories – Production”.
(2) Excludes the effects of financial instruments but includes the effects of physical delivery contracts.
(3) Includes non-cash expenses such as compensation, accretion, amortization of deferred financing fees and other losses.
(4) Total capital expenditures for the year ended December 31, 2019 include the $39 million Acquisition. See “Advisories – Capital Expenditures”.
(5) Birchcliff adopted IFRS 16: Leases effective January 1, 2019 using the modified retrospective approach; therefore 2018 comparative information has not been restated.

Q4 AND FULL-YEAR 2019 UNAUDITED FINANCIAL AND OPERATIONAL RESULTS

Production

Birchcliff’s production averaged 77,962 boe/d in Q4 2019, a 2% increase from 76,408 boe/d in Q4 2018. Birchcliff’s full-year 2019 production averaged 77,977 boe/d, a 1% increase from 77,096 boe/d in 2018, in line with its guidance of 77,000 to 79,000 boe/d. The increases were primarily due to the success of Birchcliff’s capital program which resulted in incremental production from new horizontal oil wells brought on production in Gordondale and horizontal condensate-rich natural gas wells in Pouce Coupe, partially offset by natural production declines.

Liquids accounted for approximately 22% of Birchcliff’s total production in Q4 2019 (12% light oil and condensate and 10% NGLs) as compared to approximately 21% in Q4 2018 (12% light oil and condensate and 9% NGLs), with total liquids production increasing by 9% from Q4 2018. For the full-year 2019, liquids accounted for approximately 22% of Birchcliff’s total production (13% light oil and condensate and 9% NGLs) as compared to approximately 20% in 2018 (11% light oil and condensate and 9% NGLs), in line with its guidance of 22% liquids. Total liquids production for the full-year 2019 increased by 14% from 2018. The change in the commodity production mix was primarily due to the addition of condensate-rich natural gas wells in Pouce Coupe and an increase in C3+ extracted from the natural gas stream at the Corporation’s 100% owned and operated natural gas processing plant in Pouce Coupe (the “Pouce Coupe Gas Plant”).

Adjusted Funds Flow

Birchcliff’s adjusted funds flow for Q4 2019 was $80.9 million, or $0.30 per basic common share, a 1% decrease and a 3% decrease, respectively, from $81.5 million and $0.31 per basic common share in Q4 2018. The decrease was primarily due to a realized loss on financial instruments and an increase in transportation and other expense as a result of Birchcliff’s increased Dawn and AECO firm service, partially offset by higher reported revenue and lower operating expense. Revenue received by the Corporation was higher primarily due to an increase in total liquids production and a higher average realized liquids sales price, partially offset by a lower average realized natural gas sales price.

Birchcliff’s full-year 2019 adjusted funds flow was $334.5 million, or $1.26 per basic common share, each a 7% increase from $312.9 million and $1.18 per basic common share in 2018, in line with its guidance of $335 million. The increases were primarily due to lower operating and royalty expenses and a realized gain on financial instruments as compared to a realized loss on financial instruments in 2018, partially offset by lower reported revenue and an increase in transportation and other expense as a result of Birchcliff’s increased Dawn and AECO firm service. Revenue received by the Corporation was lower primarily due to a lower average realized liquids sales price, partially offset by higher total liquids production.

Net Loss to Common Shareholders

Birchcliff recorded a net loss to common shareholders of $19.0 million, or $0.07 per basic common share, in Q4 2019, as compared to net income to common shareholders of $70.9 million and $0.27 per basic common share in Q4 2018. The change from a net income to a net loss position was primarily due to a $46.6 million unrealized mark-to-market loss on financial instruments recorded in Q4 2019 as compared to a $77.4 million unrealized mark-to-market gain on financial instruments in Q4 2018, resulting in a period-over-period change of $124.0 million (or $91.1 million on an after-tax basis). See “– Risk Management”.

Birchcliff recorded a net loss to common shareholders of $59.6 million, or $0.22 per basic common share, in 2019 as compared to net income to common shareholders of $98.0 million and $0.37 per basic common share in 2018. The change from a net income to a net loss position was primarily due to a $192.8 million unrealized mark-to-market loss on financial instruments recorded in 2019 as compared to a $64.2 million unrealized mark-to-market gain on financial instruments in 2018, resulting in a year-over-year change of $257.0 million (or $188.9 million on an after-tax basis), partially offset by higher adjusted funds flow. See “– Risk Management”.

Operating Expense

The Corporation remained focused on reducing its operating costs in 2019, resulting in a quarterly operating expense of $3.06/boe in Q4 2019, a 13% decrease from $3.51/boe in Q4 2018, and record low operating expense for the full-year 2019 of $3.09/boe, a 12% decrease from $3.52/boe in 2018. Birchcliff’s full-year annual operating expense was better than its guidance of $3.15/boe to $3.35/boe. The decreases were primarily due to: (i) a step-down reduction in natural gas processing fees which became effective January 1, 2019 at AltaGas’ deep-cut sour gas processing facility in Gordondale; (ii) reduced take-or-pay processing commitments in Pouce Coupe beginning in November 2018 which resulted in natural gas being redirected from third-party facilities to the Pouce Coupe Gas Plant; and (iii) increased operating efficiencies resulting from expanded liquids-handling capabilities in Pouce Coupe.

Operating Netback

Birchcliff’s operating netback was $14.25/boe in Q4 2019, a 6% increase from $13.47/boe in Q4 2018. Birchcliff’s full-year 2019 operating netback was $13.07/boe, a 3% decrease from $13.52/boe in 2018. The increase in Q4 2019 was primarily due to a higher average realized commodity sales price and lower per boe operating expense, partially offset by higher per boe royalty and transportation and other expenses. The decrease in the full-year 2019 was primarily due to a lower average realized commodity sales price and higher per boe transportation and other expense, partially offset by lower per boe royalty and operating expenses.

Total Cash Costs

Birchcliff’s total cash costs were $10.80/boe in Q4 2019, a 1% increase from $10.68/boe in Q4 2018. Birchcliff’s full-year 2019 total cash costs were $10.31/boe, a 1% decrease from $10.42/boe in 2018. The reasons for the changes in total cash costs are consistent with the explanation for operating netback, and include higher per boe G&A expense, partially offset by lower per boe interest expense in both periods.

