Birchcliff Energy Ltd. announces unaudited 2020 year-end and fourth quarter results and 2020 reserves highlights

CALGARY, Alberta – Birchcliff Energy Ltd. (“Birchcliff” or the “Corporation”) (TSX: BIR) is pleased to announce its unaudited 2020 year-end and fourth quarter financial and operational results and highlights from its independent reserves evaluation effective December 31, 2020.

Jeff Tonken, President and Chief Executive Officer of Birchcliff commented: “Birchcliff is proud to announce its fourth quarter and full-year 2020 results. 2020 was a challenging year for Birchcliff and for the industry as a whole. Despite the economic damage and pricing uncertainty caused by the COVID-19 pandemic, we were able to efficiently execute our 2020 capital program, generating annual adjusted funds flow of $185 million, with annual average production of 76,401 boe/d and record low annual operating costs of $2.95 per/boe. Birchcliff also returned to free funds flow generation in the second half of 2020, with free funds flow of $25 million in Q4 2020. These achievements speak to the strong performance of our assets and the significant efforts of our team to remain one of industry’s lowest-cost producers. Looking forward to 2021, we are focused on maximizing free funds flow and strengthening our balance sheet, while maintaining a relatively flat production profile. We expect to generate approximately $360 million of adjusted funds flow in 2021¹, with F&D capital expenditures of between $210 million and $230 million, resulting in significant free funds flow for the year as set forth in our press release dated January 20, 2021. As none of Birchcliff’s production is currently subject to fixed price commodity hedges, we are excited about the undersupplied natural gas market that is emerging and being accelerated by cold weather in North America, Europe and Asia, which sets up a strong outlook for forward natural gas pricing.”

Q4 2020 Highlights

• Achieved quarterly average production of 78,649 boe/d, a 1% increase from Q4 2019.
• Liquids accounted for approximately 24% of Birchcliff’s total production in Q4 2020, as compared to approximately 22% in Q4 2019, with total liquids production increasing by 8% from Q4 2019.
• Delivered $66.5 million of adjusted funds flow, or $0.25 per basic common share, an 18% decrease and a 17% decrease, respectively, from Q4 2019.
• Generated $25.2 million of free funds flow in Q4 2020, a 4% increase from $24.1 million in Q4 2019.
• Recorded net income to common shareholders of $40.4 million, or $0.15 per basic common share, as compared to a net loss to common shareholders of $19.0 million and $0.07 per basic common share in Q4 2019.
• Achieved operating expense of $3.03/boe, a 1% decrease from Q4 2019.
• Realized an operating netback of $13.01/boe, a 9% decrease from Q4 2019.
• F&D capital expenditures of $41.3 million. During the quarter, Birchcliff drilled 6 (6.0 net) wells to help ensure the efficient execution of the Corporation’s 2021 capital program (the “2021 Capital Program”).
• Redeemed 364,655 Series C preferred shares in Q4 2020 for an aggregate of $9.1 million.

2020 Year-End Highlights

• Achieved annual average production of 76,401 boe/d, a 2% decrease from 2019.
• Liquids accounted for approximately 23% of Birchcliff’s total production in 2020, as compared to approximately 22% in 2019, with total liquids production increasing by 4% from 2019.
• Delivered $184.5 million of adjusted funds flow, or $0.69 per basic common share, each a 45% decrease from 2019.
• Recorded a net loss to common shareholders of $62.0 million, or $0.23 per basic common share, as compared to a net loss to common shareholders of $59.6 million and $0.22 per basic common share in 2019.
• Achieved record low annual operating expense of $2.95/boe, a 5% decrease from 2019.
• Realized an operating netback of $10.37/boe, a 21% decrease from 2019.
• Successfully executed the Corporation’s 2020 capital program (the “2020 Capital Program”), drilling and bringing on production a total of 34 (34.0 net) wells. F&D capital expenditures were $288.0 million in 2020.
• Redeemed 402,820 Series C preferred shares during 2020. At December 31, 2020, the Corporation had 1,597,180 Series C preferred shares outstanding, with an aggregate redemption value of approximately $39.9 million.
• Total debt at December 31, 2020 was $762.0 million, as compared to $632.6 million at December 31, 2019.

Birchcliff anticipates filing its annual information form and audited financial statements and related management’s discussion and analysis for the year ended December 31, 2020 on March 10, 2021.

¹ Birchcliff’s estimate of adjusted funds flow of $360 million is based on an annual average production rate of 79,000 boe/d, which represents the mid-point of the Corporation’s 2021 annual average production guidance range. Assumes the following commodity prices and exchange rate in 2021: (i) an average WTI price of US$50.00/bbl; (ii) an average WTI-MSW differential of CDN$6.00/bbl; (iii) an average AECO 5A price of CDN$2.50/GJ; (iv) an average Dawn price of US$2.75/MMBtu; (v) an average NYMEX HH price of US$2.80/MMBtu; and (vi) an exchange rate (CDN$ to US$1) of 1.27. See “Advisories – Forward-Looking Statements”. Details of Birchcliff’s 2021 guidance and 2021 Capital Program were announced on January 20, 2021 and can be found online at www.birchcliffenergy.com/investors/news-releases/.

This press release contains forward-looking statements within the meaning of applicable securities laws. For further information regarding the forward-looking statements contained herein, see “Advisories – Forward-Looking Statements”. In addition, this press release uses the terms “adjusted funds flow”, “adjusted funds flow per basic common share”, “free funds flow”, “transportation and other expense”, “operating netback”, “adjusted funds flow netback”, “total cash costs”, “adjusted working capital deficit” and “total debt”, which do not have standardized meanings prescribed by GAAP. For further information regarding these non-GAAP measures, including reconciliations to the most directly comparable GAAP measure where applicable, see “Non-GAAP Measures”. This press release contains metrics commonly used in the oil and natural gas industry, including “netbacks”, “reserves life index”, “recycle ratio”, “reserves replacement”, “F&D costs” “FD&A costs” and “net asset value”, which do not have any standardized meanings. See “Advisories – Oil and Gas Metrics”. All financial and operating information for the fourth quarter and year ended December 31, 2020 is unaudited. See “Advisories – Unaudited Information”. With respect to the disclosure of Birchcliff’s production contained in this press release, see “Advisories – Production”.

