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Birchcliff Energy Ltd. Announces Unaudited 2018 Year-End and Fourth Quarter Results, 2018 Reserves Highlights, 2019 Capital Program and Increased Common Share Dividend


CALGARY, Alberta, Feb. 13, 2019 (GLOBE NEWSWIRE) — Birchcliff Energy Ltd. (“Birchcliff” or the “Corporation”) (TSX: BIR) is pleased to announce its unaudited 2018 year-end and fourth quarter financial and operational results, highlights from its independent reserves evaluations effective December 31, 2018, its 2019 capital program and a 5% increase to its quarterly common share dividend.

Jeff Tonken, President and Chief Executive Officer of Birchcliff commented: “We executed on our business plan and delivered very strong financial and operational results in 2018, achieving both record annual average production and very low per boe operating costs. Our annual average production in 2018 was 77,096 boe/d, a 13% increase from 2017, and our operating costs decreased by 21% to $3.52/boe. In addition, we added profitable reserves with positive recycle ratios in all categories. Subsequent to year-end, Birchcliff completed a strategic acquisition where we acquired 18 gross (15.1 net) contiguous sections of Montney land located between our existing Pouce Coupe and Gordondale properties which has further consolidated our land position in the area. We recently commenced the drilling of a 6-well pad on these lands which is targeting condensate-rich natural gas wells.

Our board of directors has approved a disciplined capital budget for 2019, in line with our objective of generating free funds flow in 2019. The 2019 capital program targets an annual average production rate of 76,000 to 78,000 boe/d which is expected to generate approximately $330 million of adjusted funds flow. Total F&D capital expenditures are estimated to be $204 million, which are significantly less than our estimated 2019 adjusted funds flow. One of the highlights of our 2019 capital program is a continued focus on condensate production in Pouce Coupe which has led us to commit to the construction of a 20,000 bbls/d inlet liquids-handling facility at our Pouce Coupe gas plant. This facility is anticipated to be online in Q3 2020 and will give us the ability to grow our condensate production from 3,000 to 10,000 bbls/d at Pouce Coupe.”

2018 Year-End Highlights

  • Production averaged 77,096 boe/d (20% oil and NGLs), a 13% increase from 2017.
  • Adjusted funds flow of $312.9 million, or $1.18 per basic common share, a 1% decrease and a 2% decrease, respectively, from 2017.
  • Net income to common shareholders of $98.0 million, or $0.37 per basic common share, as compared to the net loss to common shareholders of $51.0 million and $0.19 per basic common share in 2017.
  • Operating expense of $3.52/boe, a 21% decrease from 2017.
  • Total cash costs of $10.42/boe, a 3% decrease from 2017.
  • Operating netback of $13.52/boe, a 3% decrease from 2017.
  • Total capital expenditures of $298.0 million. During 2018, Birchcliff drilled 36 (36.0 net) wells and brought 28 (28.0 net) wells on production.
  • As at December 31, 2018, Birchcliff’s long-term bank debt was $605.3 million and its total debt was $626.5 million, a 3% increase and a 5% increase, respectively, from its long-term and total debt as at December 31, 2017.

Q4 2018 Highlights

  • Production averaged 76,408 boe/d (21% oil and NGLs), a 5% decrease from Q4 2017.
  • Adjusted funds flow of $81.5 million, or $0.31 per basic common share, a 16% decrease and a 14% decrease, respectively, from Q4 2017.
  • Net income to common shareholders of $70.9 million, or $0.27 per basic common share, a 186% increase and a 200% increase, respectively, from Q4 2017.
  • Operating expense of $3.51/boe, a 9% decrease from Q4 2017.
  • Total cash costs of $10.68/boe, a 2% decrease from Q4 2017.
  • Operating netback of $13.47/boe, a 3% decrease from Q4 2017.
  • Total capital expenditures of $52.9 million. During the quarter, Birchcliff drilled 9 (9.0 net) wells.

2018 Reserves, F&D Costs and Recycle Ratio Highlights

  • The following table summarizes the estimates of Birchcliff’s gross reserves at December 31, 2018 and December 31, 2017, 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, 2018
(Mboe)
December 31, 2017
(Mboe)
Change from
December 31, 2017
Proved Developed Producing 203,631.0 197,955.1 3 %
Total Proved 689,674.1 664,480.5 4 %
Probable 312,396.0 308,034.8 1 %
Total Proved Plus Probable 1,002,070.1 972,515.3 3 %
  • Birchcliff added 34,229.7 Mboe of proved developed producing reserves during 2018, before including the effects of acquisitions and dispositions and adding back 2018 actual production of 28,140.0 Mboe.
  • Birchcliff added 1.2 boe of proved developed producing reserves for each boe that was produced in 2018, before including the effects of acquisitions and dispositions and adding back 2018 actual production.
  • The estimated net present value at December 31, 2018 (before taxes, discounted at 10%) was $2.3 billion for Birchcliff’s proved developed producing reserves ($1.9 billion at December 31, 2017), $4.7 billion for its proved reserves ($3.7 billion at December 31, 2017) and $6.2 billion for its proved plus probable reserves ($5.1 billion at December 31, 2017).
  • Reserves life index of 7.2 years on a proved developed producing basis, 24.5 years on a proved basis and 35.6 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 2019).
  • During 2018, Birchcliff’s F&D costs were $299.7 million and its FD&A costs were $296.0 million. The following table sets forth the estimates of Birchcliff’s F&D costs and FD&A costs per boe for 2018, 2017 and 2016, excluding and including FDC:
Excluding FDC ($/boe)(1) 2018 2017 2016 3-Year Average
F&D – Proved Developed Producing $ 8.75 $ 6.29 $ 6.42 $ 6.99
F&D – Proved $ 5.56 $ 2.53 $ 1.57 $ 2.72
F&D – Proved Plus Probable $ 5.57 $ 2.54 $ 1.25 $ 2.52
FD&A – Proved Developed Producing $ 8.75 $ 4.79 $ 9.32 $ 7.71
FD&A – Proved $ 5.55 $ 1.95 $ 3.53 $ 3.25
FD&A – Proved Plus Probable $ 5.13 $ 2.35 $ 2.33 $ 2.66
 Including FDC ($/boe)(1) 2018(2) 2017(3) 2016(4) 3-Year Average
F&D – Proved $ 0.64 $ 8.14 $ 4.89 $ 5.83
F&D – Proved Plus Probable $ 1.27 $ 7.27 $ 4.43 $ 5.27
FD&A – Proved $ 0.45 $ 7.16 $ 6.73 $ 6.06
FD&A – Proved Plus Probable $ 1.47 $ 5.37 $ 5.58 $ 5.06
(1)  Please see “Advisories – Oil and Gas Metrics” for a description of the methodology used to calculate F&D and FD&A costs.
(2)  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.
(3)  Includes 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.
(4)  Includes the 2016 increase in FDC from 2015 of $690.0 million on a proved basis and $1,059.0 million on a proved plus probable basis.
  • The following table sets forth Birchcliff’s recycle ratios for its operating and adjusted funds flow netbacks for 2018 and 2017, excluding and including FDC:
  Operating Netback
Recycle Ratio(1)(2)
Adjusted Funds Flow
Netback Recycle Ratio
(1)(3)
2018 2017 2018 2017
Excluding FDC    
F&D – Proved Developed Producing 1.5 2.2 1.3 2.0
FD&A – Proved Developed Producing 1.5 2.9 1.3 2.7
F&D – Proved 2.4 5.5 2.0 5.1
FD&A – Proved 2.4 7.2 2.0 6.6
F&D – Proved Plus Probable 2.4 5.5 2.0 5.0
FD&A – Proved Plus Probable 2.6 6.0 2.2 5.5
Including FDC(4)
F&D – Proved 21.2 1.7 17.4 1.6
FD&A – Proved 30.3 2.0 24.9 1.8
F&D – Proved Plus Probable 10.7 1.9 8.8 1.8
FD&A – Proved Plus Probable 9.2 2.6 7.6 2.4
(1)  Please see “Advisories – Oil and Gas Metrics” for a description of the methodology used to calculate recycle ratios.
(2)  Birchcliff’s operating netback was $13.52/boe in 2018, as compared to $13.97/boe in 2017.
(3)  Birchcliff’s adjusted funds flow netback was $11.12/boe in 2018, as compared to $12.81/boe in 2017.
(4)  FDC decreased from 2017 primarily due to the cancellation of the proposed Phase VII deep-cut expansion at the Corporation’s 100% owned and operated natural gas processing plant in Pouce Coupe (the “Pouce Coupe Gas Plant”).
  • Birchcliff had positive recycle ratios for its proved developed producing reserves notwithstanding that 97% of its facilities and infrastructure capital spent in 2018 and an additional $27.6 million spent on drilling and development in Q4 2018 did not result in the addition of reserves at year-end 2018.

2019 Capital Program Highlights

  • Birchcliff’s disciplined 2019 capital program (the “2019 Capital Program”) is focused on its high-value light oil assets in Gordondale and its condensate-rich assets in Pouce Coupe. Highlights of the 2019 Capital Program include the following:°  The program targets an annual average production rate of 76,000 to 78,000 boe/d which is expected to generate approximately $330 million of adjusted funds flow, based on the assumptions set forth herein(1).°  Total F&D capital expenditures are estimated to be $204 million, which are significantly less than Birchcliff’s estimated 2019 adjusted funds flow.°  The program contemplates the drilling of a total of 17 (17.0 net) wells and the bringing on production of a total of 26 (26.0 net) wells during 2019.

    °  Approximately $180 million of sustaining capital(2) is required to keep production flat, which includes all of the capital required to bring the 26 wells on production. Incremental funds will be primarily directed to increasing the inlet liquids-handling capacity at the Corporation’s Pouce Coupe Gas Plant and to other infrastructure enhancement projects for future growth.

    °  Approximately 50% of the program is directed towards Birchcliff’s Pouce Coupe area and approximately 40% is directed towards Birchcliff’s Gordondale area. Approximately 60% of the program is directed towards drilling and development.

    °  The program will direct capital investment to those projects with the most favourable rates of return. In particular, the program will focus on the drilling of Montney D1 and D2 oil wells in Gordondale and condensate-rich natural gas wells in the Montney D1, D2 and C intervals in Pouce Coupe.

1 See “Outlook and Guidance” and “Advisories – Forward-Looking Statements” for the assumptions surrounding such guidance.

2 Sustaining capital refers to capital required to offset production declines on an annual basis and maintain flat production volumes of approximately 76,000 to 78,000 boe/d. Sustaining capital does not have a standardized meaning and therefore should not be used to make comparisons to similar measures presented by other issuers.

Increase to Quarterly Common Share Dividend

  • Birchcliff’s board of directors has approved a quarterly cash dividend of $0.02625 on its common shares for the quarter ending March 31, 2019, which represents a 5% increase over the prior quarter.

This press release contains forward-looking statements within the meaning of applicable securities laws. For further information regarding the forward-looking statements contained herein, please see “Advisories – Forward-Looking Statements”. In addition, this press release contains references to “adjusted funds flow”, “adjusted funds flow per common share”, “free funds flow”, “operating netback”, “adjusted 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, 2018 is unaudited. See “Advisories – Unaudited Information”. 