Pouce Coupe Gas Plant Netbacks

During 2019, Birchcliff processed approximately 72% of its total corporate natural gas production and 62% of its total corporate production through the Pouce Coupe Gas Plant as compared to 67% and 57%, respectively, during 2018. The following table sets forth Birchcliff’s average daily production and operating netback for wells producing to the Pouce Coupe Gas Plant for the periods indicated:

  2019 2018
Average production:
  Condensate (bbls/d) 3,801 2,430
  NGLs (bbls/d) 934 179
  Natural gas (Mcf/d) 263,108 250,011
Total (boe/d) 48,587 44,278
Liquids-to-gas ratio (bbls/MMcf)(1)   18.0   10.4
Netback and cost: $/Mcfe
$/boe
$/Mcfe
$/boe
  Petroleum and natural gas revenue(2) 3.20 19.17 3.02 18.11
  Royalty expense (0.07 ) (0.42 ) (0.05 ) (0.29 )
  Operating expense(3) (0.34 ) (2.05 ) (0.34 ) (2.02 )
  Transportation and other expense (0.76 ) (4.54 ) (0.59 ) (3.56 )
Operating netback $2.03 $12.16 $2.04 $12.24
Operating margin(4) 63 % 63 % 68 % 68 %

(1) “Liquids” consists of NGLs, including condensate.
(2) Excludes the effects of financial instruments but includes the effects of physical delivery contracts.
(3) Represents plant and field operating expense.
(4) Operating margin is calculated by dividing the operating netback for the period by the petroleum and natural gas revenue for the period.

Birchcliff’s liquids-to-gas ratio increased by 73% as compared to 2018 primarily due to: (i) specifically targeted condensate-rich natural gas wells that were brought on production in Pouce Coupe in 2019; and (ii) the re-configuration of Phases V and VI of the Pouce Coupe Gas Plant in Q4 2018 which provided for shallow-cut capability, allowing Birchcliff to extract C3+ from the natural gas stream. The amount of condensate from Montney horizontal natural gas wells being produced to the Pouce Coupe Gas Plant increased by 56% to 3,801 bbls/d in 2019 from 2,430 bbls/d in 2018. The increase in the liquids-to-gas ratio improved Birchcliff’s average realized sales price at the Pouce Coupe Gas Plant.

Debt

At December 31, 2019, Birchcliff had significant liquidity with long-term debt of $609.2 million (December 31, 2018: $605.3 million) from available credit facilities of $1.0 billion (December 31, 2018: $950 million), leaving $384.3 million of unutilized credit capacity after adjusting for outstanding letters of credit and unamortized interest and fees. Total debt at December 31, 2019 was $632.6 million as compared to $626.5 million at December 31, 2018.

Birchcliff’s credit facilities mature on May 11, 2022 and do not contain any financial maintenance covenants.

Commodity Prices

The following table sets forth the average benchmark index prices for the periods indicated:

  Three months ended December 31, Twelve months ended December 31,
  2019 2018 % Change 2019 2018 % Change
Average benchmark index prices:
  Light oil – WTI Cushing (US$/bbl) 56.96 58.81 (3 %) 57.03 64.77 (12 %)
  Light oil – MSW (Mixed Sweet) (CDN$/bbl) 67.66 42.42 60 % 68.72 69.04
  Natural gas – NYMEX HH (US$/MMBtu)(1) 2.50 3.76 (34 %) 2.63 3.07 (14 %)
  Natural gas – AECO 5A Daily (CDN$/GJ) 2.35 1.48 59 % 1.67 1.42 18 %
  Natural gas – AECO 7A Month Ahead (US$/MMBtu)(1) 1.77 1.45 22 % 1.22 1.54 (21 %)
  Natural gas – Dawn Day Ahead (US$/MMBtu)(1) 2.23 3.78 (41 %) 2.40 3.12 (23 %)
  Natural gas – ATP 5A Day Ahead (CDN$/GJ) 1.92 2.57 (25 %) 1.66 2.07 (20 %)
  Exchange rate (CDN$ to US$1) 1.3201 1.3215 1.3269 1.2961 2 %
  Exchange rate (US$ to CDN$1) 0.7575 0.7567 0.7536 0.7715 (2 %)

(1) $1.00/MMBtu = $1.00/Mcf based on a standard heat value Mcf. See “Advisories – MMBtu Pricing Conversions”.

Risk Management

Birchcliff engages in risk management activities by utilizing various financial instruments and physical delivery contracts to diversify its sales points or fix commodity prices and market interest rates, including NYMEX/AECO basis swaps which fix the basis differential between AECO and NYMEX HH prices, effectively providing for a floating NYMEX HH price.

Birchcliff realized a cash loss on financial instruments of $6.6 million in Q4 2019 as compared to a realized cash gain on financial instruments of $1.7 million in Q4 2018. In the full-year 2019, Birchcliff realized a cash gain on financial instruments of $13.7 million as compared to a realized cash loss of $15.8 million in 2018. The realized cash gain and loss reported in the full-year 2019 and Q4 2019 periods, respectively, were primarily due to the settlement of financial NYMEX/AECO basis swap contracts that were outstanding in the periods.

Birchcliff recorded an unrealized non-cash loss on financial instruments of $46.6 million in Q4 2019 and an unrealized non-cash loss on financial instruments of $192.8 million in the full-year 2019. The unrealized non-cash losses on financial instruments reported in the 2019 periods were primarily due to the decrease in the fair value of the Corporation’s financial instruments to a liability position of $132.6 million at December 31, 2019. The fair value of the liability is the estimated discounted value to settle outstanding financial contracts at a point in time. The decrease in the fair value of Birchcliff’s financial instruments during 2019 was primarily attributable to: (i) the decrease in the forward basis spread between NYMEX HH and AECO 7A for contracts outstanding at December 31, 2019 as compared to the fair value previously assessed at September 30, 2019 and December 31, 2018; and (ii) the settlement of financial NYMEX/AECO basis swap contracts in 2019.