 

2020 UNAUDITED FINANCIAL AND OPERATIONAL HIGHLIGHTS

	Three months ended December 31,				Twelve months ended December 31,
	2020		2019		2020		2019
OPERATING
Average production
Light oil (bbls/d)	3,566		4,435		4,415		4,742
Condensate (bbls/d)	6,658		4,906		5,824		5,145
NGLs (bbls/d)	8,285		7,814		7,650		7,264
Natural gas (Mcf/d)	360,839		364,847		351,068		364,958
Total (boe/d)	78,649		77,962		76,401		77,977
Average realized sales price (CDN$)(1)
Light oil (per bbl)	49.56		67.58		42.39		68.29
Condensate (per bbl)	52.90		68.80		48.03		68.06
NGLs (per bbl)	16.16		16.62		13.62		13.76
Natural gas (per Mcf)	2.93		2.81		2.49		2.48
Total (per boe)	21.87		22.97		18.90		21.55
NETBACK AND COST ($/boe)
Petroleum and natural gas revenue(1)	21.88		22.97		18.90		21.56
Royalty expense	(0.90	)	(1.15	)	(0.65	)	(0.96	)
Operating expense	(3.03	)	(3.06	)	(2.95	)	(3.09	)
Transportation and other expense	(4.94	)	(4.51	)	(4.93	)	(4.44	)
Operating netback ($/boe)	13.01		14.25		10.37		13.07
G&A expense, net	(1.11	)	(1.26	)	(0.88	)	(0.94	)
Interest expense	(1.20	)	(0.82	)	(0.93	)	(0.88	)
Realized gain (loss) on financial instruments	(1.63	)	(0.92	)	(2.13	)	0.48
Other income	0.12		0.03		0.17		0.02
Adjusted funds flow netback ($/boe)	9.19		11.28		6.60		11.75
Depletion and depreciation expense	(7.49	)	(7.49	)	(7.60	)	(7.50	)
Unrealized gain (loss) on financial instruments	5.84		(6.50	)	(1.27	)	(6.77	)
Other expenses (income)(2)	0.30		(0.28	)	(0.16	)	(0.51	)
Dividends on preferred shares	(0.26	)	(0.27	)	(0.27	)	(0.27	)
Income tax recovery (expense)	(2.00	)	0.61		0.48		1.21
Net income (loss) to common shareholders ($/boe)	5.58		(2.65	)	(2.22	)	(2.09	)
FINANCIAL
Petroleum and natural gas revenue ($000s)(1)	158,283		164,759		528,505		613,559
Cash flow from operating activities ($000s)	71,431		85,557		188,180		327,066
Adjusted funds flow ($000s)	66,509		80,941		184,526		334,504
Per basic common share ($)	0.25		0.30		0.69		1.26
Net income (loss) to common shareholders ($000s)	40,407		(18,984	)	(62,008	)	(59,579	)
Per basic common share ($)	0.15		(0.07	)	(0.23	)	(0.22	)
End of period basic common shares (000s)	265,943		265,935		265,943		265,935
Weighted average basic common shares (000s)	265,940		265,935		265,936		265,930
Dividends on common shares ($000s)	1,330		6,981		10,968		27,923
Dividends on preferred shares ($000s)	1,905		1,922		7,654		7,687
F&D capital expenditures ($000s)(3)	41,291		56,800		287,967		256,395
Total capital expenditures ($000s)(4)	28,778		58,136		276,785		300,246
Long-term debt ($000s)	731,372		609,177		731,372		609,177
Total debt ($000s)	761,951		632,582		761,951		632,582

^{(1)   Excludes the effects of financial instruments but includes the effects of physical delivery contracts.
(2)   Includes non-cash items such as compensation, accretion, amortization of deferred financing fees and other gains and losses.
(3)   See “Advisories – Capital Expenditures”.
(4)   Includes acquisitions, dispositions and administrative assets. See “Advisories – Capital Expenditures”.}

 

2020 RESERVES, F&D COSTS, RECYCLE RATIO AND NET ASSET VALUE HIGHLIGHTS

• The following table summarizes the estimates of Birchcliff’s gross reserves at December 31, 2020 and December 31, 2019, 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, 2020 (Mboe)	December 31, 2019 (Mboe)	Change from December 31, 2019
Proved Developed Producing	206,605.6	206,922.4	–
Total Proved	699,066.8	709,061.2	(1)%
Total Probable	341,410.1	323,133.5	6%
Total Proved Plus Probable	1,040,476.9	1,032,194.7	1%

• Proved developed producing reserves increased by 28,344.9 Mboe during 2020, before including the effects of acquisitions and dispositions and adding back 2020 actual production of 27,962.6 Mboe².
• Proved developed producing reserves increased by 1.01 boe for each boe that was produced in 2020, before including the effects of acquisitions and dispositions and adding back 2020 actual production.
• NGLs reserves, which include condensate, increased by 14% on a proved developed producing basis, 4% on a proved basis and 9% on a proved plus probable basis as a result of: (i) the discovery of condensate-rich natural gas trends in the northern area of Pouce Coupe; and (ii) Birchcliff’s focus on extracting more high-value NGLs in 2020 from its natural gas stream.
• Total light and medium crude oil and NGLs weighting of its proved developed producing, proved and proved plus probable reserves increased to 22%, 16% and 18% of total reserves in each category, respectively.
• The estimated net present value at December 31, 2020 (before income taxes, discounted at 10%) was $1.9 billion for Birchcliff’s proved developed producing reserves (December 31, 2019: $1.9 billion), $3.7 billion for its proved reserves (December 31, 2019: $4.1 billion) and $4.8 billion for its proved plus probable reserves (December 31, 2019: $5.3 billion).
• The net asset value of Birchcliff’s proved developed producing reserves at December 31, 2020, before income taxes discounted at 10% and after deducting total debt and the redemption value of the Corporation’s outstanding Series A and Series C preferred shares, is estimated to be $3.83 per common share, which is 43% above the closing trading price of its common shares of $2.68 on February 9, 2021.
• The following table sets forth Birchcliff’s net asset value for its proved developed producing, total proved and total proved plus probable reserves at December 31, 2020:

² Consists of approximately 1,616 Mbbls of light oil, 2,132 Mbbls of condensate, 2,800 Mbbls of NGLs and 128,491 MMcf of natural gas.