2018 UNAUDITED FINANCIAL AND OPERATIONAL HIGHLIGHTS
  Three months ended
December 31,
Twelve months ended
December 31,
2018 2017 2018 2017
OPERATING
Average production
Light oil (bbls/d) 4,788 5,283 4,873 6,004
Natural gas (Mcf/d) 363,596 385,280 372,170 320,927
NGLs (bbls/d) 11,021 10,607 10,195 8,471
Total (boe/d) 76,408 80,103 77,096 67,963
Average sales price (CDN$)(1)
Light oil (per bbl) 41.39 68.58 68.66 61.42
Natural gas (per Mcf) 3.03 2.64 2.45 2.72
NGLs (per bbl) 34.73 40.08 44.66 33.39
Total (per boe) 22.01 22.54 22.08 22.44
NETBACK AND COST ($/boe)
Petroleum and natural gas revenue(1) 22.01 22.55 22.08 22.45
Royalty expense (0.96 ) (1.26 ) (1.36 ) (1.16 )
Operating expense (3.51 ) (3.86 ) (3.52 ) (4.45 )
Transportation and other expense (4.07 ) (3.52 ) (3.68 ) (2.87 )
Operating netback ($/boe) 13.47 13.91 13.52 13.97
General & administrative expense, net (1.08 ) (1.28 ) (0.87 ) (1.07 )
Interest expense (1.06 ) (0.97 ) (0.99 ) (1.14 )
Realized gain (loss) on financial instruments 0.24 1.46 (0.56 ) 1.03
Other income 0.03 0.04 0.02 0.02
Adjusted funds flow netback ($/boe) 11.60 13.16 11.12 12.81
Other compensation expense, net (0.78 ) (0.13 ) (0.27 ) (0.16 )
Depletion and depreciation expense (7.29 ) (7.86 ) (7.42 ) (7.48 )
Accretion expense (0.12 ) (0.08 ) (0.11 ) (0.12 )
Amortization of deferred financing fees (0.05 ) (0.05 ) (0.05 ) (0.06 )
Gain (loss) on sale of assets (0.26 ) 1.86 (0.36 ) (7.50 )
Unrealized gain (loss) on financial instruments 11.02 (1.86 ) 2.28 0.22
Dividends on Series C preferred shares (0.12 ) (0.12 ) (0.12 ) (0.14 )
Income tax recovery (expense) (3.77 ) (1.42 ) (1.44 ) 0.54
Net income (loss) ($/boe) 10.23 3.50 3.63 (1.89 )
Dividends on Series A preferred shares (0.14 ) (0.14 ) (0.15 ) (0.17 )
Net income (loss) to common shareholders ($/boe) 10.09 3.36 3.48 (2.06 )
FINANCIAL
Petroleum and natural gas revenue ($000s)(1) 154,720 166,149 621,421 556,942
Cash flow from operating activities ($000s) 92,200 88,995 324,434 287,660
Adjusted funds flow ($000s) 81,517 97,008 312,922 317,680
Per common share – basic ($) 0.31 0.36 1.18 1.20
Per common share – diluted ($) 0.30 0.36 1.17 1.19
Net income (loss) ($000s) 71,947 25,820 102,212 (46,980 )
Net income (loss) to common shareholders ($000s) 70,900 24,773 98,025 (51,027 )
Per common share – basic ($) 0.27 0.09 0.37 (0.19 )
Per common share – diluted ($) 0.27 0.09 0.37 (0.19 )
Common shares outstanding (000s)
End of period – basic 265,911 265,797 265,911 265,797
End of period – diluted 284,699 282,895 284,699 282,895
Weighted average common shares for period – basic 265,910 265,792 265,852 265,182
Weighted average common shares for period – diluted 267,288 267,619 267,323 267,873
Dividends on common shares ($000s) 6,648 6,644 26,586 26,522
Dividends on Series A preferred shares ($000s) 1,047 1,047 4,187 4,047
Dividends on Series C preferred shares ($000s) 875 875 3,500 3,500
Total capital expenditures ($000s)(2) 52,886 18,669 298,018 276,125
Long-term debt ($000s) 605,267 587,126 605,267 587,126
Adjusted working capital deficit ($000s) 21,187 11,067 21,187 11,067
Total debt ($000s) 626,454 598,193 626,454 598,193
(1) Excludes the effects of hedges using financial instruments but includes the effects of fixed price physical delivery contracts.
(2) See “Advisories – Capital Expenditures” in this press release.

FULL-YEAR 2018 UNAUDITED FINANCIAL AND OPERATIONAL RESULTS

FINANCIAL RESULTS

Adjusted Funds Flow

Birchcliff’s adjusted funds flow for 2018 was $312.9 million, or $1.18 per basic common share, a 1% decrease and a 2% decrease, respectively, from $317.7 million and $1.20 per basic common share in 2017. The decreases were primarily due to a realized loss on financial instruments in 2018 as compared to a realized gain on financial instruments in 2017, as well as an increase in transportation and other expense as a result of the Corporation increasing its Dawn and AECO firm service. These increases were largely offset by significantly higher revenues received by the Corporation due to higher natural gas and NGLs production, notwithstanding the decrease in oil production as a result of the disposition of the Corporation’s assets in the Worsley area in Q3 2017.

Net Income to Common Shareholders

Birchcliff recorded net income to common shareholders of $98.0 million, or $0.37 per basic common share, in 2018 as compared to the net loss to common shareholders of $51.0 million and $0.19 per basic common share in 2017. The change from a net loss to a net income position was primarily due to a $64.2 million unrealized mark-to-market gain on financial instruments recorded in 2018 and a $132.3 million after-tax loss from the sale of the Worsley assets in Q3 2017, partially offset by higher depletion and income tax expenses.

Operating Expense

During 2018, the Corporation was focused on reducing its operating costs, including at Gordondale where it entered into a new long-term natural gas processing arrangement effective January 1, 2018 (the “Gordondale Processing Arrangement”) which significantly reduced its processing fees at AltaGas’ deep-cut sour gas processing facility (the “Gordondale Gas Plant”). Birchcliff’s operating expense in 2018 was $3.52/boe, a 21% decrease from $4.45/boe in 2017, and was in line with Birchcliff’s guidance of $3.40/boe to $3.60/boe. The decrease was primarily due to an incremental increase in natural gas production processed at the Pouce Coupe Gas Plant and the reduced processing fees at the Gordondale Gas Plant, as well as the disposition of the Corporation’s higher-cost Worsley assets in Q3 2017.

Transportation and Other Expense

Birchcliff’s transportation and other expense was $3.68/boe in 2018, a 28% increase from $2.87/boe in 2017, and was 3% lower than the low end of Birchcliff’s guidance of $3.80/boe to $4.10/boe. The increase was primarily due to the firm service transportation tolls for natural gas transported to Dawn which commenced on November 1, 2017 and new unused firm transportation costs associated with Birchcliff’s commitments on the NGTL system.

G&A Expense

Birchcliff’s G&A expense was $0.87/boe in 2018, a 19% decrease from $1.07/boe in 2017. The decrease was primarily due to higher corporate production, with no increase in aggregate G&A expense.

Interest Expense

Birchcliff’s interest expense was $0.99/boe in 2018, a 13% decrease from $1.14/boe in 2017. The decrease was primarily due to higher corporate production and a lower average effective interest rate on Birchcliff’s credit facilities, partially offset by a higher average outstanding credit facilities balance.

Total Cash Costs

Birchcliff’s total cash costs were $10.42/boe in 2018, a 3% decrease from $10.69/boe in 2017. The decrease was primarily due to lower per boe operating, G&A and interest expenses, partially offset by higher per boe royalty and transportation and other expenses.

Netbacks

Birchcliff’s operating netback was $13.52/boe in 2018, a 3% decrease from $13.97/boe in 2017. The decrease was primarily due to a lower corporate average realized commodity sales price and higher per boe royalty and transportation and other expenses, partially offset by lower per boe operating expense. 

Birchcliff’s adjusted funds flow netback was $11.12/boe in 2018, a 13% decrease from $12.81/boe in 2017. The decrease was primarily due to a lower operating netback and a realized loss on financial instruments, partially offset by lower per boe G&A and interest expenses.

Pouce Coupe Gas Plant Netbacks

During 2018, Birchcliff processed approximately 67% of its total corporate natural gas production and 57% of its total corporate production through the Pouce Coupe Gas Plant as compared to 60% and 49%, respectively, during 2017. These increases were primarily due to the incremental production from horizontal natural gas wells brought on production in Pouce Coupe. The average plant and field operating expense for production processed through the Pouce Coupe Gas Plant in 2018 was $0.34/Mcfe ($2.02/boe) and the operating netback at the Pouce Coupe Gas Plant was $2.04/Mcfe ($12.24/boe), resulting in an operating margin of 68% in 2018.

During 2018, Birchcliff specifically targeted condensate-rich natural gas wells in Pouce Coupe. This materially increased the amount of condensate being produced at the Pouce Coupe Gas Plant to 2,431 bbls/d from 1,292 bbls/d, an 88% increase from 2017. This resulted in a 53% increase in the liquids-to-gas ratio as compared to 2017 from 6.8 bbls/MMcf to 10.4 bbls/MMcf.

This increased condensate volume has led Birchcliff to commit to the construction of a 20,000 bbls/d inlet liquids-handling facility at its Pouce Coupe Gas Plant which is anticipated to be online in Q3 2020. See “2019 Capital Program”.

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:

  2018 2017
Average production:
Natural gas (Mcf/d) 250,011 193,417
NGLs (bbls/d)(1) 2,609 1,316
Total (boe/d) 44,278 33,552
Liquids(1)-to-gas ratio (bbls/MMcf)   10.4   6.8
Netback and cost: $/Mcfe
$/boe
$/Mcfe
$/boe
Petroleum and natural gas revenue(2) 3.02 18.11 3.04 18.24
Royalty expense (0.05 ) (0.29 ) (0.07 ) (0.44 )
Operating expense(3) (0.34 ) (2.02 ) (0.34 ) (2.07 )
Transportation and other expense(4) (0.59 ) (3.56 ) (0.44 ) (2.61 )
Operating netback $ 2.04 $ 12.24 $ 2.19 $ 13.12
Operating margin 68 % 68 % 72 % 72 %
(1)  Primarily condensate.
(2)  Excludes the effects of hedges using financial instruments but includes the effects of fixed price physical delivery contracts. See “Risk Management”.
(3)  Represents plant and field operating expense.
(4)  The increase in transportation and other expense from 2017 was primarily due to transportation tolls for natural gas sold at the Dawn price during 2018. Birchcliff began selling natural gas at the Dawn price on November 1, 2017.

Debt

At December 31, 2018, Birchcliff had significant liquidity with long-term bank debt of $605.3 million (December 31, 2017: $587.1 million) from available credit facilities of $950 million (December 31, 2017: $950 million), leaving $324.0 million of unutilized credit capacity after adjusting for outstanding letters of credit and unamortized interest and fees. Total debt at December 31, 2018 was $626.5 million as compared to $598.2 million at December 31, 2017. Birchcliff’s credit facilities do not contain any financial maintenance covenants and do not mature until May 11, 2021.

Commodity Prices

The following table sets forth the average benchmark index prices and Birchcliff’s average realized sales prices for the periods indicated:

  2018 2017
Average benchmark index prices:
Light oil – WTI Cushing (US$/bbl) 64.77 50.95
Light oil – WTI Cushing (CDN$/bbl) 83.89 66.11
Light oil – MSW (Mixed Sweet) Edmonton (CDN$/bbl)(1) 69.04 62.52
Natural gas – NYMEX HH (US$/MMBtu)(2) 3.07 3.02
Natural gas – AECO 5A (CDN$/GJ) 1.42 2.04
Natural gas – AECO 5A (US$/MMBtu)(2) 1.16 1.66
Natural gas – Dawn Day Ahead (CDN$/GJ) 3.84 3.74
Natural gas – Dawn Day Ahead (US$/MMBtu)(2) 3.12 3.04
Natural gas – ATP 5A Day Ahead (CDN$/GJ) 2.07 2.02
Natural gas – Chicago City Gate (US$/MMBtu)(2) 3.02 2.90
Exchange rate (CDN$ to US$1) 1.2961 1.2979
Birchcliff’s average realized sales prices:(3)
Light oil ($/bbl) 68.66 61.42
Natural gas ($/Mcf) 2.45 2.72
NGLs ($/bbl) 44.66 33.39
Birchcliff’s average realized sales price ($/boe) 22.08 22.44
(1)  Previously referred to as the “Edmonton Par price”.
(2)  $1.00/MMBtu = $1.00/Mcf based on a standard heat value Mcf. Please see “Advisories – MMBtu Pricing Conversions”.
(3)  Excludes the effects of hedges using financial instruments but includes the effects of fixed price physical delivery contracts.