The unrealized gains and losses on financial NYMEX HH basis contracts can fluctuate materially from period-to-period due to movement in the forward NYMEX HH and AECO 7A strip prices. Unrealized gains and losses on financial instruments do not impact adjusted funds flow and may differ materially from the actual gains or losses realized on the eventual cash settlement of financial contracts in a period.

Marketing and Natural Gas Market Diversification

Birchcliff’s physical natural gas sales exposure primarily consists of the AECO, Dawn and Alliance markets. Effective November 1, 2019, Birchcliff’s level of firm service on TCPL’s Canadian Mainline to Dawn increased to 175,000 GJ/d from 150,000 GJ/d. In addition, the Corporation has various financial instruments outstanding that provide it with exposure to NYMEX HH pricing.

The following table details Birchcliff’s effective sales, production and average realized sales price for natural gas and liquids for Q4 2019, after taking into account the Corporation’s financial instruments:

Three months ended December 31, 2019
   Effective
sales
(CDN$000s)
Percentage of total sales
(%)
Effective
production
(per day)
Percentage of
total natural gas production
(%)
Percentage of
total corporate production
(%)
Effective average realized
sales price
(CDN$)
Markets
AECO(1) 27,536 17 113,196 Mcf 31 24 2.64/Mcf
Dawn(2) 43,706 28 152,115 Mcf 42 33 3.12/Mcf
Alliance(3) 1,507 1 8,271 Mcf 2 2 1.98/Mcf
NYMEX HH(1) 14,875 9 91,265 Mcf 25 19 1.77/Mcf
Total natural gas 87,624 55 364,847 Mcf 100 78 2.61/Mcf
Light oil 27,571 17 4,435 bbls 6 67.58/bbl
Condensate 31,050 20 4,906 bbls 6 68.80/bbl
NGLs 11,944 8 7,814 bbls 10 16.62/bbl
Total liquids 70,565 45 17,155 bbls   22 44.71/bbl
Total corporate 158,189 100 77,962 boe   100 22.05/boe

(1) A portion of AECO 5A sales and production that effectively received NYMEX HH pricing under Birchcliff’s long-term physical and financial NYMEX/AECO 7A basis swap contracts has been included as effective sales and production in NYMEX HH markets. Birchcliff sold financial and physical AECO 7A basis swaps for 100,000 MMBtu/d at an average contract price of NYMEX HH less US$1.28/MMBtu during Q4 2019.
(2) Birchcliff has agreements for the firm service transportation of an aggregate of 175,000 GJ/d of natural gas on TCPL’s Canadian Mainline, whereby natural gas is transported to the Dawn trading hub in Southern Ontario. The first tranche of this service (120,000 GJ/d) became available on November 1, 2017, the second tranche (30,000 GJ/d) became available on November 1, 2018 and the third tranche (25,000 GJ/d) became available on November 1, 2019. Each tranche has a 10-year term.
(3) Birchcliff has sales agreements with a third party marketer to sell and deliver into the Alliance pipeline system until October 31, 2020. Alliance sales are recorded net of transportation tolls.

Effectively 83% of the Corporation’s sales revenue, representing 69% of its total natural gas production and 76% of its total corporate production, was generated from markets outside of AECO in Q4 2019, after taking into account its liquids sales and long-term financial NYMEX/AECO basis swap position.

The following tables set forth Birchcliff’s sales, production, average realized sales price, transportation costs and natural gas sales netback by natural gas market for the periods indicated, before taking into account the Corporation’s financial instruments:

Three months ended December 31, 2019
Natural gas
sales
(1)
($000s)
Percentage of natural gas sales
(%)
Natural gas production
(Mcf/d)
Percentage of natural gas production
(%)
Average realized
natural gas sales
price(1)
($/Mcf)
Natural gas transportation costs(2)
($/Mcf)
Natural gas sales netback(3)
($/Mcf)
AECO 48,976 52 204,461 56 2.60 0.34 2.26
Dawn(4) 43,706 46 152,115 42 3.12 1.37 1.75
Alliance(5) 1,507 2 8,271 2 1.98 1.98
Total 94,189 100 364,847 100 2.81 0.77 2.04
Three months ended December 31, 2018
Natural gas
sales
(1)
($000s)
Percentage of natural gas sales
(%)
Natural gas production
(Mcf/d)
Percentage of natural gas production
(%)
Average realized
natural gas sales
price(1)
($/Mcf)
Natural gas transportation costs(2)
($/Mcf)
Natural gas sales netback(3)
($/Mcf)
AECO 33,788 33 223,261 61 1.67 0.31 1.36
Dawn(4) 64,969 64 127,211 35 5.55 1.34 4.21
Alliance(5) 2,492 3 13,124 4 2.06 2.06
Total 101,249 100 363,596 100 3.03 0.66 2.37

(1) Excludes the effects of financial instruments but includes the effects of physical delivery contracts.
(2) Reflects costs to transport natural gas from the field receipt point to the delivery sales trading hub.
(3) Natural gas sales netback denotes the average realized natural gas sales price less natural gas transportation costs.
(4) During Q4 2018, Birchcliff entered into physical natural gas delivery contracts at Dawn for 50,000 MMBtu/d at an average contract price of US$5.05/MMBtu for the period from December 1, 2018 to March 31, 2019. There were no physical delivery contracts in place at Dawn subsequent to March 31, 2019.
(5) Alliance transportation tolls are recorded net of sales price.

Capital Activities and Investment

Birchcliff’s successful 2019 capital program (the “2019 Capital Program”) was focused on the drilling of high-value light oil wells in Gordondale and condensate-rich and low-cost natural gas wells in Pouce Coupe. In addition, the 2019 Capital Program advanced the Corporation’s 20,000 bbls/d (50% condensate, 50% water) inlet liquids-handling facility at the Pouce Coupe Gas Plant (the “Inlet Liquids-Handling Facility”) and directed funds towards other infrastructure enhancement projects. The 2019 Capital Program was strategically front-end loaded resulting in a more efficient capital spending and production profile during the year. This allowed Birchcliff to realize numerous capital cost savings and bring new wells on production relatively early in the year, optimizing producing days in the year for the capital spent.