	Proved Developed Producing			Total Proved			Total Proved Plus Probable
P&NG reserves, NPV10% before income taxes ($000s)(1)		1,869,446			3,736,237			4,831,693
Total debt ($000s)		(761,951	)		(761,951	)		(761,951	)
Preferred shares ($000s)(2)		(89,930	)		(89,930	)		(89,930	)
Net asset value ($000s)(3)		1,017,565			2,884,356			3,979,812
Net asset value (per share)(3)(4)(5)	$	3.83		$	10.85		$	14.96

^{(1)   Represents the net present values of the future net revenue of Birchcliff’s proved developed producing, total proved and total proved plus probable reserves, as applicable, as estimated by Deloitte LLP (“Deloitte”) at December 31, 2020 using forecast prices and costs. Includes Deloitte’s estimate of the net present value of Birchcliff’s abandonment and reclamation costs.
(2)   Represents the redemption value of Series A and Series C preferred shares.
(3)   Excludes any value from undeveloped land, seismic and unexercised securities.
(4)   Based on 265.9 million common shares outstanding at December 31, 2020.
(5)   See “Advisories – Oil and Gas Metrics” for a description of the methodology used to calculate net asset value.}

• Reserves life index of 7.2 years on a proved developed producing basis, 24.2 years on a proved basis and 36.1 years on a proved plus probable basis, based on a forecast production rate of 79,000 boe/d (which represents the mid-point of Birchcliff’s annual average production guidance range for 2021).
• During 2020, Birchcliff’s F&D capital expenditures were $288.0 million, which included $74.8 million of facilities and infrastructure capital spent in 2020 that did not result in the addition of proved developed producing reserves at year-end 2020. FD&A capital expenditures were $275.1 million in 2020.
• The following table sets forth Birchcliff’s F&D costs and FD&A costs per boe for its proved developed producing, total proved and total proved plus probable reserves for 2020, 2019 and 2018, including FDC:

($/boe)(1)	2020(2)			2019(3)			2018(4)			3-Year Average
F&D – Proved Developed Producing	$	10.16		$	8.65		$	8.75		$	9.15
FD&A – Proved Developed Producing	$	9.95		$	9.38		$	8.75		$	9.32
F&D – Proved	$	7.08		$	7.84		$	0.64		$	4.58
F&D – Proved Plus Probable	$	6.66		$	6.22		$	1.27		$	4.70
FD&A – Proved	$	6.57		$	8.71		$	0.45		$	4.69
FD&A – Proved Plus Probable	$	6.44		$	7.25		$	1.47		$	4.87

^{(1)   See “Advisories – Oil and Gas Metrics” for a description of the methodology used to calculate F&D and FD&A costs.
(2)   Reflects the 2020 decrease in FDC from 2019 of $157.0 million on a proved basis and $41.8 million on a proved plus probable basis.
(3)   Reflects the 2019 increase in FDC from 2018 of $118.8 million on a proved basis and $127.0 million on a proved plus probable basis.
(4)   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.}

• The following table sets forth Birchcliff’s recycle ratios, on an operating and adjusted funds flow netback basis, for its proved developed producing, total proved and total proved plus probable reserves for 2020 and 2019, including FDC:

	Operating Netback Recycle Ratio(1)(2)		Adjusted Funds Flow Netback Recycle Ratio(1)(3)
	2020	2019	2020	2019
F&D – Proved Developed Producing	1.0	1.5	0.6	1.4
FD&A – Proved Developed Producing	1.0	1.4	0.7	1.3
F&D – Proved	1.5	1.7	0.9	1.5
FD&A – Proved	1.6	1.5	1.0	1.3
F&D – Proved Plus Probable	1.6	2.1	1.0	1.9
FD&A – Proved Plus Probable	1.6	1.8	1.0	1.6

^{(1)   See “Advisories – Oil and Gas Metrics” for a description of the methodology used to calculate recycle ratios.
(2)   Birchcliff’s operating netback was $10.37/boe in 2020, as compared to $13.07/boe in 2019.
(3)   Birchcliff’s adjusted funds flow netback was $6.60/boe in 2020, as compared to $11.75/boe in 2019.}

• Due to the unprecedented effects of the COVID-19 pandemic, the Corporation believes that its 2020 adjusted funds flow netback does not properly reflect the future profitability of the proved developed producing reserves added in 2020. Birchcliff anticipates that as a result of improved commodity prices, the Corporation’s netbacks and recycle ratios will improve in 2021 to be more comparable to its historical recycle ratios prior to COVID-19.

Operations Update

Birchcliff currently has 3 drilling rigs at work, consisting of 2 rigs drilling a 10-well pad in Pouce Coupe and 1 rig drilling a 4-well pad in Gordondale.

Birchcliff has successfully completed its 7-well 04-04 pad in Pouce Coupe, which was drilled in late Q4 2020 and early January 2021. Flowback operations have commenced to achieve stabilized production rates prior to installing permanent production facilities. The majority of the wells on the pad are expected to be onstream in mid-March 2021. Six wells on the 04-04 pad were drilled in the Basal Doig interval, offsetting recent successful third-party drilling results, and one well was drilled in the Montney D1 interval, offsetting several of Birchcliff’s existing high-productivity, low-cost natural gas wells. Production from the 04-04 pad will flow into Birchcliff’s existing owned and operated infrastructure.

Q4 AND FULL-YEAR 2020 UNAUDITED FINANCIAL AND OPERATIONAL RESULTS

Production

Birchcliff’s production averaged 78,649 boe/d in Q4 2020, which was a 1% increase from Q4 2019 and within its guidance of 78,000 to 79,000 boe/d. Birchcliff’s full-year 2020 production averaged 76,401 boe/d, a 2% decrease from 77,977 boe/d in 2019 and within its guidance of 76,000 to 77,000 boe/d. Birchcliff’s Q4 2020 and full-year 2020 production was positively impacted by new horizontal light oil and condensate-rich natural gas wells brought on production in 2020, including incremental production from the 14‐well pad brought on production in Pouce Coupe in Q3 2020 and negatively impacted by natural production declines and the ongoing impacts of frac driven interaction. Additionally, in order to manage the higher condensate and frac water flowback volumes associated with the 14‐well pad, Birchcliff proactively and temporarily restricted production of existing wells in Pouce Coupe during Q3 2020, which negatively impacted Q4 2020 and full-year 2020 production.