Natural Gas Market Diversification

Birchcliff actively looks for profitable opportunities to diversify its natural gas markets and reduce its exposure to prices at AECO. Birchcliff has agreements for the firm service transportation of an aggregate of 175,000 GJ/d of natural gas on TCPL’s Canadian Mainline for a 10-year term, 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 and the second tranche (30,000 GJ/d) became available on November 1, 2018. The last tranche of service (25,000 GJ/d) will become available on November 1, 2019. In addition, Birchcliff has also entered into various risk management contracts to sell its natural gas at prices based on the Dawn and NYMEX HH prices as discussed in further detail below under “Risk Management”.

The following table sets forth Birchcliff’s natural gas sales, average daily production and average realized sales price by natural gas market for the three and twelve months ended December 31, 2018:

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)
($/Mcf)
Natural gas
transportation
costs
(3)
($/Mcf)
Natural gas
sales
netback

($/Mcf)
AECO 33,788 33 223,261 61 1.67 0.31 1.36
Dawn(2) 64,969 64 127,211 35 5.55 1.34 4.21
Alliance 2,492 3 13,124 4 2.06 (4) 2.06
Total 101,249 100 363,596 100 3.03 0.66 2.37
Twelve 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)
($/Mcf)
Natural gas
transportation
costs
(3)
($/Mcf)
Naturalgas
sales
netback

($/Mcf)
AECO 132,342 40 229,225 61 1.59 0.29 1.30
Dawn(2) 182,385 55 114,110 31 4.38 1.33 3.05
Alliance 18,252 5 28,835 8 1.73 (4) 1.73
Total 332,979 100 372,170 100 2.45 0.58 1.87
(1)  Excludes the effects of hedges using financial instruments.
(2)  During Q4 2018, Birchcliff entered into physical delivery sales 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.
(3)  Reflects the average realized natural gas wellhead price after adjusting for fuel to transport natural gas from the field receipt point to the delivery sales trading hub.
(4)  Alliance transportation tolls are recorded net of sales price.

For information regarding Birchcliff’s natural gas market exposure during 2019, see “Outlook and Guidance”.

RISK MANAGEMENT

Birchcliff maintains an ongoing hedging program and engages in various risk management activities to reduce its exposure to volatility in commodity prices. During 2018, Birchcliff realized a cash loss on financial commodity price risk management contracts of $15.8 million as compared to a realized cash gain of $25.8 million in 2017. The realized loss in 2018 was due to the settlement of WTI fixed price financial contracts with an average contract price that was below the average benchmark commodity index price in that period. This loss was offset by a realized gain of $4.0 million recorded in Q4 2018 due to the monetization of Birchcliff’s outstanding 2019 WTI fixed price financial contracts.

As at December 31, 2018, Birchcliff had the following risk management contracts in place:

Product Type of Contract Notional Quantity Term(1) Contract Price
Financial Derivative Contracts – Sell
Natural gas AECO 7A basis swap 30,000 MMBtu/d Jan. 1, 2019 – Dec. 31, 2023 NYMEX HH less US$1.298/MMBtu
Natural gas AECO 7A basis swap 10,000 MMBtu/d Jan. 1, 2019 – Dec. 31, 2023 NYMEX HH less US$1.32/MMBtu
Natural gas AECO 7A basis swap 30,000 MMBtu/d Jan. 1, 2019 – Dec. 31, 2023 NYMEX HH less US$1.33/MMBtu
Natural gas AECO 7A basis swap 15,000 MMBtu/d Jan. 1, 2019 – Dec. 31, 2024 NYMEX HH less US$1.185/MMBtu
Natural gas AECO 7A basis swap 5,000 MMBtu/d Jan. 1, 2019 – Dec. 31, 2024 NYMEX HH less US$1.20/MMBtu
Natural gas AECO 7A basis swap 5,000 MMBtu/d Jan. 1, 2019 – Dec. 31, 2024 NYMEX HH less US$1.20/MMBtu
Financial Derivative Contracts – Buy
Natural gas AECO 7A basis swap 10,000 MMBtu/d Jan. 1, 2019 – Mar. 31, 2019 NYMEX HH less US$3.10/MMBtu
Natural gas AECO 7A basis swap 10,000 MMBtu/d Jan. 1, 2019 – Mar. 31, 2019 NYMEX HH less US$3.15/MMBtu
Natural gas AECO 7A basis swap 30,000 MMBtu/d Jan. 1, 2019 – Mar. 31, 2019 NYMEX HH less US$3.16/MMBtu
Physical Delivery Sales Contracts – Sell
Natural gas AECO 7A basis swap 5,000 MMBtu/d Jan. 1, 2019 – Dec. 31, 2023 NYMEX HH less US$1.205/MMBtu
Natural gas Dawn fixed price(2) 5,000 MMBtu/d Jan. 1, 2019 – Mar. 31, 2019 US$5.100/MMBtu
Natural gas Dawn fixed price(2) 10,000 MMBtu/d Jan. 1, 2019 – Mar. 31, 2019 US$5.000/MMBtu
Natural gas Dawn fixed price(2) 10,000 MMBtu/d Jan. 1, 2019 – Mar. 31, 2019 US$5.005/MMBtu
Natural gas Dawn fixed price(2) 10,000 MMBtu/d Jan. 1, 2019 – Mar. 31, 2019 US$5.020/MMBtu
Natural gas Dawn fixed price(2) 15,000 MMBtu/d Jan. 1, 2019 – Mar. 31, 2019 US$5.103/MMBtu
(1) Transactions with common terms and the same counterparty have been aggregated and presented at the weighted average price.
(2) Birchcliff entered into a 4-month fixed price physical natural gas Dawn sales arrangement commencing December 1, 2018.

Birchcliff recorded a $64.2 million unrealized mark-to-market gain on financial commodity price risk management contracts in 2018 as compared to a $5.4 million unrealized gain in 2017. The unrealized gain in 2018 was due to an increase in the fair value of Birchcliff’s financial contracts to an asset position of $60.2 million at December 31, 2018, as compared to a liability position of $4.0 million at December 31, 2017. The increase in the fair value of Birchcliff’s financial contracts was primarily attributable to the addition of the multi-year AECO/NYMEX basis swap contracts entered into during 2018 and the settlement of all of the financial risk management contracts still active at the end of 2017 in 2018. Any changes in the forward commodity price assumptions period-over-period will also be reflected in the unrealized gain or loss. The fair value of the asset or liability is the estimated value to settle the outstanding contracts at a point in time. As such, unrealized financial gains or losses do not impact adjusted funds flow and the actual gains or losses realized on eventual cash settlement can vary materially due to subsequent fluctuations in commodity prices as compared to the valuation assumptions.

Subsequent to year-end, Birchcliff entered into additional financial AECO 7A basis swaps for: (i) 45,000 MMBtu/d at an average contract price of NYMEX HH less US$1.128/MMBtu for the period from January 1, 2024 to December 31, 2025; and (ii) 20,000 MMBtu/d at an average contract price of NYMEX HH less US$1.179/MMBtu for the period from January 1, 2021 to December 31, 2025.

The settlement of financial and physical commodity risk management contracts outstanding as at February 13, 2019 has been included in Birchcliff’s forecast of adjusted funds flow for 2019. See “Outlook and Guidance” in this press release.

OPERATIONAL RESULTS

Production

Birchcliff’s production averaged 77,096 boe/d in 2018, a 13% increase from 67,963 boe/d in 2017, and was in line with its guidance of 76,000 to 78,000 boe/d. The increase was primarily attributable to the success of Birchcliff’s capital programs which resulted in incremental production from new horizontal wells brought on production in Gordondale and Pouce Coupe, partially offset by temporary restrictions in pipeline and compressor station capacity on the Alberta NGTL system and natural production declines.

Production consisted of approximately 80% natural gas, 6% light oil and 14% NGLs in 2018, as compared to 79% natural gas, 9% light oil and 12% NGLs in 2017, and was in line with Birchcliff’s guidance of 80% natural gas and 20% oil and NGLs.

Capital Activities and Investment

Birchcliff’s successful 2018 capital program (the “2018 Capital Program”) was focused on the drilling of crude oil wells in Gordondale and a combination of liquids-rich and low-cost natural gas wells in Pouce Coupe, as well as the completion of strategic infrastructure to provide for future growth. The 2018 Capital Program was strategically front-end loaded and highly focused on the first half of 2018, which allowed Birchcliff to bring new wells on production relatively early in the year in order to optimize producing days for the capital spent in 2018.

During 2018, Birchcliff drilled, completed and brought on production 27 (27.0 net) wells, 100% of which were successful. In Q4 2018, Birchcliff drilled an additional 9 (9.0 net) horizontal wells (5 in Pouce Coupe and 4 in Gordondale) which were originally targeted for 2019 in order to help to ensure the efficient execution of the 2019 Capital Program. All wells drilled in 2018 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, completed and brought on production in 2018:

Area Total wells drilled in 2018(1) Total wells drilled, completed and
brought on production in 2018
(2)
Pouce Coupe
Montney D1 horizontal natural gas wells 17 12
Montney D2 horizontal natural gas wells 1 1
Montney C horizontal natural gas wells 1 1
Total – Pouce Coupe
19 14
Gordondale
Montney D2 horizontal oil wells 10 8
Montney D1 horizontal oil wells 7 5
Total – Gordondale 17 13
TOTAL – COMBINED 36 27
(1) Includes the 9 additional wells drilled in Q4 2018.
(2) Does not include the 9 additional wells drilled in Q4 2018 as none of these wells were completed or brought on production in 2018. In addition, the 2018 Capital Program included the capital associated with 1 Montney/Doig well in Pouce Coupe that was drilled in December 2017 and subsequently completed and brought on production in 2018. Accordingly, a total of 28 (28.0 net) wells were brought on production in 2018.

Total capital expenditures for 2018 were $298.0 million, including drilling and development expenditures of $183.2 million and facilities and infrastructure expenditures of $70.2 million, as compared to Birchcliff’s guidance of $288.0 million, $179.0 million and $70.8 million, respectively.

Gordondale

During 2018, the Corporation was focused on the drilling of crude oil wells and the delineation of the Montney D1 and D2 intervals in Gordondale. Birchcliff drilled 17 (17.0 net) horizontal wells and brought 13 (13.0 net) wells on production in Gordondale in 2018.

Since Birchcliff acquired its assets in Gordondale in 2016, it has drilled 40 (40.0 net) wells in the area, consisting of 22 (22.0 net) Montney D2 horizontal oil wells, 13 (13.0 net) Montney D1 horizontal oil wells, 4 (4.0 net) Montney D1 liquids-rich horizontal natural gas wells and 1 (1.0 net) water disposal well. When Birchcliff first acquired its assets in Gordondale, the average production for such assets was approximately 22,000 boe/d at the date of the acquisition. The horizontal wells that Birchcliff has subsequently drilled and brought on production have replaced the natural production declines and significantly increased the production on its Gordondale assets (currently approximately 28,000 boe/d). The Montney D2 horizontal wells that Birchcliff has drilled, completed and brought on production to-date have significantly delineated, de-risked and proven the commerciality of the Montney D2 play.

Pouce Coupe

During 2018, Birchcliff was focused on the drilling of liquids-rich natural gas wells and the pursuit of condensate and other NGLs in several different Montney/Doig intervals, including the Montney D1, D2 and C. Birchcliff drilled 19 (19.0 net) horizontal wells and brought 15 (15.0 net) wells on production in Pouce Coupe in 2018.