During 2019, Birchcliff drilled 30 (30.0 net) horizontal wells, 7 (7.0 net) of which were drilled in Q4 2019 to help ensure the efficient execution of the Corporation’s 2020 capital program. Of these, 5 (5.0 net) were condensate-rich natural gas wells in Pouce Coupe and 2 (2.0 net) were oil wells in Gordondale. The Corporation brought on production 33 (33.0 net) wells during 2019, including 9 (9.0 net) wells that were drilled in Q4 2018 and 1 of the 7 wells drilled in Q4 2019, the remaining 6 of which will be brought on production in Q1 and Q2 2020. All wells drilled in 2019 were drilled on multi-well pads, which allows Birchcliff to reduce its per well costs and environmental footprint. The following table summarizes the number of wells Birchcliff drilled and brought on production in 2019:

Area Total wells drilled in 2019(1) Total wells brought on production in 2019(2)
Pouce Coupe
Montney D1 horizontal natural gas wells 9 14
Montney D2 horizontal natural gas wells 5 2
Montney C horizontal natural gas wells 2 1
Total – Pouce Coupe 16 17
Gordondale
Montney D4 horizontal oil wells 1 0
Montney D2 horizontal oil wells 7 9
Montney D1 horizontal oil wells 6 7
Total – Gordondale 14 16
TOTAL – COMBINED 30 33

(1) Includes the 6 additional wells drilled in Q4 2019.
(2) Does not include the 6 additional wells drilled in Q4 2019 as none of these wells were brought on production in 2019. In addition, the 2019 Capital Program included the capital associated with 9 Montney/Doig wells (5 in Pouce Coupe and 4 in Gordondale) that were drilled in Q4 2018 and subsequently brought on production in 2019.

Total capital expenditures for 2019 were $300.2 million, including F&D capital expenditures of $256.4 million, as compared to Birchcliff’s guidance of $283.0 million and $242.0 million, respectively. Total capital expenditures were $58.1 million in Q4 2019.

Pouce Coupe

Key focus areas for Pouce Coupe in 2019 were the drilling of condensate-rich natural gas wells and the further exploitation and delineation of condensate-rich trends in the Montney D1, D2 and C intervals. In 2019, the Corporation drilled 16 (16.0 net) wells and brought on production 17 (17.0 net) wells. Birchcliff has been encouraged with the results of the wells brought on production in 2019, with strong condensate rates and the benefits from improved prices at AECO in Q4 2019. For details regarding Birchcliff’s drilling results, see its updated corporate presentation available on its website at www.birchcliffenergy.com/investors/corporate-presentation/.

Birchcliff also initiated the construction of the Inlet Liquids-Handling Facility in 2019 in order to handle increased condensate volumes in the area. Once completed, this facility will give Birchcliff the ability to increase its condensate production in the Pouce Coupe area to approximately 10,000 bbls/d (2019: 3,801 bbls/d). Fabrication of the various components and site preparation are underway. The facility is anticipated to be online in Q3 2020.

On January 3, 2019, Birchcliff completed the Acquisition of 18 gross (15.1 net) contiguous sections of Montney land located between its existing Pouce Coupe and Gordondale properties. The Acquisition demonstrates the highly functional integrated teams working together at Birchcliff. The Acquisition was directly related to the learnings from the offsetting 2018 science and technology pad, which led to the evaluation and acquisition of these lands. That, in turn, allowed Birchcliff’s operations team to quickly and efficiently drill, complete and bring on production 6 wells on the acquired lands in early 2019, targeting condensate-rich natural gas. The wells were drilled in three different intervals (4 in the Montney D1, 1 in the Montney D2 and 1 in the Montney C) and have shown strong production results, including high condensate-to-gas ratios.

With the positive results of the first 6 wells on the acquired lands, specifically in the new Montney D2 and C drilling intervals, Birchcliff returned to this pad in Q4 2019 to drill an additional 6 (6.0 net) wells, 3 Montney D2 and 3 Montney C wells, 2 of which were drilled by year-end 2019. These 6 wells will be brought on production in Q2 2020.

Gordondale

Key focus areas for Gordondale in 2019 were the drilling of crude oil wells and the further exploitation and delineation of oil in the Montney D1 and D2 intervals, specifically in the southeastern part of the Gordondale field. Birchcliff drilled 14 (14.0 net) horizontal wells and brought 16 (16.0 net) wells on production in Gordondale in 2019.

Due to the Corporation’s success in the southeastern part of the Gordondale field and the targeted activity expected in 2020, Birchcliff commenced the engineering and procurement for the addition of natural gas compression at both of its 100% owned and operated oil batteries in Gordondale in 2019. The Corporation also initiated the construction of a significant trunk line to transport oil, natural gas and water to these batteries from the southeastern portion of the field. Both projects are expected to be completed in Q2 2020, in conjunction with the bringing on production of 10 wells in the southeastern part of the field.

For details regarding Birchcliff’s drilling results, see its updated corporate presentation available on its website at www.birchcliffenergy.com/investors/corporate-presentation/.

Potential Future Drilling Opportunities on the Montney/Doig Resource Play

As at December 31, 2019, Birchcliff held 413.2 sections of land that have potential for the Montney/Doig Resource Play. Of these lands, 408.2 (378.3 net) sections have potential for the Basal Doig/Upper Montney interval, 381.7 (368.9 net) sections have potential for the Montney D4 interval, 387.4 (373.5 net) sections have potential for the Montney D2 interval, 385.9 (372.0 net) sections have potential for the Montney D1 interval and 386.8 (372.8 net) sections have potential for the Montney C interval. As at December 31, 2019, Birchcliff’s total land holdings on these five intervals were 1,950.0 (1,865.5 net) sections. Assuming full development of four horizontal wells per section per drilling interval, Birchcliff has 7,462.0 net existing horizontal wells and potential net future horizontal drilling locations in respect of the Basal Doig/Upper Montney and the Montney D1, D2, D4 and C intervals as at December 31, 2019. With 425 (417.4 net) horizontal locations drilled at the end of 2019, there remains 7,044.6(1) potential net future horizontal drilling locations as at December 31, 2019, up from 6,365.8 at year-end 2018. This increase is largely due to the acquisition of third party and crown lands within Birchcliff’s key focus areas.