Liquids accounted for approximately 24% of Birchcliff’s total production in Q4 2020, as compared to approximately 22% in Q4 2019, with total liquids production increasing by 8% from Q4 2019. For full-year 2020, liquids accounted for approximately 23% of Birchcliff’s total production, as compared to approximately 22% in 2019. Total liquids production for full-year 2020 increased by 4% from 2019. The change in the commodity production mix was primarily due to incremental production from new liquids-rich natural gas wells brought on production in 2020.

Adjusted Funds Flow

Birchcliff’s adjusted funds flow for Q4 2020 was $66.5 million, or $0.25 per basic common share, an 18% decrease and a 17% decrease, respectively, from $80.9 million and $0.30 per basic common share in Q4 2019. Birchcliff’s full-year 2020 adjusted funds flow was $184.5 million, or $0.69 per basic common share, each a 45% decrease from $334.5 million and $1.26 per basic common share in 2019. Full-year 2020 adjusted funds flow was below Birchcliff’s guidance of $195 million primarily due to a lower than anticipated average realized natural gas sales price in Q4 2020.

The decrease in adjusted funds flow from the comparative prior periods was primarily due to lower reported revenue and a realized loss on financial instruments recorded in Q4 2020 and full-year 2020. Revenue decreased largely due to a 24% decrease in the average realized light oil and condensate sales price (combined) in Q4 2020 and a 33% decrease in full-year 2020, as compared to the comparative prior periods. Birchcliff’s light oil and condensate sales revenue in 2020 was negatively impacted by the significant weakness and volatility in benchmark oil prices as a result of the COVID-19 pandemic and ensuing global demand destruction.

Birchcliff recorded a realized loss on financial instruments of $11.8 million in Q4 2020 and $59.7 million in full-year 2020, as compared to a realized loss on market diversification financial contracts of $6.6 million in Q4 2019 and a realized gain on market diversification financial contracts of $13.7 million in full-year 2019. Birchcliff’s realized gains and losses on financial instruments were primarily due to the settlement of NYMEX/AECO basis swap contracts in the periods indicated.

Adjusted funds flow in Q4 2020 and full-year 2020 was also negatively impacted by higher interest and transportation and other expenses, and positively impacted by lower royalty, operating and G&A expenses.

Net Income (Loss) to Common Shareholders

Birchcliff recorded net income to common shareholders of $40.4 million, or $0.15 per basic common share, in Q4 2020, as compared to a net loss to common shareholders of $19.0 million and $0.07 per basic common share in Q4 2019. The change to a net income position was primarily due to an unrealized after-tax mark‐to‐market gain on financial instruments of $32.5 million in Q4 2020, as compared to an unrealized after-tax mark-to-market loss of $35.9 million in Q4 2019, partially offset by lower adjusted funds flow in Q4 2020 as described above.

Birchcliff recorded a net loss to common shareholders of $62.0 million, or $0.23 per basic common share, in full-year 2020, as compared to a net loss to common shareholders of $59.6 million and $0.22 per basic common share in 2019. The increase in net loss was primarily due to lower adjusted funds flow as described above, partially offset by a lower unrealized after-tax mark-to-market loss on financial instruments. Birchcliff recorded an unrealized after-tax mark‐to‐market loss on financial instruments of $26.5 million in 2020, as compared to an unrealized after-tax mark-to-market loss of $148.4 million in 2019. Birchcliff’s unrealized gains and losses for the periods indicated were due to changes in the fair value of its market diversification financial contracts. The changes in the fair value of market diversification financial contracts were primarily due to: (i) fluctuations in the forward basis spread between NYMEX HH and AECO 7A contracts outstanding at December 31, 2020, as compared to the fair value previously assessed at September 30, 2020 and December 31, 2019; and (ii) the settlement of financial NYMEX/AECO basis swap contracts in the periods.

Operating Expense

The Corporation remained focused on reducing its operating costs in 2020, resulting in an operating expense of $3.03/boe in Q4 2020, a 1% decrease from $3.06/boe in Q4 2019, and record low operating expense for full-year 2020 of $2.95/boe, a 5% decrease from $3.09/boe in 2019. Birchcliff’s full-year annual operating expense was within its guidance of $2.85/boe to $3.05/boe. The decreases were primarily due to various field optimization and cost saving initiatives in Pouce Coupe and Gordondale, which included the Corporation’s expanded liquids‐handling capabilities in Pouce Coupe.

Operating Netback

Birchcliff’s operating netback was $13.01/boe in Q4 2020, a 9% decrease from $14.25/boe in Q4 2019. Birchcliff’s full-year 2020 operating netback was $10.37/boe, a 21% decrease from $13.07/boe in 2019. The decreases were primarily due to lower average realized light oil and condensate sales prices in 2020.

Total Cash Costs

Birchcliff’s total cash costs were $11.18/boe in Q4 2020, a 4% increase from $10.80/boe in Q4 2019. The increase was primarily due to higher per boe interest and transportation and other expenses, partially offset by lower per boe operating, royalty and G&A expenses. Birchcliff’s full-year 2020 total cash costs of $10.34/boe were comparable to $10.31/boe in 2019.

Pouce Coupe Gas Plant Netbacks

During 2020, Birchcliff processed 68% of its total corporate natural gas production and 59% of its total corporate production through its 100% owned and operated natural gas processing plant in Pouce Coupe (the “Pouce Coupe Gas Plant”), as compared to 72% and 62%, respectively, during 2019. 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:

		2020						2019
Average production:
Condensate (bbls/d)					4,284						3,801
NGLs (bbls/d)					1,156						934
Natural gas (Mcf/d)					239,419						263,108
Total (boe/d)					45,343						48,587
Liquids-to-gas ratio(1) (bbls/MMcf)					22.7						18.0
Netback and cost:	$/Mcfe			$/boe			$/Mcfe			$/boe
Petroleum and natural gas revenue(2)		3.05			18.29			3.20			19.17
Royalty expense		(0.06	)		(0.37	)		(0.07	)		(0.42	)
Operating expense(3)		(0.36	)		(2.14	)		(0.34	)		(2.05	)
Transportation and other expense		(0.88	)		(5.27	)		(0.76	)		(4.54	)
Operating netback	$	1.75		$	10.51		$	2.03		$	12.16
Operating margin(4)		57	%		57	%		63	%		63	%

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

Birchcliff’s liquids-to-gas ratio increased by 26% as compared to 2019 primarily due to: (i) the completion of Birchcliff’s inlet liquids‐handling facility at the Pouce Coupe Gas Plant (the “Inlet Liquids‐Handling Facility”); and (ii) the addition of the condensate‐rich 14‐well pad brought on production in Pouce Coupe in Q3 2020.