Another focus for Birchcliff in 2018 was the completion of strategic infrastructure to allow for future growth. In Q3 2018, the 80 MMcf/d Phase VI expansion of Birchcliff’s Pouce Coupe Gas Plant was brought on-stream, which increased the total processing capacity of the plant to 340 MMcf/d from 260 MMcf/d. In Q4 2018, Birchcliff completed the re-configuration of Phases V and VI to provide for shallow-cut capability. This shallow-cut capability allows Birchcliff to extract propane plus (C3+) from the natural gas stream, further enhancing Birchcliff’s ability to maximize its liquids production.

As part of Birchcliff’s commitment to continuous performance improvement, it designed and executed on its science and technology pad in 2018, which involved the drilling of one vertical well and four horizontal wells in three different intervals (one Montney C, one Montney D2 and two Montney D1 wells). Using the pad, Birchcliff has been able to acquire high-quality subsurface and operational data and thus gain important insights into reservoir behaviour, including fracture initiation and propagation, inter-well fracture communication, well productivity by cluster, the role of natural fractures on production and optimal well spacing by and between zones. Birchcliff has also been able to increase its knowledge regarding field development, including well landing depths, well spacing both laterally and vertically and completion, cluster and stage spacing. In addition, a permanent fibre optic cable installed in one of the horizontal wells allows Birchcliff to observe how wells interact in the subsurface over time. Ultimately, the knowledge gained from the science and technology pad has helped Birchcliff to improve and refine its best practices at the well, pad and field levels in order to optimize field development.

Potential Future Drilling Opportunities on the Montney/Doig Resource Play

As at December 31, 2018, Birchcliff held 367.4 sections of land that have potential for the Montney/Doig Resource Play. Of these lands, 362.4 (340.3 net) sections have potential for the Basal Doig/Upper Montney interval, 343.9 (336.2 net) sections have potential for the Montney D1 interval, 345.4 (337.7 net) sections have potential for the Montney D2 interval, 343.9 (336.2 net) sections have potential for the Montney D4 interval and 343.9 (336.2 net) sections have potential for the Montney C interval. As at December 31, 2018, Birchcliff’s total land holdings on these five intervals were 1,739.5 (1,686.6 net) sections. Assuming full development of four horizontal wells per section per drilling interval, Birchcliff has 6,746.4 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, 2018. With 385.0 (380.6 net) horizontal locations drilled at the end of 2018, there remains 6,365.8(3) potential net future horizontal drilling locations as at December 31, 2018, up from 4,710.0 at year-end 2017. This increase is largely due to the exploration and delineation success of the Montney C interval as such interval is now considered commercial by Birchcliff.

Birchcliff’s consolidated reserves report effective December 31, 2018 attributed proved reserves to 888.8 net existing wells and potential net future horizontal drilling locations (of which 521.6 net wells are potential future drilling locations) and proved plus probable reserves to 1,121.8 net existing wells and potential net future horizontal drilling locations (of which 754.3 net wells are potential future drilling locations). The remaining 5,624.6 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. Please see “2018 Year-End Reserves” and “Advisories – Drilling Locations”.

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

Acquisitions and Dispositions

During 2018, Birchcliff completed various non-core asset sales for total proceeds of approximately $5.0 million and completed various minor acquisitions for total consideration of approximately $1.5 million.

On November 14, 2018, Birchcliff announced that it had entered into a definitive purchase and sale agreement to acquire 18 gross (15.1 net) contiguous sections of Montney land located between the Corporation’s existing Pouce Coupe and Gordondale properties, as well as various other non-Montney lands and other assets, for total cash consideration of $39 million (the “Acquisition”). Closing of the Acquisition occurred on January 3, 2019 and further consolidated Birchcliff’s land position in the area. Birchcliff recently commenced the drilling of a 6-well pad on these lands which is targeting condensate-rich natural gas wells. See “2019 Capital Program”.

Q4 2018 UNAUDITED FINANCIAL AND OPERATIONAL RESULTS

FINANCIAL RESULTS

Adjusted Funds Flow

Birchcliff’s adjusted funds flow for Q4 2018 was $81.5 million, or $0.31 per basic common share, a 16% decrease and a 14% decrease, respectively, from $97.0 million and $0.36 per basic common share in Q4 2017. The decreases were primarily due to lower corporate production, lower average realized oil and NGLs sales prices, higher interest and transportation and other expenses and lower realized gains on financial instruments, partially offset by a higher average realized natural gas sales price.

Net Income to Common Shareholders

Birchcliff recorded net income to common shareholders of $70.9 million, or $0.27 per basic common share, in Q4 2018, a 186% increase and a 200% increase, respectively, from $24.8 million and $0.09 per basic common share in Q4 2017. The increases were primarily due to a $77.5 million unrealized mark-to-market gain on financial instruments, partially offset by lower adjusted funds flow and higher income tax expenses.

Operating Expense

Birchcliff’s operating expense was $3.51/boe in Q4 2018, a 9% decrease from $3.86/boe in Q4 2017. The decrease was primarily due to an incremental increase in natural gas production processed at the Pouce Coupe Gas Plant and the reduced processing fees at the Gordondale Gas Plant.

Transportation and Other Expense

Birchcliff’s transportation and other expense was $4.07/boe in Q4 2018, a 16% increase from $3.52/boe in Q4 2017. The increase was primarily due to higher firm service transportation tolls for natural gas transported to Dawn in Q4 2018 and new unused firm transportation costs associated with Birchcliff’s commitments on the NGTL system. Effective November 1, 2018, Birchcliff increased its natural gas transported to Dawn from 120,000 GJ/d to 150,000 GJ/d.

G&A Expense

Birchcliff’s G&A expense was $1.08/boe in Q4 2018, a 16% decrease from $1.28/boe Q4 2017. The decrease was primarily due to lower corporate production.

Interest Expense

Birchcliff’s interest expense was $1.06/boe in Q4 2018, a 9% increase from $0.97/boe in Q4 2017. The increase was primarily due to a higher average outstanding credit facilities balance, partially offset by a lower average effective interest rate on Birchcliff’s credit facilities and lower corporate production.

Total Cash Costs

Birchcliff’s total cash costs were $10.68/boe in Q4 2018, a 2% decrease from $10.89/boe in Q4 2017. The decrease was primarily due to lower per boe operating and G&A expenses, partially offset by higher per boe royalty, interest and transportation and other expenses.

Netbacks

Birchcliff’s operating netback was $13.47/boe in Q4 2018, a 3% decrease from $13.91/boe in Q4 2017. The decrease was primarily due to a lower corporate average realized commodity sales price and higher per boe transportation and other expense, partially offset by lower per boe operating and royalty expenses.

Birchcliff’s adjusted funds flow netback was $11.60/boe in Q4 2018, a 12% decrease from $13.16/boe in Q4 2017. The decrease was primarily due to a lower operating netback and realized gains on financial instruments, partially offset by a decrease in per boe G&A and interest expenses.

OPERATIONAL RESULTS

Production

Birchcliff’s production averaged 76,408 boe/d in Q4 2018, a 5% decrease from 80,103 boe/d in Q4 2017. The decrease was primarily due to temporary restrictions in pipeline and compressor station capacity on the Alberta NGTL system and natural production declines, partially offset by incremental production from new horizontal wells brought on production in Gordondale and Pouce Coupe.

Production consisted of approximately 79% natural gas, 6% light oil and 15% NGLs in Q4 2018, as compared to 80% natural gas, 7% light oil and 13% NGLs in Q4 2017.

Capital Activities and Investment

Birchcliff drilled 9 (9.0 net) horizontal wells in Q4 2018, consisting of 5 (5.0 net) horizontal natural gas wells in Pouce Coupe (all of which were Montney D1 wells) and 4 (4.0 net) horizontal oil wells in Gordondale (2 Montney D2 wells and 2 Montney D1 wells). Total capital expenditures were $52.9 million in Q4 2018.

2019 CAPITAL PROGRAM

Overview and Highlights

Birchcliff’s disciplined 2019 Capital Program is focused on its high-value light oil assets in Gordondale and its condensate-rich assets in Pouce Coupe. The key highlights of the 2019 Capital Program are as follows:

  • The program targets an annual average production rate of 76,000 to 78,000 boe/d which is expected to generate approximately $330 million of adjusted funds flow, based on the assumptions set forth herein(4).
  • Total F&D capital expenditures are estimated to be $204 million, which are significantly less than Birchcliff’s estimated 2019 adjusted funds flow.
  • The program contemplates the drilling of a total of 17 (17.0 net) wells and the bringing on production of a total of 26 (26.0 net) wells during 2019.
  • Approximately $180 million of sustaining capital is required to keep production flat, which includes all of the capital required to bring the 26 wells on production. Incremental funds will be primarily directed to increasing the inlet liquids-handling capacity at the Pouce Coupe Gas Plant and to other infrastructure enhancement projects for future growth.
  • Approximately 50% of the program is directed towards Birchcliff’s Pouce Coupe area and approximately 40% is directed towards Birchcliff’s Gordondale area. Approximately 60% of the program is directed towards drilling and development.
  • The program will direct capital investment to those projects with the most favourable rates of return. In particular, the program will focus on the drilling of Montney D1 and D2 oil wells in Gordondale and condensate-rich natural gas wells in the Montney D1, D2 and C intervals in Pouce Coupe.
  • Given the available capacity at the Pouce Coupe Gas Plant, Birchcliff has the ability to expand its drilling program and increase its natural gas production. The program has been designed with financial and operational flexibility such that Birchcliff has the ability to expand its drilling program should commodity prices and/or economic conditions improve during the year.

4 See “Outlook and Guidance” and “Advisories – Forward-Looking Statements” for the assumptions surrounding such guidance.

The following tables set forth details regarding Birchcliff’s expected capital spending allocation and the number and types of wells expected to be drilled and brought on production in 2019:

2019 Capital Program – Capital Expenditures by Classification
Classification  Gross Wells Net Wells Capital
(MM)
Drilling and Development
Pouce Coupe(1)(2)
Montney D1 horizontal natural gas wells 6 6.0 $ 34.8
Montney D2 horizontal natural gas wells 2 2.0 $ 11.4
Montney C horizontal natural gas wells 1 1.0 $ 6.2
Gordondale(1)(2)
Montney D2 horizontal oil wells 5 5.0 $ 27.4
Montney D1 horizontal oil wells 3 3.0 $ 16.2
Additional Well Completions Capital(3) $ 26.2
Total Drilling and Development 17 17.0 $ 122.2
Facilities and Infrastructure(4) $ 33.9
Maintenance and Optimization $ 22.8
Land and Seismic(5) $ 8.4
Other $ 16.7
TOTAL(6)     $ 204.0
(1)  On a DCCET basis, the average well cost in 2019 is estimated to be $5.7 million for Pouce Coupe and $5.8 million for Gordondale. These costs can vary depending on factors such as the size of the associated multi-well pads, the costs of construction, the existence of pipelines and other infrastructure and the distance to existing or planned pipelines and other infrastructure.
(2)  On a DCCET basis.
(3)  Represents the estimated completion, equipping and tie-in costs associated with the 9 (9.0 net) wells that were drilled and rig released in Q4 2018.
(4)  Includes capital for increasing the liquids-handling capacity at the Pouce Coupe Gas Plant and other infrastructure enhancement projects, pipeline twinning and replacements and water storage.
(5)  Includes capital for crown sales and rental payments but does not include other property acquisitions and dispositions.
(6)  The estimate of capital set forth in the table above does not take into account the purchase price for the Acquisition. After taking into account the purchase price for the Acquisition, Birchcliff’s estimate of total capital expenditures in 2019 is $245 million. See “Outlook and Guidance”. Net property acquisitions and dispositions have not been included in the table above as these amounts are generally unbudgeted. Birchcliff makes acquisitions and dispositions in the ordinary course of business and any acquisitions and dispositions completed during 2019 could have an impact on Birchcliff’s capital expenditures, production, adjusted funds flow, costs and total debt, which impact could be material. See “Advisories – Capital Expenditures”.