Birchcliff’s consolidated reserves report effective December 31, 2019 attributed proved reserves to 939.3 net existing wells and potential net future horizontal drilling locations (of which 533.1 net wells are potential future drilling locations) and proved plus probable reserves to 1,175.1 net existing wells and potential net future horizontal drilling locations (of which 768.9 net wells are potential future drilling locations). The remaining 6,286.9 potential net future horizontal drilling locations have not yet had any proved or probable reserves attributed to them by Birchcliff’s independent qualified reserves evaluators. See “2019 Year-End Reserves” and “Advisories – Drilling Locations”.

1 This does not include any potential net future horizontal drilling locations for the other prospective Montney interval, the Montney D3.

2019 YEAR-END RESERVES

Birchcliff retained two independent qualified reserves evaluators, Deloitte LLP (“Deloitte”) and McDaniel & Associates Consultants Ltd. (“McDaniel”), to evaluate and prepare reports on 100% of Birchcliff’s light crude oil and medium crude oil, conventional natural gas, shale gas and NGLs reserves. Deloitte evaluated all of Birchcliff’s properties other than the Corporation’s assets in Gordondale and Progress, representing approximately 80% of the assigned total proved plus probable reserves, and McDaniel evaluated the reserves attributable to the Corporation’s assets in Gordondale and Progress, representing approximately 20% of the assigned total proved plus probable reserves.

The reserves data set forth below at December 31, 2019 is based upon the evaluations by Deloitte with an effective date of December 31, 2019 as contained in the report of Deloitte dated February 12, 2020 (the “2019 Deloitte Reserves Report”) and the evaluation by McDaniel with an effective date of December 31, 2019 as contained in the report of McDaniel dated February 12, 2020 (the “2019 McDaniel Reserves Report”), which are contained in the consolidated report of Deloitte dated February 12, 2020 with an effective date of December 31, 2019 (the “2019 Consolidated Reserves Report”). Deloitte prepared the 2019 Consolidated Reserves Report by consolidating the properties evaluated by Deloitte in the 2019 Deloitte Reserves Report with the properties evaluated by McDaniel in the 2019 McDaniel Reserves Report. The forecast commodity prices, inflation and exchange rates utilized were computed using the average of forecasts from Deloitte, McDaniel, GLJ Petroleum Consultants Ltd. and Sproule Associates Ltd. effective January 1, 2020 (the “2019 IQRE Price Forecast”).

Deloitte also prepared an evaluation with an effective date of December 31, 2018 as contained in the report of Deloitte dated February 13, 2019 (the “2018 Deloitte Reserves Report”) and McDaniel prepared an evaluation with an effective date of December 31, 2018 as contained in the report of McDaniel dated February 13, 2019 (the “2018 McDaniel Reserves Report”), which are contained in the consolidated report of Deloitte with an effective date of December 31, 2018 (the “2018 Consolidated Reserves Report”). Deloitte prepared the 2018 Consolidated Reserves Report by consolidating the properties evaluated by Deloitte in the 2018 Deloitte Reserves Report with the properties evaluated by McDaniel in the 2018 McDaniel Reserves Report, in each case using Deloitte’s forecast price and cost assumptions effective December 31, 2018 (the “2018 Deloitte Price Forecast”).

All of the above-noted reserves reports were prepared in accordance with the standards contained in the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”) and National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) in effect at the relevant time.

For additional information regarding the presentation of Birchcliff’s reserves disclosure contained herein, see “Presentation of Oil and Gas Reserves” and “Advisories” in this press release. The reserves data provided in this press release presents only a portion of the disclosure required under NI 51-101. The disclosure required under NI 51-101 will be contained in Birchcliff’s Annual Information Form for the year ended December 31, 2019, which is expected to be filed on the System for Electronic Document Analysis and Retrieval (www.sedar.com) on March 11, 2020. In certain of the tables below, numbers may not add due to rounding.

Reserves Summary

The following table summarizes the estimates of Birchcliff’s gross reserves at December 31, 2019 and December 31, 2018, estimated using the forecast price and cost assumptions in effect as at the effective dates of the applicable reserves evaluations:

Summary of Gross Reserves
(Forecast Prices and Costs)

Reserves Category December 31, 2019
(Mboe)
December 31, 2018
(Mboe)
Change from
December 31, 2018
Proved Developed Producing 206,922.4 203,631.0 2%
Total Proved 709,061.2 689,674.1 3%
Probable 323,133.5 312,396.0 3%
Total Proved Plus Probable 1,032,194.7 1,002,070.1 3%

The following table sets forth Birchcliff’s light crude oil and medium crude oil, conventional natural gas, shale gas and NGLs reserves at December 31, 2019, estimated using the 2019 IQRE Price Forecast:

Summary of Reserves at December 31, 2019
(Forecast Prices and Costs)

Reserves Category Light Crude Oil and
Medium Crude Oil

Conventional
Natural Gas
Shale Gas
NGLs(1)
Total Boe
Gross
(Mbbls)
Net
(Mbbls)
Gross
(MMcf)
Net
(MMcf)
Gross
(MMcf)
Net
(MMcf)
Gross
(Mbbls)
Net
(Mbbls)
Gross
(Mboe)
Net
(Mboe)
Proved
Developed Producing 9,695.0 7,951.6 7,814.9 7,266.9 982,141.3 922,927.5 32,234.6 25,443.1 206,922.4 188,427.2
Developed Non-Producing 0.0 0.0 781.0 726.3 21,756.0 20,362.1 650.9 547.0 4,407.1 4,061.8
Undeveloped 11,358.3 9,801.8 2,870.5 2,624.0 2,576,268.7 2,414,085.0 56,516.9 46,590.6 497,731.7 459,177.2
Total Proved 21,053.3 17,753.5 11,466.4 10,617.2 3,580,166.0 3,357,374.6 89,402.5 72,580.7 709,061.2 651,666.1
Probable 12,543.4 10,172.4 8,348.4 7,850.7 1,553,306.8 1,437,876.2 50,314.2 39,829.8 323,133.5 290,956.6
Total Proved Plus Probable 33,596.8 27,925.8 19,814.8 18,467.9 5,133,472.7 4,795,250.8 139,716.7 112,410.5 1,032,194.7 942,622.8

(1) NGLs includes condensate.