Debt

Birchcliff has sufficient liquidity from its credit facilities which have an aggregate principal amount of $1.0 billion and are comprised of an extendible revolving syndicated term credit facility of $900.0 million and an extendible revolving working capital facility of $100.0 million. Birchcliff’s credit facilities do not contain any financial maintenance covenants and do not mature until May 11, 2022.

At December 31, 2020, Birchcliff had long-term bank debt of $731.4 million (December 31, 2019: $609.2 million) from available credit facilities of $1.0 billion (December 31, 2019: $1.0 billion), leaving $263.2 million of unutilized credit capacity after adjusting for outstanding letters of credit and unamortized interest and fees. Total debt at December 31, 2020 was $762.0 million, as compared to $632.6 million at December 31, 2019, which was slightly above Birchcliff’s guidance of $740 to $760 million, primarily due to the redemption of $9.1 million of Series C preferred shares in December 2020 and a lower than anticipated average realized natural gas sales price in Q4 2020.

Commodity Prices

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

	Three months ended December 31,				Twelve months ended December 31,
	2020	2019	% Change		2020	2019	% Change
Light oil – WTI Cushing (US$/bbl)	42.57	56.96	(25	)%	38.91	57.03	(32	)%
Light oil – MSW (Mixed Sweet) (CDN$/bbl)	49.57	67.66	(27	)%	43.52	68.72	(37	)%
Natural gas – NYMEX HH (US$/MMBtu)(1)	2.66	2.50	6	%	2.08	2.63	(21	)%
Natural gas – AECO 5A Daily (CDN$/GJ)	2.50	2.35	6	%	2.11	1.67	26	%
Natural gas – AECO 7A Month Ahead (US$/MMBtu)(1)	2.10	1.77	19	%	1.68	1.22	38	%
Natural gas – Dawn Day Ahead (US$/MMBtu)(1)	2.30	2.23	3	%	1.88	2.40	(22	)%
Natural gas – ATP 5A Day Ahead (CDN$/GJ)	2.78	1.92	45	%	2.05	1.66	23	%
Exchange rate (CDN$ to US$1)	1.3035	1.3201	(1	)%	1.3413	1.3269	1	%
Exchange rate (US$ to CDN$1)	0.7672	0.7575	1	%	0.7455	0.7536	(1	)%

^{(1)   See “Advisories – MMBtu Pricing Conversions”.}

Marketing and Natural Gas Market Diversification

Birchcliff’s physical natural gas sales exposure primarily consists of the AECO, Dawn and Alliance markets. In addition, the Corporation has various financial instruments outstanding that provide it with exposure to NYMEX HH pricing.

The following table details Birchcliff’s effective sales, production and average realized sales price for natural gas and liquids for Q4 2020, after taking into account the Corporation’s financial instruments:

Three months ended December 31, 2020
	Effective sales (CDN$000s)	Percentage of total sales (%)	Effective production (per day)	Percentage of total natural gas production (%)	Percentage of total corporate production (%)	Effective average realized sales price (CDN$)
Markets
AECO(1)	13,420	10	52,096 Mcf	15	11	2.80/Mcf
Dawn(2)	44,785	30	159,071 Mcf	44	33	3.06/Mcf
Alliance(3)	7,952	5	28,951 Mcf	8	6	2.99/Mcf
NYMEX HH(1)	20,904	14	120,721 Mcf	33	26	1.88/Mcf
Total natural gas	87,061	59	360,839 Mcf	100	76	2.62/Mcf
Light oil	16,261	11	3,566 bbls		5	49.56/bbl
Condensate	32,406	22	6,658 bbls		8	52.90/bbl
NGLs	12,320	8	8,285 bbls		11	16.16/bbl
Total liquids	60,987	41	18,509 bbls		24	35.82/bbl
Total corporate	148,048	100	78,649 boe		100	20.46/boe

^{(1)   A portion of AECO 5A sales and production that effectively received NYMEX HH pricing under Birchcliff’s long-term physical and financial NYMEX/AECO 7A basis swap contracts has been included as effective sales and production in NYMEX HH markets. Birchcliff sold financial and physical AECO 7A basis swaps for 132,500 MMBtu/d at an average contract price of NYMEX HH less US$1.234/MMBtu during Q4 2020.
(2)   Birchcliff has agreements for the firm service transportation of an aggregate of 175,000 GJ/d of natural gas on TCPL’s Canadian Mainline, whereby natural gas is transported to the Dawn trading hub in Southern Ontario.
(3)   Birchcliff has sales agreements with third party marketers to sell and deliver into the Alliance pipeline system. Alliance sales are recorded net of transportation tolls.}

Effectively 90% of the Corporation’s sales revenue, representing 85% of its total natural gas production and 89% of its total corporate production, was generated from markets outside of AECO in Q4 2020, after taking into account its liquids sales and long-term financial NYMEX/AECO basis swap position.

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

Three months ended December 31, 2020
	Natural gas sales(1) (CDN$000s)	Percentage of natural gas sales (%)	Natural gas production (Mcf/d)	Percentage of natural gas production (%)	Average realized natural gas sales price(1) (CDN$/Mcf)	Natural gas transportation costs(2) (CDN$/Mcf)	Natural gas sales netback(3) (CDN$/Mcf)
AECO	44,556	46	172,817	48	2.80	0.39	2.41
Dawn	44,785	46	159,071	44	3.06	1.42	1.64
Alliance(4)	7,952	8	28,951	8	2.99	–	2.99
Total	97,293	100	360,839	100	2.93	0.81	2.12
Three months ended December 31, 2019
	Natural gas sales(1) (CDN$000s)	Percentage of natural gas sales (%)	Natural gas production (Mcf/d)	Percentage of natural gas production (%)	Average realized natural gas sales price(1) (CDN$/Mcf)	Natural gas transportation costs(2) (CDN$/Mcf)	Natural gas sales netback(3) (CDN$/Mcf)
AECO	48,976	52	204,461	56	2.60	0.34	2.26
Dawn	43,706	46	152,115	42	3.12	1.37	1.75
Alliance(4)	1,507	2	8,271	2	1.98	–	1.98
Total	94,189	100	364,847	100	2.81	0.77	2.04