 

2019 Capital Program – Wells to be Drilled and Brought on Production
Area  Total wells to be drilled in 2019(1) Total wells to be brought on
production in 2019
(2)
Pouce Coupe
Montney D1 horizontal natural gas wells 6 11
Montney D2 horizontal natural gas wells 2 2
Montney C horizontal natural gas wells 1 1
Total – Pouce Coupe
9 14
 
Gordondale
Montney D2 horizontal oil wells 5 7
Montney D1 horizontal oil wells 3 5
Total – Gordondale 8 12
TOTAL – COMBINED 17 26
(1) On a DCCET basis.
(2) Includes the 9 (9.0) wells that were drilled and rig released in Q4 2018.

Information regarding the 2019 Capital Program constitutes forward-looking statements and information. For further information, please see “Outlook and Guidance” and “Advisories – Forward-Looking Statements”.

Gordondale

Birchcliff plans to invest approximately $84 million in Gordondale during 2019. Key focus areas for Gordondale in 2019 will be 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 plans to drill 8 (8.0 net) horizontal oil wells, consisting of 5 (5.0 net) Montney D2 wells and 3 (3.0 net) Montney D1 wells, all of which will be drilled on multi-well pads.

Pouce Coupe

Birchcliff plans to invest approximately $100 million in Pouce Coupe during 2019. Key focus areas for Pouce Coupe in 2019 will be 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 addition, due to increased condensate volumes from Pouce Coupe, Birchcliff has committed to the construction of a 20,000 bbls/d inlet liquids-handling facility at its Pouce Coupe Gas Plant. This facility is anticipated to be online in Q3 2020 and will give Birchcliff the ability to grow its condensate production from 3,000 to 10,000 bbls/d in Pouce Coupe. Birchcliff plans on spending approximately $9.5 million on the associated engineering and long-lead equipment for this facility in 2019.

Birchcliff plans to drill 9 (9.0 net) condensate-rich horizontal natural gas wells, consisting of 6 (6.0 net) Montney D1 wells, 2 (2.0 net) Montney D2 wells and 1 (1.0 net) Montney C well, all of which will be drilled on multi-well pads. This includes a 6 well pad on the lands that Birchcliff recently acquired pursuant to the Acquisition. Birchcliff believes that the acquired lands are located on a significant condensate-rich trend and are highly prospective in the Montney D1, D2, C and Basal Doig/Upper Montney intervals. The lands are strategically located near Birchcliff’s science and technology pad in Pouce Coupe where Birchcliff drilled four successful wells in 2018 (two in the Montney D1, one in the Montney D2 and one in the Montney C intervals).

Activities Year-to-Date

Birchcliff currently has three drilling rigs at work, with one rig in the Gordondale area and two in the Pouce Coupe area. Year-to-date, Birchcliff has drilled 5 (5.0 net) wells, consisting of 2 (2.0 net) Montney horizontal oil wells in the Gordondale area and 3 (3.0 net) Montney/Doig horizontal natural gas wells in the Pouce Coupe area. All of these wells were drilled on multi-well pads and none have been completed yet. With respect to the 9 wells Birchcliff drilled in Q4 2018, 3 of these wells were recently brought on production on the condensate-rich trend in Pouce Coupe. Birchcliff expects that the remaining 6 wells will be completed later this quarter and brought on production in early Q2 2019.

With 12 (12.0 net) wells left to drill under the 2019 Capital Program, Birchcliff expects to reduce the drilling rigs being utilized after break-up. Birchcliff anticipates that all 17 (17.0 net) wells to be drilled in 2019 will be brought on production by the end of Q3 2019.

Birchcliff is focused on continuous improvements in all aspects of its business. In 2019, Birchcliff will continue to pilot innovative technologies in its completions operations in order to achieve better well results, including zipper fracturing, plug and perf technology as well as fluid additives to enhance its condensate production and recoveries. Birchcliff’s operations team is focused on maximizing fracture pumping time through surface manifolds, which allows for a quick change over from well to well on multi-well pads and on utilizing new smart coil tubing units for wellbore milling operations post fracture treatment. Regarding drilling in 2019, Birchcliff has modified its drill bit, drilling mud and downhole motor selection to reduce drill times and has trialled the use of rotary steerable technology for smoother well trajectories. Birchcliff continues to utilize compressed natural gas in 2019 to displace diesel from its operations for both drilling and completions, which has helped to reduce costs and lessen Birchcliff’s environmental footprint. Several of these initiatives are a result of the important insights that Birchcliff has been able to gain from the science and technology pad it completed in 2018. See “Full-Year 2018 Unaudited Financial and Operational Results – Capital Activities and Investment – Pouce Coupe”.

INCREASE TO QUARTERLY COMMON SHARE DIVIDEND AND DECLARATION OF PREFERRED SHARE DIVIDENDS

Birchcliff’s board of directors has declared a quarterly cash dividend of $0.02625 per share on its common shares for the quarter ending March 31, 2019. The dividend is payable on April 1, 2019 to shareholders of record at the close of business on March 15, 2019. This dividend represents a 5% increase over the prior quarter and demonstrates Birchcliff’s ability to generate free funds flow. It is expected that the total dividends payable to common shareholders during 2019 will be approximately $28 million, assuming a quarterly dividend of $0.02625 per common share and approximately 266 million common shares issued and outstanding.

In addition, Birchcliff’s board of directors has declared the following quarterly cash dividends on its preferred shares for the quarter ending March 31, 2019:

Shares TSX Stock Symbol Dividend per Share
Cumulative Redeemable Preferred Shares, Series A BIR.PR.A $ 0.523375
Cumulative Redeemable Preferred Shares, Series C BIR.PR.C $ 0.4375

These preferred share dividends are also payable on April 1, 2019 to shareholders of record at the close of business on March 15, 2019. All of the foregoing dividends have been designated as eligible dividends for the purposes of the Income Tax Act (Canada).

The declaration of dividends in the future and the amount of such dividends, if any, is subject to the discretion of the board of directors and may vary depending on a variety of factors and conditions existing from time to time.

OUTLOOK AND GUIDANCE

Birchcliff’s 2019 Capital Program targets an annual average production rate of 76,000 to 78,000 boe/d which is expected to generate approximately $330 million of adjusted funds flow, based on the assumptions set forth herein. Total F&D capital expenditures are estimated to be $204 million, which are significantly less than Birchcliff’s estimated 2019 adjusted funds flow.

Based on the assumptions set forth in the table below, Birchcliff currently expects that it will be well positioned to generate significant free funds flow in 2019 as supported by its natural gas diversification and financial risk management contracts and mix of long-life and low decline assets which provide it with a stable base of production. Any free funds flow will be allocated based on what Birchcliff believes will provide the most value to its shareholders, with alternatives that may include debt reduction, production growth and purchasing common shares under its normal course issuer bid. Any free funds flow will also be allocated by Birchcliff to pay dividends on its common and preferred shares (including the increased dividend on the common shares) and to pay for the Acquisition.

During 2019, the Corporation expects that approximately 65% of its natural gas will be effectively sold at prices that are not based on AECO. In addition, effectively 87% of Birchcliff’s total revenue in 2019 is expected to be based on non-AECO benchmark prices after taking into account Birchcliff’s commodity risk management contracts and expected sales from oil and NGLs and based on the commodity price assumptions set forth in the table below. This natural gas market diversification together with Birchcliff’s financial risk management contracts will help to further strengthen Birchcliff’s balance sheet and protect its cash flow and project economics.

The following table sets forth Birchcliff’s previous and updated guidance and commodity price assumptions for 2019, as well as its 2018 actual unaudited results for comparative purposes:

    Previous
Preliminary 2019
Guidance and
Assumptions(1)
  Updated 2019
Guidance and
Assumptions
(2)
  2018 Actual
Unaudited
Results
Production
Annual average production (boe/d) 76,000 – 78,000 76,000 – 78,000 77,096
% Natural gas 80 % 79 % 80 %
% Light oil 7 % 6 %
% Condensate 6 % 6 %
% Other NGLs 8 % 8 %
 
Average Expenses ($/boe)
Royalty N/A 1.30 – 1.50 1.36
Operating N/A 3.15 – 3.35 3.52
Transportation and other N/A 4.65 – 4.85(3) 3.68(4)
Adjusted Funds Flow (MM$) 345 330(5) 312.9
 
F&D Capital Expenditures (MM$) 210 204(6)(7) 299.7
 
Free Funds Flow (MM$)(8) 135 126 13.2
 
Acquisition Purchase Price (MM$) 39(9) 39(9) N/A
 
Total Capital Expenditures (MM$) N/A 245(6) 298.0
 
Natural Gas Market Exposure(10)
AECO exposure as a % of total natural gas production 38 % 35 % 61 %
Dawn exposure as a % of total natural gas production 36 % 39 % 31 %
NYMEX HH exposure as a % of total natural gas production 25 % 25 % N/A
Alliance pipeline exposure as a % of total natural gas production 1 % 1 % 8 %
 
Commodity Prices
Average WTI price (US$/bbl) 70.00 56.00 64.77
Average WTI-MSW differential (CDN$/bbl) 16.00 10.00 14.85
Average AECO price (CDN$/GJ) 1.75 1.65 1.42
Average Dawn price (CDN$/GJ) 3.50 3.40 3.84
Average NYMEX HH price (US$/MMBtu)(11) 3.00 3.00 3.07
Exchange rate (CDN$ to US$1) 1.28 1.32 1.2961
(1)  As disclosed on November 14, 2018.
(2)  Please see “Advisories – Forward-Looking Statements”. Birchcliff’s guidance for its commodity mix, average expenses, funds flow, capital expenditures and natural gas market exposure in 2019 is based on an annual average production rate of 77,000 boe/d during 2019, which is the mid-point of Birchcliff’s annual average production guidance for 2019.
(3)  Includes transportation tolls for 150,000 GJ/d of natural gas sold at the Dawn price from January 1, 2019 to October 31, 2019 and 175,000 GJ/d from November 1, 2019 to December 31, 2019. Also includes any new unused firm transportation costs associated with Birchcliff’s commitments on the NGTL system.
(4)  Includes transportation tolls for 120,000 GJ/d of natural gas sold at the Dawn price from January 1, 2018 to October 31, 2018 and 150,000 GJ/d from November 1, 2018 to December 31, 2018.
(5)  Birchcliff’s estimate of adjusted funds flow takes into account the settlement of financial and physical commodity risk management contracts outstanding as at February 13, 2019. See “Full-Year 2018 Unaudited Financial and Operational Results – Risk Management”.
(6)  Birchcliff’s estimate of F&D capital expenditures corresponds to Birchcliff’s 2019 capital budget. This estimate excludes the purchase price for the Acquisition and any other net potential acquisitions and dispositions. Birchcliff’s estimate of total capital expenditures includes the purchase price for the Acquisition; however, this estimate does not take into account any other potential acquisitions or dispositions as these amounts are unbudgeted. The estimate of total capital expenditures also includes minor administrative assets. See also “2019 Capital Program” and “Advisories – Capital Expenditures”.
(7)  See “2019 Capital Program”.
(8)  Free funds flow is calculated as adjusted funds flow less F&D capital expenditures and is prior to administrative assets, acquisitions, dispositions, dividend payments and abandonment and reclamation obligations. See “Non-GAAP Measures”. Free funds flow may be used by Birchcliff to reduce debt, pursue additional growth, pay dividends and/or to fund share buybacks under its normal course issuer bid. Any prolonged or significant decrease in commodity prices may leave insufficient free funds flow for debt reduction or the other foregoing purposes.
(9)  Represents the purchase price for the Acquisition of $39 million.
(10)  Birchcliff’s guidance regarding its natural gas market exposure in 2019 assumes: (i) 150,000 GJ/d being sold at the Dawn index price from January 1, 2019 to October 31, 2019 and 175,000 GJ/d from November 1, 2019 to December 31, 2019; (ii) 5 MMcf/d being sold at Alliance’s Trading Pool daily index price; and (iii) 100,000 MMBtu/d being hedged at a fixed basis differential between the AECO price and the NYMEX HH price.
(11)  $1.00 per MMBtu equals $1.00 per Mcf based on a standard heat value of 37.4 MJ/mor a heat uplift of 1.055 when converting from $/GJ.