Net Present Values of Future Net Revenue

The following table sets forth the net present values of future net revenue attributable to Birchcliff’s reserves at December 31, 2019, estimated using the 2019 IQRE Price Forecast, before deducting future income tax expenses and calculated at various discount rates:

Summary of Net Present Values of Future Net Revenue at December 31, 2019(1)(2)
(Forecast Prices and Costs)

Reserves Category Before Income Taxes Discounted At (%/year) 
0
(MM$)
5
(MM$)
10
(MM$)
15
(MM$)
20 (MM$) Unit Value Discounted at 10%/year ($/boe)(3)
Proved
Developed Producing 3,258.4 2,462.2 1,938.5 1,594.6 1,357.2 10.29
Developed Non-Producing 79.2 39.8 19.5 7.7 0.3 4.80
Undeveloped 7,044.1 3,759.9 2,148.9 1,271.7 755.5 4.68
Total Proved 10,381.7 6,261.9 4,106.9 2,874.0 2,113.1 6.30
Probable 5,890.7 2,481.5 1,207.6 654.3 383.8 4.15
Total Proved Plus Probable 16,272.4 8,743.3 5,314.5 3,528.3 2,496.9 5.64

(1) Estimates of future net revenue, whether calculated without discount or using a discount rate, do not represent fair market value.
(2) Includes abandonment, decommissioning and reclamation costs for all oil and natural gas assets, including all wells, gathering systems, pipelines, facilities and surface land development.
(3) Unit values are based on net reserves.

Pricing Assumptions

The following table sets forth the 2019 IQRE Price Forecast used in the 2019 Consolidated Reserves Report:

2019 IQRE Price Forecast

Year Crude Oil Natural Gas(1)
NGLs
Currency Exchange Rate (CDN$/US$)  Price and Cost Inflation Rates (%)
WTI at Cushing Oklahoma (US$/bbl) Edmonton City Gate (CDN$/bbl) Alberta AECO
Average
Price

(CDN$/Mcf)
Ontario Dawn
Reference Point
(CDN$/Mcf)
NYMEX Henry Hub (US$/Mcf) Edmonton Ethane (CDN$/bbl) Edmonton Propane (CDN$/bbl) Edmonton Butane (CDN$/bbl) Edmonton Pentanes + Condensate (CDN$/bbl)
2020 60.25 71.58 2.05 3.27 2.57 6.29 24.04 37.56 74.21 0.760 0.0
2021 63.11 75.33 2.32 3.62 2.79 7.17 28.75 44.41 78.15 0.768 2.0
2022 66.02 77.51 2.60 3.80 2.99 8.04 33.14 50.19 80.48 0.779 2.0
2023 67.64 79.77 2.74 3.94 3.15 8.45 34.16 51.67 82.77 0.789 2.0
2024 69.16 81.60 2.82 4.05 3.22 8.73 35.00 52.88 84.66 0.786 2.0
2025 70.69 83.46 2.91 4.14 3.29 8.97 35.85 54.09 86.56 0.789 2.0
2026 72.25 85.34 2.97 4.23 3.35 9.18 36.71 55.33 88.49 0.789 2.0
2027 73.77 87.19 3.03 4.31 3.43 9.38 37.55 56.53 90.40 0.789 2.0
2028 75.25 88.97 3.10 4.40 3.49 9.58 38.37 57.69 92.22 0.789 2.0
2029 76.76 90.79 3.16 4.48 3.56 9.81 39.19 58.87 94.09 0.789 2.0
2030 78.29 92.61 3.24 4.57 3.64 10.01 40.03 60.05 96.00 0.789 2.0
2031 79.86 94.46 3.30 4.67 3.71 10.22 40.83 61.25 97.91 0.789 2.0
2032 81.45 96.34 3.36 4.76 3.79 10.43 41.65 62.47 99.87 0.789 2.0
2033 83.08 98.27 3.44 4.85 3.86 10.62 42.48 63.72 101.87 0.789 2.0
2034 84.75 100.23 3.50 4.95 3.94 10.84 43.34 64.99 103.90 0.789 2.0
2035 86.44 102.25 3.57 5.05 4.01 11.06 44.20 66.29 105.99 0.789 2.0
2036 88.17 104.29 3.65 5.15 4.10 11.28 45.08 67.63 108.11 0.789 2.0
2037 89.93 106.37 3.71 5.26 4.17 11.50 45.98 68.97 110.26 0.789 2.0
2038 91.73 108.50 3.79 5.36 4.26 11.73 46.91 70.35 112.47 0.789 2.0
2039 93.57 110.66 3.86 5.47 4.34 11.98 47.84 71.76 114.71 0.789 2.0
  2039+ 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 0.789 2.0

(1) 1 Mcf = 1 MMBtu.

In comparison to the 2018 Deloitte Price Forecast, the AECO natural gas price forecast for 2020 decreased by 7%, the Dawn natural gas price forecast for 2020 decreased by 21%, the NYMEX HH natural gas price forecast for 2020 decreased by 18% and the Edmonton City Gate oil price forecast for 2020 decreased by 1%.