^{(1)   Excludes the effects of financial instruments but includes the effects of physical delivery contracts.
(2)   Reflects costs to transport natural gas from the field receipt point to the delivery sales trading hub.
(3)   Natural gas sales netback denotes the average realized natural gas sales price less natural gas transportation costs.
(4)   Alliance sales are recorded net of transportation tolls.}

Capital Activities and Investment

The 2020 Capital Program was focused on the drilling of high-value light oil wells in Gordondale and low-cost condensate-rich natural gas wells in Pouce Coupe. In addition, the Corporation completed the 20,000 bbls/d (50% condensate, 50% water) Inlet Liquids-Handling Facility and directed funds towards other infrastructure enhancement projects. The 2020 Capital Program was strategically front-end loaded resulting in a more efficient capital spending and production profile during the year. This allowed Birchcliff to realize numerous capital cost savings and bring new wells on production relatively early in the year, optimizing producing days in the year for the capital spent.

Total capital expenditures for 2020 were $276.8 million, which included F&D capital expenditures of $288.0 million as well as a non-core disposition in Q4 2020. F&D capital expenditures for full-year 2020 were in line with Birchcliff’s guidance of $285 million.

DCCET Activities

During 2020, Birchcliff drilled 34 (34.0 net) horizontal wells, 6 (6.0 net) of which were drilled in Q4 2020 to help ensure the efficient execution of the 2021 Capital Program. The Corporation brought on production 34 (34.0 net) wells during 2020, including 6 (6.0 net) wells that were drilled in Q4 2019. All wells drilled in 2020 were drilled on multi-well pads, allowing Birchcliff to reduce its per well costs and environmental footprint. The following table summarizes the number of wells Birchcliff drilled and brought on production in 2020:

Area			Total wells drilled in 2020	Total wells brought on production in 2020(1)
Pouce Coupe
	Montney D1 horizontal natural gas wells		4	4
	Montney D2 horizontal natural gas wells		9	12
	Montney C horizontal natural gas wells		7	8
	Basal Doig horizontal natural gas wells		6	0
	Total – Pouce Coupe		26	24
Gordondale
		Montney D1 horizontal oil wells	4	5
		Montney D2 horizontal oil wells	4	4
		Montney D4 horizontal oil wells	0	1
		Total – Gordondale	8	10
TOTAL – COMBINED			34	34

^{(1)   Does not include the 6 additional wells drilled in Q4 2020 as none of these wells were brought on production in 2020. The 2020 Capital Program included the capital associated with 6 Montney/Doig wells that were drilled in Q4 2019 and subsequently brought on production in 2020.}

Pouce Coupe

Key focus areas for Pouce Coupe in 2020 were the drilling of condensate-rich natural gas wells and the further exploitation and delineation of condensate-rich trends in the Montney D1, D2 and C intervals.

In Pouce Coupe, the Corporation drilled 26 (26.0 net) wells and brought 24 (24.0 net) wells on production. The wells were drilled on four multi-well pads as described below:

• 06-32-078-12W6 (4-well pad): An existing pad site where Birchcliff drilled 2 wells in Q4 2019 and 2 wells in Q1 2020. All of these wells were drilled in the Montney D2 interval and were brought on production in late Q1 2020.
• 14-06-079-12W6 (6-well pad): An existing pad site where Birchcliff drilled 2 wells in Q4 2019 and 4 wells in Q1 2020. These 6 wells were drilled in 2 different intervals (3 in the Montney D2 and 3 in the Montney C) and were all brought on production in Q2 2020.
• 14-19-079-12W6 (14-well pad): This 14-well pad used multi-interval cube-style development to maximize operational efficiencies through scale and repeatability, which led to substantial cost savings on a per well basis. The pad is adjacent to the successful condensate-rich wells drilled by Birchcliff in 2019 in the Montney D1, D2 and C intervals at its 14-06-079-12W6 pad. The 14 wells were drilled in 3 different intervals (5 in the Montney D1, 4 in the Montney D2 and 5 in the Montney C). The pad utilized two fit-for-purpose walking style drilling rigs which each drilled 7 wells. Utilizing two drilling rigs allowed for significant shared service-related synergies and resulted in a more efficient cycle time and cost savings. Significant cost saving were also realized during the completion of this pad due to economies of scale and minimal non-productive time. Birchcliff collected high-value diagnostic data that is expected to further improve the next round of multi-interval cube-style development planned for 2021. The results from the 14-well pad demonstrate the extension of the Gordondale light oil pool into the northeastern area of Pouce Coupe, which provides the Corporation with significantly more potential condensate/light oil drilling opportunities.
• 04-04-78-13W6 (7-well pad): Birchcliff drilled 6 of 7 wells on this pad in Q4 2020 in order to help ensure the efficient execution of the Corporation’s 2021 Capital Program. This pad consists of 6 wells in the Basal Doig interval and one well in the Montney D1 interval, which was rig released in early 2021. Flowback operations have commenced on the wells to achieve stabilized production rates prior to installing permanent production facilities. The majority of the wells on the pad are expected to be onstream in mid-March 2021.

At the Pouce Coupe Gas Plant, the Inlet Liquids-Handling Facility was brought on-stream in late July 2020. This facility was completed ahead of schedule and under budget and it represents an important milestone for Birchcliff as it gives the Corporation the ability to optimize its condensate and NGLs product streams and pricing, as well as grow its condensate production in Pouce Coupe to approximately 10,000 bbls/d.

Gordondale

Key focus areas for Gordondale in 2020 were the drilling of crude oil wells and the further exploitation and delineation of oil in the Montney D1 and D2 intervals, specifically in the southeastern part of the Gordondale field.

In Gordondale, the Corporation drilled 8 (8.0 net) wells and brought 10 (10.0 net) wells on production. Birchcliff used multi-interval cube-style development to drill the 10 wells, using two drilling rigs on two proximal pads targeting the Montney D1, D2 and D4 intervals. Two wells were drilled in Q4 2019 and the remaining 8 wells were drilled in Q1 2020.