The following table illustrates the expected impact of changes in commodity prices and the CDN/US exchange rate on the Corporation’s estimate of adjusted funds flow for 2019 of $330 million, after taking into account its commodity risk management contracts outstanding as at February 13, 2019:

  Estimated change to 2019 
adjusted funds flow 
(MM$)(1)(2)
Change in WTI US$1.00/bbl 5
Change in NYMEX HH US$0.10/MMBtu 5
Change in Dawn CDN$0.10/MMBtu 5
Change in AECO CDN$0.10/MMBtu 5
Change in CDN/US exchange rate CDN$0.01 3
(1)  See the guidance table above.
(2)  The calculated impact on adjusted funds flow is only applicable within the limited range of change indicated. Calculations are performed independently and may not be indicative of actual results. Actual results may vary materially when multiple variables change at the same time.

For further information regarding Birchcliff’s guidance, please see “Advisories – Forward-Looking Statements”.

2018 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 (combined), conventional natural gas, shale gas and NGLs reserves. Deloitte evaluated all of Birchcliff’s properties other than the Corporation’s assets in Gordondale, representing approximately 78% of the assigned total proved plus probable reserves, and McDaniel evaluated the reserves attributable to the Corporation’s assets in Gordondale, representing approximately 22% of the assigned total proved plus probable reserves.

The reserves data set forth below at December 31, 2018 is based upon the evaluation by Deloitte 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 the evaluation by McDaniel 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 dated February 13, 2019 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”).

Deloitte also prepared an evaluation with an effective date of December 31, 2017 as contained in the report of Deloitte dated February 9, 2018 (the “2017 Deloitte Reserves Report”) and McDaniel prepared an evaluation with an effective date of December 31, 2017 as contained in the report of McDaniel dated February 14, 2018 (the “2017 McDaniel Reserves Report”), which are contained in the consolidated report of Deloitte with an effective date of December 31, 2017 (the “2017 Consolidated Reserves Report”). Deloitte prepared the 2017 Consolidated Reserves Report by consolidating the properties evaluated by Deloitte in the 2017 Deloitte Reserves Report with the properties evaluated by McDaniel in the 2017 McDaniel Reserves Report, in each case using Deloitte’s forecast price and cost assumptions effective December 31, 2017 (the “2017 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, please 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, 2018, which is expected to be filed on the System for Electronic Document Analysis and Retrieval (www.sedar.com) on March 13, 2019. 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, 2018 and December 31, 2017, 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, 2018
(Mboe)
December 31, 2017
(Mboe)
Change from
December 31, 2017
Proved Developed Producing 203,631.0 197,955.1 3 %
Total Proved 689,674.1 664,480.5 4 %
Probable 312,396.0 308,034.8 1 %
Total Proved Plus Probable 1,002,070.1 972,515.3 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, 2018, estimated using the 2018 Deloitte Price Forecast:

Summary of Reserves at December 31, 2018
(Forecast Prices and Costs)
Reserves Category Light Crude Oil and
Medium Crude Oil

Conventional Natural Gas 
 Shale Gas
 NGLs
 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 9,292.8 7,406.5 5,620.7 5,176.5 989,197.3 918,413.6 28,535.1 22,404.8 203,631.0 183,743.1
Developed Non-Producing 0.0 0.5 666.1 645.3 31,301.6 29,130.5 317.5 239.6 5,645.4 5,202.7
Undeveloped 11,221.1 9,451.5 3,192.9 2,930.1 2,568,438.0 2,339,902.8 40,571.5 32,695.9 480,397.7 432,619.5
Total Proved 20,513.9 16,858.5 9,479.7 8,752.0 3,588,937.0 3,287,446.9 69,424.1 55,340.3 689,674.1 621,565.3
Probable 14,318.3 11,287.8 8,546.2 7,973.1 1,519,533.0 1,347,374.6 43,397.8 33,596.7 312,396.0 270,775.8
Total Proved Plus Probable 34,832.2 28,146.3 18,025.9 16,725.1 5,108,470.0 4,634,821.5 112,821.9 88,937.0 1,002,070.1 892,341.1

Net Present Value of Future Net Revenue

The following table sets forth the net present value of future net revenue attributable to Birchcliff’s reserves at December 31, 2018, estimated using the 2018 Deloitte Price Forecast, before deducting future income tax expenses and calculated at various discount rates:

Summary of Net Present Value of Future Net Revenue at December 31, 2018(1)
(Forecast Prices and Costs)
Before Income Taxes Discounted At (%/year)
Reserves Category 0
(MM$)
5
(MM$)
10
(MM$)
15
(MM$)
20
(MM$)
Unit Value Discounted at 10%/year
($/boe)(2)
Proved
Developed Producing 4,261.8 3,033.8 2,329.5 1,885.9 1,585.7 12.68
Developed Non-Producing 98.6 64.4 46.1 35.2 28.2 8.87
Undeveloped 8,197.4 4,252.0 2,370.8 1,365.3 781.9 5.48
Total Proved 12,557.8 7,350.2 4,746.4 3,286.5 2,395.8 7.64
Probable 6,869.4 2,898.5 1,433.1 789.6 469.2 5.29
Total Proved Plus Probable 19,427.1 10,248.6 6,179.5 4,076.1 2,865.0 6.93
(1)  Estimates of future net revenue, whether calculated without discount or using a discount rate, do not represent fair market value.
(2)  Unit values are based on net reserves.

Pricing Assumptions

The following table sets forth the 2018 Deloitte Price Forecast used in the 2018 Consolidated Reserves Report:

2018 Deloitte Price Forecast
Year Crude Oil Natural Gas 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$/Mcf)(1)
Ontario Dawn
Reference
Point
(CDN$/Mcf)(1)
NYMEX Henry Hub
(US$/Mcf)
Edmonton Ethane
(CDN$/bbl)

Edmonton Propane (CDN$/bbl) Edmonton Butane (CDN$/bbl) Edmonton
Pentanes +
Condensate
(CDN$/bbl)
2019 58.00 65.80 1.75 3.90 3.00 5.70 32.90 29.60 75.65 0.760 0.0
2020 61.20 72.45 2.20 4.15 3.15 6.10 36.25 39.90 79.70 0.760 2.0
2021 64.50 78.35 2.50 4.40 3.45 6.95 39.15 50.95 86.20 0.770 2.0
2022 69.00 81.95 2.80 4.50 3.60 7.85 40.95 53.25 90.10 0.790 2.0
2023 75.75 89.30 3.20 4.75 3.85 8.95 44.65 58.05 98.25 0.800 2.0
2024 77.30 91.10 3.55 5.15 4.15 9.90 45.55 59.25 100.20 0.800 2.0
2025 78.85 92.90 3.85 5.45 4.40 10.70 46.45 60.40 102.20 0.800 2.0
2026 80.40 94.75 3.95 5.65 4.55 11.10 47.40 61.65 104.25 0.800 2.0
2027 82.00 96.65 4.10 5.80 4.70 11.50 48.35 62.85 106.35 0.800 2.0
2028 83.65 98.60 4.20 5.90 4.80 11.70 49.30 64.10 108.45 0.800 2.0
2029 85.35 100.55 4.25 6.05 4.90 11.95 50.30 65.40 110.60 0.800 2.0
2030 87.05 102.60 4.35 6.15 4.95 12.20 51.30 66.70 112.85 0.800 2.0
2031 88.80 104.65 4.45 6.30 5.05 12.45 52.30 68.05 115.10 0.800 2.0
2032 90.55 106.70 4.55 6.40 5.15 12.70 53.35 69.40 117.40 0.800 2.0
2033 92.35 108.85 4.60 6.55 5.30 12.95 54.45 70.80 119.75 0.800 2.0
2034 94.20 111.05 4.70 6.65 5.40 13.20 55.50 72.20 122.15 0.800 2.0
2035 96.10 113.25 4.80 6.80 5.50 13.45 56.65 73.65 124.60 0.800 2.0
2036 98.00 115.50 4.90 6.95 5.60 13.70 57.75 75.10 127.05 0.800 2.0
2037 100.00 117.85 5.00 7.05 5.70 14.00 58.90 76.65 129.60 0.800 2.0
2038 102.00 120.20 5.10 7.20 5.85 14.30 60.10 78.15 132.20 0.800 2.0
2038+ 2.0 % 2.0 % 2.0 % 2.0 % 2.0 % 2.0 % 2.0 % 2.0 % 2.0 % 0.800 2.0
(1) 1 Mcf = 1 MMBtu.

In comparison to the 2017 Deloitte Price Forecast, the AECO natural gas price forecast for 2019 decreased by 24% and the Edmonton City Gate oil price forecast decreased by 4%.

Reconciliation of Changes in Reserves

The following table sets forth a reconciliation of Birchcliff’s gross reserves at December 31, 2018 as set forth in the 2018 Consolidated Reserves Report, estimated using the 2018 Deloitte Price Forecast, to Birchcliff’s gross reserves at December 31, 2017 as set forth in the 2017 Consolidated Reserves Report, estimated using the 2017 Deloitte Price Forecast:

Reconciliation of Gross Reserves from December 31, 2017 to December 31, 2018
(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, 2017 16,615.8 21,752.4 3,470,382.2 65,842.3 664,480.5
Discoveries(1) 0.0 0.0 0.0 0.0 0.0
Extensions & Improved Recovery(2) 2,304.6 0.0 167,870.6 2,950.3 33,233.3
Technical Revisions(3) 3,436.2 (4,081.1 ) 82,830.1 4,322.0 20,883.0
Acquisitions(4) 0.0 15.9 2,722.3 37.7 494.1
Dispositions(5) (235.3 ) (4,941.9 ) 0.0 (11.9 ) (1,070.8 )
Economic Factors(6) 171.2 (2,416.2 ) 124.3 4.8 (206.0 )
Production(7) (1,778.6 ) (849.4 ) (134,992.5 ) (3,721.1 ) (28,140.0 )
Closing balance December 31, 2018 20,513.9 9,479.7 3,588,937.0 69,424.1 689,674.1
GROSS TOTAL PROBABLE
Opening balance December 31, 2017 14,394.0 14,103.2 1,449,379.3 49,727.2 308,034.8
Discoveries(1) 0.0 0.0 0.0 0.0 0.0
Extensions & Improved Recovery(2) 1,280.5 0.0 28,582.0 885.6 6,929.8
Technical Revisions(3) (1,094.9 ) (4,924.4 ) 16,047.0 (8,214.5 ) (7,455.7 )
Acquisitions(4) 0.0 0.0 24,954.9 969.3 5,128.4
Dispositions(5) (264.3 ) (2,210.4 ) 0.0 (6.6 ) (639.2 )
Economic Factors(6) 3.0 1,577.8 569.9 36.8 397.8
Production(7) 0.0 0.0 0.0 0.0 0.0
Closing balance December 31, 2018 14,318.3 8,546.2 1,519,533.0 43,397.8 312,396.0
GROSS TOTAL PROVED PLUS PROBABLE
Opening balance December 31, 2017 31,009.7 35,855.6 4,919,761.5 115,569.4 972,515.3
Discoveries(1) 0.0 0.0 0.0 0.0 0.0
Extensions & Improved Recovery(2) 3,585.1 0.0 196,452.5 3,835.9 40,163.1
Technical Revisions(3) 2,341.3 (9,005.5 ) 98,877.1 (3,892.5 ) 13,427.5
Acquisitions(4) 0.0 15.9 27,677.2 1,007.0 5,622.5
Dispositions(5) (499.5 ) (7,152.4 ) 0.0 (18.5 ) (1,710.0 )
Economic Factors(6) 174.2 (838.4 ) 694.2 41.6 191.8
Production(7) (1,778.6 ) (849.4 ) (134,992.5 ) (3,721.1 ) (28,140.0 )
Closing balance December 31, 2018 34,832.2 18,025.9 5,108,470.0 112,821.9 1,002,070.1
(1)  Additions to volumes in reservoirs where no reserves were previously booked.
(2)  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.
(3)  Positive or negative volume revisions to an estimate resulting from new technical data or revised interpretations on previously assigned volumes, performance and operating costs.
(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 production.