Reconciliation of Changes in Reserves

The following table sets forth a reconciliation of Birchcliff’s gross reserves at December 31, 2019 as set forth in the 2019 Consolidated Reserves Report, estimated using the 2019 IQRE Price Forecast, to Birchcliff’s gross reserves at December 31, 2018 as set forth in the 2018 Consolidated Reserves Report, estimated using the 2018 Deloitte Price Forecast:

Reconciliation of Gross Reserves from December 31, 2018 to December 31, 2019
(Forecast Prices and Costs)

Factors Light Crude Oil and
Medium Crude Oil (Mbbls)
Conventional Natural Gas (MMcf) Shale Gas (MMcf) NGLs (Mbbls) Oil Equivalent (Mboe)
GROSS TOTAL PROVED          
Opening balance December 31, 2018 20,513.9 9,479.7 3,588,937.0 69,424.1 689,674.1
Extensions and Improved Recovery(1) 2,700.4 0.0 274,162.5 9,974.3 58,368.5
Technical Revisions(2) (494.6 ) 957.6 (90,222.7 ) 14,979.7 (392.4 )
Discoveries(3) 0.0 0.0 0.0 0.0 0.0
Acquisitions(4) 257.4 2,805.3 11,985.5 402.8 3,125.3
Dispositions(5) 0.0 0.0 (29,912.5 ) (302.4 ) (5,287.8 )
Economic Factors(6) (193.1 ) (779.2 ) (42,571.1 ) (546.8 ) (7,964.9 )
Production(7) (1,730.7 ) (996.9 ) (132,212.8 ) (4,529.3 ) (28,461.6 )
Closing balance December 31, 2019 21,053.3 11,466.4 3,580,166.0 89,402.5 709,061.2
GROSS TOTAL PROBABLE
Opening balance December 31, 2018 14,318.3 8,546.2 1,519,533.0 43,397.8 312,396.0
Extensions and Improved Recovery(1) 536.4 0.0 174,021.8 6,914.4 36,454.4
Technical Revisions(2) (2,367.0 ) (439.8 ) (30,056.7 ) 2,762.1 (4,687.7 )
Discoveries(3) 0.0 0.0 0.0 0.0 0.0
Acquisitions(4) 365.8 475.6 11,093.7 397.8 2,691.8
Dispositions(5) (241.0 ) 0.0 (69,341.2 ) (2,462.6 ) (14,260.5 )
Economic Factors(6) (69.0 ) (233.6 ) (51,943.8 ) (695.2 ) (9,460.4 )
Production(7) 0.0 0.0 0.0 0.0 0.0
Closing balance December 31, 2019 12,543.4 8,348.4 1,553,306.8 50,314.2 323,133.5
GROSS TOTAL PROVED PLUS PROBABLE
Opening balance December 31, 2018 34,832.2 18,025.9 5,108,470.0 112,821.9 1,002,070.1
Extensions and Improved Recovery(1) 3,236.8 0.0 448,184.3 16,888.7 94,822.9
Technical Revisions(2) (2,861.6 ) 517.8 (120,279.3 ) 17,741.8 (5,080.1 )
Discoveries(3) 0.0 0.0 0.0 0.0 0.0
Acquisitions(4) 623.2 3,280.9 23,079.2 800.5 5,817.1
Dispositions(5) (241.0 ) 0.0 (99,253.8 ) (2,765.0 ) (19,548.3 )
Economic Factors(6) (262.2 ) (1,012.8 ) (94,514.9 ) (1,241.9 ) (17,425.4 )
Production(7) (1,730.7 ) (996.9 ) (132,212.8 ) (4,529.3 ) (28,461.6 )
Closing balance December 31, 2019 33,596.8 19,814.8 5,133,472.7 139,716.7 1,032,194.7

(1) Additions to volumes resulting from capital expenditures for: (i) step-out drilling in previously discovered reservoirs; (ii) infill drilling in previously discovered reservoirs that were not drilled as part of an enhanced recovery scheme; and (iii) the installation of improved recovery schemes.
(2) Positive or negative volume revisions to an estimate resulting from new technical data or revised interpretations on previously assigned volumes, performance and operating costs.
(3) Additions to volumes in reservoirs where no reserves were previously booked.
(4) Positive additions to volume estimates because of purchasing interests in oil and gas properties.
(5) Reductions in volume estimates because of selling all or a portion of an interest in oil and gas properties.
(6) Changes to volumes resulting from different price forecasts, inflation rates and regulatory changes.
(7) Reductions in the volume estimates due to actual production.

Key highlights include the following:

  • Extensions and Improved Recovery – Reserves were added due to the wells that were drilled and brought on production pursuant to the Corporation’s successful 2019 Capital Program, which also resulted in the assignment of reserves to potential future drilling locations offsetting those wells.
  • Technical Revisions – The technical revisions in all reserves categories for light and medium crude oil were mainly a result of: (i) the performance of the existing producing oil wells; (ii) adjustments to the future well layouts in the development plan; and (iii) future well location adjustments based on offsetting well performance. The technical revisions in all reserves categories for shale gas were mainly a result of: (i) gas shrinkage as a result of higher NGLs extraction in the Pouce Coupe Gas Plant; and (ii) adjustments to the producing oil and gas wells and future oil and gas locations. The technical revisions in all reserves categories for NGLs were a mainly result of: (i) improved performance of the existing C3+ recoveries at Phases V and VI of the Pouce Coupe Gas Plant; (ii) increased condensate from the producing wells and future locations in Pouce Coupe; and (iii) additional C3+ extraction assumed for Phases I to IV of the Pouce Coupe Gas Plant.
  • Acquisitions – Changes were the result of the Acquisition, which occurred in January 2019, as well as various other minor acquisitions Birchcliff completed in the Gordondale and Pouce Coupe areas in 2019.
  • Dispositions – Changes were the result of various non-core dispositions Birchcliff completed in 2019.
  • Economic Factors – The forecast prices for each product type were lower in the 2019 IQRE Price Forecast than the 2018 Deloitte Price Forecast, which resulted in the economic limit at the end of a well’s life being achieved earlier and therefore a reduction of the reserves volumes in all reserves categories. The reduced price forecast also resulted in the loss of reserves for 4 gross (2.5 net) proved undeveloped future natural gas locations and 11 gross (6.6 net) probable future natural gas locations, primarily in Elmworth, that did not generate a positive net present value at a 10% discount rate.