• 06-35-077-11W6 (4-well pad): Birchcliff drilled 4 wells on this pad in Q1 2020. These 4 wells were drilled in 2 different intervals (2 in the Montney D1 and 2 in the Montney D2) and were all brought on production in Q2 2020.
• 02-02-078-11W6 (6-well pad): Birchcliff drilled 6 wells on this pad, which is adjacent to an existing pad site. Two of the wells were drilled in Q4 2019 and 4 wells were drilled in Q1 2020. These 6 wells were drilled in 3 different intervals (3 in the Montney D1, 2 in the Montney D2 and 1 in the Montney D4). All of the wells were brought on production in Q2 2020.

In Gordondale, Birchcliff completed the addition of natural gas compression at both of its 100% owned and operated oil batteries and the construction of its significant trunk line to transport oil, natural gas and water to these batteries from the southeastern portion of the field. Both projects were completed in Q2 2020. The addition of natural gas compression at both batteries allows the existing wells to produce against lower wellhead pressures, which in turn has increased production rates. The addition of the new trunk line allows the compression to become even more effective and handle both the new and existing volumes in the area.

2020 YEAR-END RESERVES

Birchcliff retained Deloitte, independent qualified reserves evaluator, to evaluate and prepare a report on 100% of Birchcliff’s light crude oil and medium crude oil, conventional natural gas, shale gas and NGLs reserves. The reserves data set forth below at December 31, 2020 is based upon the evaluation by Deloitte with an effective date of December 31, 2020 as contained in the report of Deloitte dated February 10, 2021 (the “2020 Deloitte Reserves Report”). The forecast commodity prices, inflation and exchange rates utilized were computed using the average of forecasts from Deloitte, McDaniel & Associates Consultants Ltd. (“McDaniel”), GLJ Petroleum Consultants Ltd. and Sproule Associates Ltd. effective January 1, 2021 (the “2020 IQRE Price Forecast”).

The 2020 Deloitte Reserves Report has been 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”).

For additional information regarding the presentation of Birchcliff’s reserves disclosure contained herein, see “Presentation of Oil and Gas Reserves” and “Advisories” in this press release. The reserves data provided in this press release presents only a portion of the disclosure required under NI 51-101. The disclosure required under NI 51-101 will be contained in Birchcliff’s Annual Information Form for the year ended December 31, 2020, which is expected to be filed on the System for Electronic Document Analysis and Retrieval (www.sedar.com) on March 10, 2021. 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, 2020 and December 31, 2019, 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, 2020 (Mboe)	December 31, 2019(1) (Mboe)	Change from December 31, 2019
Proved Developed Producing	206,605.6	206,922.4	–
Total Proved	699,066.8	709,061.2	(1	)%
Total Probable	341,410.1	323,133.5	6	%
Total Proved Plus Probable	1,040,476.9	1,032,194.7	1	%

^{(1)   Deloitte prepared an evaluation with an effective date of December 31, 2019 as contained in the report of Deloitte dated February 12, 2020 (the “2019 Deloitte Reserves Report”) and McDaniel prepared an evaluation with an effective date of December 31, 2019 as contained in the report of McDaniel dated February 12, 2020 (the “2019 McDaniel Reserves Report”), which are contained in the consolidated report of Deloitte with an effective date of December 31, 2019 (the “2019 Consolidated Reserves Report”). Deloitte prepared the 2019 Consolidated Reserves Report by consolidating the properties evaluated by Deloitte in the 2019 Deloitte Reserves Report with the properties evaluated by McDaniel in the 2019 McDaniel Reserves Report, in each case using the average of forecasts from Deloitte, McDaniel, GLJ Petroleum Consultants Ltd. and Sproule Associates Ltd. effective January 1, 2020 (the “2019 IQRE Price Forecast”).}

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, 2020, estimated using the 2020 IQRE Price Forecast:

Summary of Reserves at December 31, 2020
(Forecast Prices and Costs)

			Light Crude Oil and Medium Crude Oil				Conventional Natural Gas				Shale Gas				NGLs(1)				Total Boe
Reserves Category			Gross (Mbbls)		Net (Mbbls)		Gross (MMcf)		Net (MMcf)		Gross (MMcf)		Net (MMcf)		Gross (Mbbls)		Net (Mbbls)		Gross (Mboe)		Net (Mboe)
Proved
Developed Producing			9,290.7		8,056.8		5,095.3		4,729.1		958,123.9		903,152.6		36,778.3		30,248.4		206,605.6		189,618.8
Developed Non-Producing			54.3		51.6		988.8		931.2		21,037.6		19,841.1		345.2		280.3		4,070.6		3,793.9
Undeveloped			10,223.0		9,113.8		2,379.1		2,260.2		2,530,366.6		2,380,312.2		56,043.3		47,724.2		488,390.6		453,933.3
Total Proved			19,568.0		17,222.2		8,463.2		7,920.4		3,509,528.1		3,303,305.9		93,166.8		78,252.8		699,066.8		647,346.1
Total Probable			11,776.1		9,867.4		5,268.9		4,842.9		1,619,891.4		1,508,888.9		58,774.0		48,392.8		341,410.1		310,548.9
Total Proved Plus Probable			31,344.1		27,089.6		13,732.1		12,763.3		5,129,419.6		4,812,194.8		151,940.8		126,645.7		1,040,476.9		957,895.0

^{(1)   NGLs includes condensate.}

Net Present Values of Future Net Revenue

The following table sets forth the net present values of future net revenue attributable to Birchcliff’s reserves at December 31, 2020, estimated using the 2020 IQRE Price Forecast, before deducting future income tax expenses and calculated at various discount rates:

Summary of Net Present Values of Future Net Revenue at December 31, 2020⁽¹⁾
(Forecast Prices and Costs)

Reserves Category	Before Income Taxes Discounted At (%/year)
		0 (M$)		5 (M$)		10 (M$)		15 (M$)		20 (M$)		Unit Value Discounted at 10%/year ($/boe)(2)
Proved
Developed Producing		3,094,004.5		2,362,268.1		1,869,445.8		1,543,544.0		1,318,157.9		9.86
Developed Non-Producing		62,025.0		39,061.4		27,018.9		19,833.2		15,142.9		7.12
Undeveloped		6,360,779.8		3,318,292.6		1,839,771.8		1,044,033.6		582,054.5		4.05
Total Proved		9,516,809.3		5,719,622.0		3,736,236.5		2,607,410.8		1,915,355.3		5.77
Total Probable		5,657,841.5		2,320,228.0		1,095,456.1		578,697.4		334,170.2		3.53
Total Proved Plus Probable		15,174,650.8		8,039,850.0		4,831,692.5		3,186,108.2		2,249,525.6		5.04