Key highlights include the following:

  • Extensions and Improved Recovery – Reserves added were due to the successful 2018 Capital Program for the wells drilled and brought on production, including the additional offsetting future drilling locations that were assigned.
  • Technical Revisions – The positive technical revisions in the total proved and the total proved plus probable reserves categories were primarily the result of the following: (i) for shale gas, increased well performance in existing and future drilling locations in Pouce Coupe; (ii) for light and medium crude oil, the reclassification of drilling locations from shale gas to light and medium crude oil in Gordondale; and (iii) for NGLs, the successful C3+ extraction project at Phases V and VI of the Pouce Coupe Gas Plant. These positive technical revisions were offset by the loss of NGLs reserves due to the cancellation of the proposed Phase VII deep-cut expansion at the Pouce Coupe Gas Plant in connection with Birchcliff entering into the Gordondale Processing Arrangement, as well as the removal of the conventional natural gas reserves for the planned abandonment of a non-core facility.The negative technical revisions in the total probable reserves category were primarily the result of the loss of NGLs reserves due to the cancellation of Phase VII, the removal of the conventional natural gas reserves for the planned abandonment of the non-core facility and the adjustment in light and medium crude oil reserves for future infill drilling locations in Gordondale.
  • Acquisitions – Changes were the result of various minor acquisitions Birchcliff completed in the Gordondale and Pouce Coupe areas in 2018.
  • Dispositions – Changes were the result of various non-core dispositions Birchcliff completed in 2018.
  • Economic Factors – The lower natural gas price forecast resulted in the reduction of conventional natural gas reserves in the proved reserves category as one future drilling location was not economic to develop and was reclassified into the probable reserves category. In addition, the economic limit caused the reduction of proved plus probable conventional natural gas reserves. This was offset by the slightly higher price forecasts for oil and NGLs which resulted in increases to the light and medium crude oil, shale gas and NGLs reserves in all reserves categories.

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$)
Proved Plus Probable
(MM$)
2019 244.9 271.0
2020 492.5 514.5
2021 399.6 506.4
2022 720.5 791.8
2023 477.0 535.0
Thereafter 627.3 1,673.1
Total undiscounted 2,961.8 4,291.8

FDC for total proved reserves decreased to $2.96 billion at December 31, 2018 from $3.23 billion at December 31, 2017. FDC for total proved plus probable reserves decreased to $4.29 billion at December 31, 2018 from $4.50 billion at December 31, 2017. The decreases in FDC for both proved and proved plus probable reserves were largely due to: (i) the cancellation of Phase VII; and (ii) the completion of Phase VI of the Pouce Coupe Gas Plant which occurred in Q3 2018. These decreases were partially offset by 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 2018 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 $331 million 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, 2018
(MM$)
December 31, 2017
(MM$)
Pouce Coupe(1) 4.7 4.6
Gordondale(2) 5.4 5.2
(1)  Estimated by Deloitte. Up slightly compared to 2017 based on actual costs incurred in 2018 from higher completions costs as a result of increased fracture intensities per well.
(2)  Estimated by McDaniel. Up slightly compared to 2017 based on actual costs incurred in 2018 from higher completions costs as a result of increased fracture intensities per well.

Reserves Replacement

The following table sets forth Birchcliff’s 2018 reserves replacement ratios:

Reserves Category 2018 Reserves Replacement, Excluding the Effects of Acquisitions and Dispositions(1) 2018 Reserves Replacement, Including the
Effects of Acquisitions and Dispositions
(1)
Proved Developed Producing 122 % 120 %
Proved 192 % 190 %
Proved Plus Probable 191 % 205 %
(1)  Please 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 2018 reserves life index:

Reserves Category   2018 Reserves Life Index(1)
Proved Developed Producing 7.2 years
Total Proved 24.5 years
Total Proved Plus Probable 35.6 years
(1)  Based on a forecast production rate of 77,000 boe/d for 2019, which represents the mid-point of Birchcliff’s annual average production guidance range for 2019. Please 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 2018 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 2018 2017 2018 2017 2018 2017 2018 2017 2018 2017 2018 2017
Proved Developed Producing 973.4 976.5 9,239.1 8,323.4 27,923.0 23,066.0 199,396.1 194,145.1 368 339 364.3 333.8
Total Proved 3,572.8 3,464.1 20,460.2 16,318.7 68,779.3 65,348.2 684,710.4 659,029.0 903 862 888.8 846.0
Total Proved Plus Probable 5,088.6 4,911.2 34,758.7 30,428.7 111,985.9 114,869.1 994,848.1 963,836.1 1,154 1,103 1,121.8 1,072.0
(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, 2018, the estimated FDC for Birchcliff’s reserves on its Montney/Doig Resource Play is $0.0 million on a proved developed producing basis (as compared to $0.0 million at December 31, 2017), $2,958.7 million on a proved basis (as compared to $3,223.3 million at December 31, 2017) and $4,282.9 million on a proved plus probable basis (as compared to $4,480.8 million at December 31, 2017).


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
DCCET drill, case, complete, equip and tie-in
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 International Financial Reporting Standards as issued by the International Accounting Standards Board
GJ gigajoule
GJ/d gigajoules per day
HH Henry Hub
m3 cubic metres
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
MJ megajoule
MM millions
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
NGTL NOVA Gas Transmission Ltd.
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

NON-GAAP MEASURES

This press release uses “adjusted funds flow”, “adjusted funds flow per common share”, “free funds flow”, “operating netback”, “adjusted funds flow netback”, “operating margin”, “total cash costs”, “adjusted working capital deficit” and “total debt”. These measures do not have standardized meanings prescribed by GAAP and therefore may not be comparable to similar measures presented by other companies where similar terminology is used. Management believes that these non-GAAP measures assist management and investors in assessing Birchcliff’s profitability, efficiency, liquidity and overall performance. Each of these measures is discussed in further detail below.

“Adjusted funds flow” denotes cash flow from operating activities before the effects of decommissioning expenditures and changes in non-cash working capital and “adjusted funds flow per common share” denotes adjusted funds flow divided by the basic or diluted weighted average number of common shares outstanding for the period. Birchcliff eliminates changes in non-cash working capital and settlements of decommissioning expenditures from cash flow from operating activities as the amounts can be discretionary and may vary from period-to-period depending on its capital programs and the maturity of its operating areas. The settlement of decommissioning expenditures are managed with Birchcliff’s capital budgeting process which considers available adjusted funds flow. Management believes that adjusted funds flow and adjusted funds flow per common share assist management and investors in assessing Birchcliff’s profitability, as well as its ability to generate the cash necessary to fund future growth through capital investments, decommission its assets, pay dividends and repay debt. Investors are cautioned that adjusted funds flow should not be construed as an alternative to or more meaningful than cash flow from operating activities or net income or loss as determined in accordance with GAAP as an indicator of Birchcliff’s performance. Birchcliff previously referred to adjusted funds flow as “funds flow from operations”. The following table provides a reconciliation of cash flow from operating activities, as determined in accordance with GAAP, to adjusted funds flow for the periods indicated:

  Three months ended
December 31,
Twelve months ended
December 31,
($000s) 2018 2017 2018 2017
Cash flow from operating activities 92,200 88,995 324,434 287,660
Add back:
Change in non-cash working capital (10,838 ) 7,920 (12,591 ) 29,226
Funds flow 81,362 96,915 311,843 316,886
Adjustments:
Decommissioning expenditures 155 93 1,079 794
Adjusted funds flow 81,517 97,008 312,922 317,680

“Free funds flow” denotes adjusted funds flow less F&D capital expenditures. Management believes that free funds flow assists management and investors in assessing Birchcliff’s ability to generate the cash necessary to repay debt, pay dividends, fund a portion of its future growth investments and/or fund share buybacks.

“Operating netback” denotes petroleum and natural gas revenue less royalty expense, less operating expense and less transportation and other expense. “Adjusted funds flow netback” denotes petroleum and natural gas revenue less royalty expense, less operating expense, less transportation and other expense, less net G&A expense, less interest expense and less any realized losses (plus realized gains) on financial instruments and plus any other cash income sources. Birchcliff previously referred to adjusted funds flow netback as “funds flow netback”. All netbacks are calculated on a per unit basis, unless otherwise indicated. Management believes that operating netback and adjusted funds flow netback assist management and investors in assessing Birchcliff’s profitability and its operating results on a per unit basis to better analyze its performance against prior periods on a comparable basis. The following table provides a breakdown of Birchcliff’s operating netback and adjusted funds flow netback for the periods indicated:

  Three months ended
December 31,
Twelve months ended
December 31,
  2018
2017 2018 2017
  ($000s) ($/boe) ($000s) ($/boe) ($000s) ($/boe) ($000s) ($/boe)
Petroleum and natural gas revenue 154,720 22.01 166,149 22.55 621,421 22.08 556,942 22.45
Royalty expense (6,763 ) (0.96 ) (9,271 ) (1.26 ) (38,306 ) (1.36 ) (28,727 ) (1.16 )
Operating expense (24,677 ) (3.51 ) (28,460 ) (3.86 ) (99,104 ) (3.52 ) (110,486 ) (4.45 )
Transportation and other expense (28,567 ) (4.07 ) (25,883 ) (3.52 ) (103,547 ) (3.68 ) (71,224 ) (2.87 )
Operating netback(1) 94,713 13.47 102,535 13.91 380,464 13.52 346,505 13.97
General & administrative expense, net (7,618 ) (1.08 ) (9,451 ) (1.28 ) (24,602 ) (0.87 ) (26,504 ) (1.07 )
Interest expense (7,438 ) (1.06 ) (7,131 ) (0.97 ) (27,969 ) (0.99 ) (28,374 ) (1.14 )
Realized gain (loss) on financial instruments 1,658 0.24 10,787 1.46 (15,771 ) (0.56 ) 25,785 1.03
Other income 202 0.03 268 0.04 800 0.02 268 0.02
Adjusted funds flow netback(1) 81,517 11.60 97,008 13.16 312,922 11.12 317,680 12.81
(1)  All per boe amounts are calculated by dividing each aggregate financial amount by the production (boe) in the respective period.

The reconciliation for the operating netback of the Pouce Coupe Gas Plant is provided under the heading “Full-Year 2018 Unaudited Financial and Operational Results – Pouce Coupe Gas Plant Netbacks”.

“Operating margin” for the Pouce Coupe Gas Plant is calculated by dividing the operating netback for the period by the petroleum and natural gas revenue for the period. Management believes that operating margin assists management and investors in assessing the profitability and efficiency of the Pouce Coupe Gas Plant and Birchcliff’s ability to generate operating cash flows (equal to petroleum and natural gas revenue less royalties, less operating expense and less transportation and other expense).

“Total cash costs” are comprised of royalty, operating, transportation and other, G&A and interest expenses. Total cash costs are calculated on a per unit basis. Management believes that total cash costs assists management and investors in assessing Birchcliff’s efficiency and overall cash cost structure.