Future Development Costs

FDC reflects the independent reserves evaluators’ best estimate of what it will cost to bring the proved and proved plus probable reserves on production. Changes in forecast FDC occur annually as a result of development activities, acquisition and disposition activities and capital cost estimates. The following table sets forth development costs deducted in the estimation of Birchcliff’s future net revenue attributable to the reserves categories noted below:

Future Development Costs
(Forecast Prices and Costs)

  Proved (MM$) Proved Plus Probable (MM$)
2020 322.5 322.5
2021 411.8 475.4
2022 555.8 611.9
2023 775.8 818.0
2024 405.0 508.3
Thereafter 609.7 1,682.8
Total undiscounted 3,080.6 4,418.9

FDC for total proved reserves increased to $3.08 billion at December 31, 2019 from $2.96 billion at December 31, 2018. FDC for total proved plus probable reserves increased to $4.42 billion at December 31, 2019 from $4.29 billion at December 31, 2018. The increases in FDC for both proved and proved plus probable reserves were largely due to: (i) the addition of the Inlet Liquids-Handling Facility; (ii) the additional compression and line looping scheduled in 2020 in Gordondale; (iii) and the FDC associated with a net increase in Montney/Doig potential net future drilling locations added in each category of reserves as a result of Birchcliff’s successful 2019 drilling program.

The FDC for both proved and proved plus probable reserves are primarily the capital costs required to drill, complete, equip and tie-in the net undeveloped locations. The estimates of FDC on a proved and proved plus probable basis also include approximately $374 million (unescalated) for the continued expansion of the Pouce Coupe Gas Plant from the existing 340 MMcf/d to 660 MMcf/d of total throughput. The FDC for the expansions of the Pouce Coupe Gas Plant also include the costs of the related gathering pipelines and maintenance capital.

The following table sets forth the average cost to drill, complete, equip and tie-in a multi-stage fractured horizontal well as estimated by Deloitte and McDaniel:

Average Well Cost, as Estimated
by Deloitte or McDaniel
December 31, 2019
(MM$)
December 31, 2018
(MM$)
Pouce Coupe(1) 4.7 4.7
Gordondale(2) 5.4 5.4

(1) Estimated by Deloitte.
(2) Estimated by McDaniel.

Reserves Replacement

The following table sets forth Birchcliff’s 2019 reserves replacement ratios:

Reserves Category 2019 Reserves Replacement, Excluding the Effects of Acquisitions and Dispositions(1) 2019 Reserves Replacement, Including the Effects of Acquisitions and Dispositions(1)
Proved Developed Producing 104 % 112 %
Proved 176 % 168 %
Proved Plus Probable 254 % 206 %

(1) See “Advisories – Oil and Gas Metrics” for a description of the methodology used to calculate reserves replacement.

Reserves Life Index

The following table sets forth Birchcliff’s 2019 reserves life index:

Reserves Category   2019 Reserves Life Index(1)
Proved Developed Producing 7.0 years
Total Proved 24.0 years
Total Proved Plus Probable 34.9 years

(1) Based on a forecast production rate of 81,000 boe/d, which represents the mid-point of Birchcliff’s annual average production guidance range for 2020. See “Advisories – Oil and Gas Metrics” for a description of the methodology used to calculate reserves life index.

Reserves on the Montney/Doig Resource Play

The following table summarizes the estimates of reserves attributable to Birchcliff’s horizontal wells on the Montney/Doig Resource Play as contained in the 2019 Consolidated Reserves Report and the number of horizontal wells to which reserves were attributed:

Montney/Doig Resource Play Reserves Data(1)(2)

Shale Gas
(Bcf)
Light Crude Oil and Medium Crude Oil Combined
(Mbbls)
NGLs
(Mbbls)
Total
(Mboe)
 
Existing Horizontal Wells and Potential Future Horizontal Well Locations
(Gross) (Net)
Reserves Category 2019 2018 2019 2018 2019 2018 2019 2018 2019 2018 2019 2018
Proved Developed Producing 969.2 973.4 9,620.4 9,239.1 31,793.7 27,923.0 202,945.5 199,396.1 410(3) 368 403.2(3) 364.3
Total Proved 3,567.2 3,572.8 20,978.7 20,460.2 88,638.2 68,779.3 704,152.4 684,710.4 953 903 939.3 888.8
Total Proved Plus Probable 5,117.5 5,088.6 33,502.5 34,758.7 138,737.4 111,985.9 1,025,152.8 994,848.1 1,199 1,154 1,175.1 1,121.8

(1) Estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation.
(2) At December 31, 2019, the estimated FDC for Birchcliff’s reserves on its Montney/Doig Resource Play is $12.6 million on a proved developed producing basis (as compared to $0.0 million at December 31, 2018), $3,077.6 million on a proved basis (as compared to $2,958.7 million at December 31, 2018) and $4,409.8 million on a proved plus probable basis (as compared to $4,282.9 million at December 31, 2018).
(3) Does not include three 100% working interest proved non-producing wells.

ABBREVIATIONS

AECO benchmark price for natural gas determined at the AECO ‘C’ hub in southeast Alberta
bbl barrel
bbls barrels
bbls/d barrels per day
Bcf billion cubic feet
boe barrel of oil equivalent
boe/d barrel of oil equivalent per day
C3+ propane plus
condensate pentanes plus (C5+)
F&D finding and development
FD&A finding, development and acquisition
FDC future development costs
G&A general and administrative
GAAP generally accepted accounting principles for Canadian public companies which are currently IFRS
GJ gigajoule
GJ/d gigajoules per day
HH Henry Hub
IFRS International Financial Reporting Standards as issued by the International Accounting Standards Board
Mbbls thousand barrels
Mboe thousand barrels of oil equivalent
Mcf thousand cubic feet
Mcf/d thousand cubic feet per day
Mcfe thousand cubic feet of gas equivalent
MM$ millions of dollars
MMBtu million British thermal units
MMBtu/d million British thermal units per day
MMcf million cubic feet
MMcf/d million cubic feet per day
MSW price for mixed sweet crude oil at Edmonton, Alberta
NGLs natural gas liquids
NYMEX New York Mercantile Exchange
TCPL TransCanada PipeLines
WTI West Texas Intermediate, the reference price paid in U.S. dollars at Cushing, Oklahoma, for crude oil of standard grade
000s thousands
$000s thousands of dollars


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