“Adjusted working capital deficit” is calculated as current assets minus current liabilities excluding the effects of any financial instruments. Management believes that adjusted working capital deficit assists management and investors in assessing Birchcliff’s liquidity. The following table reconciles working capital deficit (current assets minus current liabilities), as determined in accordance with GAAP, to adjusted working capital deficit:

As at, ($000s) December 31, 2018 December 31, 2017
Working capital deficit (surplus) (15,611 ) 15,113
Financial instrument – asset 36,798
Financial instrument – liability (4,046 )
Adjusted working capital deficit 21,187 11,067

“Total debt” is calculated as the revolving term credit facilities plus adjusted working capital deficit. Management believes that total debt assists management and investors in assessing Birchcliff’s liquidity. The following table provides a reconciliation of the revolving term credit facilities, as determined in accordance with GAAP, to total debt:

As at, ($000s) December 31, 2018 December 31, 2017
Revolving term credit facilities 605,267 587,126
Adjusted working capital deficit 21,187 11,067
Total debt 626,454 598,193

PRESENTATION OF OIL AND GAS RESERVES

Deloitte prepared the 2018 Consolidated Reserves Report, the 2017 Consolidated Reserves Report, the 2018 Deloitte Reserves Report and the 2017 Deloitte Reserves Report. McDaniel prepared the 2018 McDaniel Reserves Report and the 2017 McDaniel Reserves Report. In addition, Deloitte prepared a reserves evaluation in respect of Birchcliff’s oil and natural gas properties effective December 31, 2016. Such evaluations were prepared in accordance with the standards contained in NI 51-101 and the COGE Handbook that were in effect at the relevant time. Reserves estimates stated herein are extracted from the relevant evaluation.

There are numerous uncertainties inherent in estimating quantities of oil, natural gas and NGLs reserves and the future net revenue attributed to such reserves, including many factors beyond the control of Birchcliff. The reserves and associated future net revenue information set forth in this press release are estimates only. In general, estimates of economically recoverable oil, natural gas and NGLs reserves and the future net revenue therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, decline rates, ultimate reserves recovery, the timing and amount of capital expenditures, the success of future development activities, future commodity prices, marketability of oil, natural gas and NGLs, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially from actual results. For those reasons, estimates of the economically recoverable oil, natural gas and NGLs reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenue associated with reserves prepared by different engineers, or by the same engineer at different times, may vary substantially. Birchcliff’s actual production, revenues, taxes and development and operating expenditures with respect to its reserves will vary from estimates thereof and such variations could be material.

It should not be assumed that the undiscounted or discounted net present value of future net revenue attributable to the Corporation’s reserves estimated by the Corporation’s independent qualified reserves evaluators represent the fair market value of those reserves. There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. Actual oil, natural gas and NGLs reserves may be greater than or less than the estimates provided herein and variances could be material. With respect to the disclosure of reserves contained herein relating to portions of Birchcliff’s properties, the 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. In this press release, all references to “reserves” are to Birchcliff’s gross company reserves unless otherwise stated.

The information set forth in this press release relating to the reserves and future net revenues of Birchcliff constitutes forward-looking statements and is subject to certain risks and uncertainties. See “Advisories – Forward-Looking Statements”.

Definitions

Certain terms used herein but not defined are defined in NI 51-101, CSA Staff Notice 51-324 – Revised Glossary to NI 51-101 Standards of Disclosure for Oil and Gas Activities (“CSA Staff Notice 51-324”) and/or the COGE Handbook and, unless the context otherwise requires, shall have the same meanings herein as in NI 51-101, CSA Staff Notice 51-324 and the COGE Handbook, as the case may be.

Reserves Categories

Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on the analysis of drilling, geological, geophysical and engineering data; the use of established technology; and specified economic conditions, which are generally accepted as being reasonable. Reserves are classified according to the degree of certainty associated with the estimates:

  • Proved reserves” are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.
  • Probable reserves” are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

Interest in Reserves, Production, Wells and Properties

Gross” means: (a) in relation to Birchcliff’s interest in production or reserves, its “company gross reserves”, which are Birchcliff’s working interest (operating or non-operating) share before deduction of royalties and without including any royalty interests of Birchcliff; (b) in relation to wells, the total number of wells in which Birchcliff has an interest; and (c) in relation to properties, the total area of properties in which Birchcliff has an interest.

Net” means: (a)  in relation to Birchcliff’s interest in production or reserves, Birchcliff’s working interest (operating or non-operating) share after deduction of royalty obligations, plus Birchcliff’s royalty interests in production or reserves; (b) in relation to Birchcliff’s interest in wells, the number of wells obtained by aggregating Birchcliff’s working interest in each of its gross wells; and (c) in relation to Birchcliff’s interest in a property, the total area in which Birchcliff has an interest multiplied by the working interest owned by Birchcliff.

ADVISORIES

Unaudited Information

All financial and operating information contained in this press release for the fourth quarter and year ended December 31, 2018, such as FD&A costs, F&D costs, recycle ratio, adjusted funds flow, total capital expenditures, operating expense, total cash costs, total debt and production information, is based on unaudited estimated results. These estimated results are subject to change upon completion of the audited financial statements for the year ended December 31, 2018, and changes could be material. Birchcliff anticipates filing its audited financial statements and related management’s discussion and analysis for the year ended December 31, 2018 on SEDAR on March 13, 2019.

Currency

Unless otherwise indicated, all dollar amounts are expressed in Canadian dollars and all references to “$” and “CDN$” are to Canadian dollars and all references to “US$” are to United States dollars.

Boe and Mcfe Conversions

Boe amounts have been calculated by using the conversion ratio of 6 Mcf of natural gas to 1 bbl of oil and Mcfe amounts have been calculated by using the conversion ratio of 1 bbl of oil to 6 Mcf of natural gas. Boe and Mcfe amounts may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf: 1 bbl and an Mcfe conversion ratio of 1 bbl: 6 Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.

MMBtu Pricing Conversions

$1.00 per MMBtu equals $1.00 per Mcf based on a standard heat value Mcf.

Oil and Gas Metrics

This press release 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 have been determined by Birchcliff as set out below. These oil and gas metrics do not have any standardized meanings or standard methods of calculation and therefore may not be comparable to similar measures presented by other companies where similar terminology is used. As such, they should not be used to make comparisons. Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare Birchcliff’s performance over time; however, such measures are not reliable indicators of Birchcliff’s future performance, which may not compare to Birchcliff’s performance in previous periods, and therefore should not be unduly relied upon.

  • Reserves life index is calculated by dividing reserves estimated by Birchcliff’s independent qualified reserves evaluators at December 31, 2018 by 77,000 boe/d, which production rate represents the mid-point of Birchcliff’s annual average production guidance range for 2019. Reserves life index may be used as a measure of a company’s sustainability.
  • Recycle ratios are calculated by dividing the average operating netback per boe or adjusted funds flow netback per boe, as the case may be, by F&D costs and FD&A costs, as the case may be. Recycle ratios may be used as a measure of a company’s profitability.
  • Reserves replacement is calculated by dividing proved developed producing reserves, proved reserves or proved plus probable reserves additions, as the case may be, before production by total production in the applicable period. Reserves replacement ratios have been presented both including and excluding the effects of acquisitions and dispositions. Reserves replacement may be used as a measure of a company’s sustainability and its ability to replace its proved developed producing reserves, proved reserves or proved plus probable reserves, as the case may be.
  • With respect to F&D and FD&A costs disclosed in this press release:°  F&D costs both including and excluding FDC have been presented herein. F&D costs for each reserves category in a particular period are calculated by taking the sum of: (i) exploration and development costs incurred in the period; and (ii) where FDC has been included, the change during the period in FDC for the reserves category; divided by the additions to the reserves category before production during the period. F&D costs exclude the effects of acquisitions and dispositions. FD&A costs are calculated in the same manner as F&D costs but include the effects of acquisitions and dispositions.°  In calculating the amounts of F&D and FD&A costs for a year, the changes during the year in estimated reserves and estimated FDC are based upon the evaluations of Birchcliff’s reserves prepared by its independent qualified reserves evaluators, effective December 31 of such year.°  The aggregate of the exploration and development costs incurred in the most recent financial year and any change during that year in estimated FDC generally will not reflect total F&D costs related to reserves additions for that year.

    °  F&D and FD&A costs may be used as a measure of a company’s efficiency with respect to finding and developing its reserves.

  • For information regarding netbacks, please see “Non-GAAP Measures”.

Drilling Locations

This press release discloses net existing horizontal wells and potential net future horizontal drilling locations in four categories: (i) proved locations; (ii) proved plus probable locations; (iii) unbooked locations; and (iv) an aggregate total of (ii) and (iii). Of the 6,746.4 net existing horizontal wells and potential net future horizontal drilling locations identified herein, 888.8 are proved locations, 1,121.8 are proved plus probable locations and 5,624.6 are unbooked locations.

Proved locations and probable locations are proposed drilling locations identified in the 2018 Consolidated Reserves Report that have proved and/or probable reserves, as applicable, attributed to them in the 2018 Consolidated Reserves Report. Unbooked locations are internal estimates based on Birchcliff’s prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal technical analysis review. Unbooked locations have been identified by management as an estimate of Birchcliff’s multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. Unbooked locations do not have proved or probable reserves attributed to them in the 2018 Consolidated Reserves Report.

Birchcliff’s ability to drill and develop these locations and the drilling locations on which Birchcliff actually drills wells depends on a number of uncertainties and factors, including, but not limited to, the availability of capital, equipment and personnel, oil and natural gas prices, costs, inclement weather, seasonal restrictions, drilling results, additional geological, geophysical and reservoir information that is obtained, production rate recovery, gathering system and transportation constraints, the net price received for commodities produced, regulatory approvals and regulatory changes. As a result of these uncertainties, there can be no assurance that the potential future drilling locations that Birchcliff has identified will ever be drilled and, if drilled, that such locations will result in additional oil, NGLs or natural gas production and, in the case of unbooked locations, additional reserves. As such, Birchcliff’s actual drilling activities may differ materially from those presently identified, which could adversely affect Birchcliff’s business. While certain of the unbooked drilling locations have been de-risked by drilling existing wells in relatively close proximity to such unbooked drilling locations, some of the other unbooked drilling locations are farther away from existing wells, where management has less information about the characteristics of the reservoir and there is therefore more uncertainty whether wells will be drilled in such locations and, if drilled, there is more uncertainty that such wells will result in additional proved or probable reserves, resources or production.

Initial Production Rates

Any references in this press release to initial production rates or other short-term production rates are useful in confirming the presence of hydrocarbons; however, such rates are not determinative of the rates at which such wells will continue to produce and decline thereafter and are not indicative of the long-term performance or of the ultimate recovery of such wells. In addition, such rates may also include recovered “load oil” or “load water” fluids used in well completion stimulation. While encouraging, readers are cautioned not to place undue reliance on such rates in calculating the aggregate production for Birchcliff. Such rates are based on field estimates and may be based on limited data available at this time.

Capital Expenditures

Unless otherwise stated, references in this press release to: (i) “F&D capital” denotes capital for land, seismic, workovers, drilling and completions and well equipment and facilities; and (ii) “total capital expenditures” denotes F&D capital plus acquisitions, less any dispositions, plus administrative assets. Birchcliff previously referred to total capital expenditures as “net capital expenditures” or “capital expenditures, net”.

Payment of Dividends

The declaration of dividends in any quarter and the amount of such dividends, if any, is subject to the discretion of Birchcliff’s board of directors and may vary depending on a variety of factors and conditions existing from time to time, including fluctuations in commodity prices, the financial condition of Birchcliff, production levels, results of operations, capital expenditure and debt service requirements, contractual restrictions, hedging activities or programs, available investment opportunities, Birchcliff’s business plan, strategies and objectives, the satisfaction of the solvency and liquidity tests imposed by the Business Corporations Act (Alberta) for the declaration and payment of dividends and other factors that Birchcliff’s board of directors may deem relevant. The payment of cash dividends to common shareholders in the future is not assured or guaranteed and dividends may be reduced or suspended. Birchcliff’s dividend policy will be periodically reviewed by its board of directors and no assurance or guarantee can be given that Birchcliff will maintain the dividend policy in its current form.



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