^{(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 volumes.}

Pricing Assumptions

The following table sets forth the 2020 IQRE Price Forecast used in the 2020 Deloitte Reserves Report:

2020 IQRE Price Forecast

Year		Crude Oil				Natural Gas(1)						NGLs								Currency Exchange Rate (US$/CDN$)		Price and Cost Inflation Rates (%)
		WTI at Cushing Oklahoma (US$/bbl)		Edmonton City Gate (CDN$/bbl)		Alberta AECO Average Price (CDN$/Mcf)		Ontario Dawn Reference Point (CDN$/Mcf)		NYMEX Henry Hub (US$/Mcf)		Edmonton Ethane (CDN$/bbl)		Edmonton Propane (CDN$/bbl)		Edmonton Butane (CDN$/bbl)		Edmonton Pentanes + Condensate (CDN$/bbl)
2021		46.88		55.13		2.75		3.47		2.80		8.51		18.30		25.76		57.75		0.77		0.0
2022		51.14		60.62		2.70		3.55		2.87		8.35		23.49		33.27		63.10		0.77		1.5
2023		54.83		64.68		2.65		3.61		2.93		8.16		26.11		40.49		67.58		0.77		2.0
2024		56.48		66.73		2.69		3.67		3.00		8.28		26.94		41.80		69.74		0.77		2.0
2025		57.62		68.11		2.74		3.75		3.05		8.45		27.50		42.66		71.15		0.77		2.0
2026		58.77		69.52		2.81		3.80		3.11		8.62		28.07		43.55		72.58		0.77		2.0
2027		59.94		70.95		2.86		3.90		3.17		8.79		28.64		44.44		74.04		0.77		2.0
2028		61.14		72.40		2.91		3.96		3.24		8.98		29.23		45.36		75.52		0.77		2.0
2029		62.36		73.89		2.97		4.05		3.30		9.16		29.82		46.28		77.03		0.77		2.0
2030		63.61		75.37		3.02		4.12		3.36		9.34		30.42		47.21		78.58		0.77		2.0
2031		64.89		76.88		3.09		4.20		3.43		9.53		31.03		48.16		80.16		0.77		2.0
2032		66.18		78.42		3.15		4.30		3.50		9.72		31.65		49.13		81.76		0.77		2.0
2033		67.50		79.98		3.21		4.40		3.57		9.91		32.29		50.11		83.39		0.77		2.0
2034		68.86		81.59		3.28		4.46		3.64		10.11		32.93		51.10		85.06		0.77		2.0
2035		70.23		83.21		3.34		4.55		3.72		10.32		33.59		52.13		86.75		0.77		2.0
2036		71.64		84.88		3.40		4.65		3.78		10.51		34.25		53.17		88.49		0.77		2.0
2037		73.07		86.57		3.48		4.74		3.87		10.72		34.94		54.23		90.26		0.77		2.0
2038		74.53		88.31		3.54		4.84		3.94		10.94		35.65		55.31		92.08		0.77		2.0
2039		76.01		90.07		3.62		4.94		4.02		11.17		36.36		56.42		93.91		0.77		2.0
2040		77.54		91.88		3.69		5.04		4.09		11.39		37.08		57.56		95.79		0.77		2.0
2041+		2.0%		2.0%		2.0%		2.0%		2.0%		2.0%		2.0%		2.0%		2.0%		0.77		2.0

^{(1)   1 Mcf = 1 MMBtu.}

Reconciliation of Changes in Reserves

The following table sets forth the reconciliation of Birchcliff’s gross reserves at December 31, 2020 as set forth in the 2020 Deloitte Reserves Report, estimated using the 2020 IQRE Price Forecast, to Birchcliff’s gross reserves at December 31, 2019 as set forth in the 2019 Consolidated Reserves Report, estimated using the 2019 IQRE Price Forecast:

Reconciliation of Gross Reserves from December 31, 2019 to December 31, 2020
(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, 2019		21,053.3		11,466.4		3,580,166.0		89,402.5		709,061.2
Extensions and Improved Recovery(1)		709.5		0.0		205,348.7		7,685.0		42,619.3
Technical Revisions(2)		(391.8	)	(914.9	)	(118,680.1	)	1,697.5		(18,626.8	)
Discoveries(3)		0.0		0.0		0.0		0.0		0.0
Acquisitions(4)		0.6		19.5		0.0		0.1		4.0
Dispositions(5)		(30.3	)	(623.3	)	(9,471.6	)	(197.8	)	(1,910.6	)
Economic Factors(6)		(157.4	)	(701.7	)	(20,126.8	)	(488.8	)	(4,117.7	)
Production(7)		(1,615.8	)	(782.9	)	(127,708.1	)	(4,931.6	)	(27,962.6	)
Closing balance December 31, 2020		19,568.0		8,463.2		3,509,528.1		93,166.8		699,066.8
GROSS TOTAL PROBABLE
Opening balance December 31, 2019		12,543.4		8,348.4		1,553,306.8		50,314.2		323,133.5
Extensions and Improved Recovery(1)		124.9		0.0		109,157.0		6,179.4		24,497.1
Technical Revisions(2)		(798.3	)	(294.3	)	(24,026.0	)	2,707.0		(2,144.7	)
Discoveries(3)		0.0		0.0		0.0		0.0		0.0
Acquisitions(4)		0.0		10.8		2,840.5		40.5		515.7
Dispositions(5)		(13.9	)	(102.7	)	(3,408.3	)	(68.6	)	(667.6	)
Economic Factors(6)		(80.0	)	(2,693.3	)	(17,978.6	)	(398.5	)	(3,923.8	)
Production(7)		0.0		0.0		0.0		0.0		0.0
Closing balance December 31, 2020		11,776.1		5,268.9		1,619,891.4		58,774.0		341,410.1
GROSS TOTAL PROVED PLUS PROBABLE
Opening balance December 31, 2019		33,596.8		19,814.8		5,133,472.7		139,716.7		1,032,194.7
Extensions and Improved Recovery(1)		834.3		0.0		314,505.7		13,864.4		67,116.4
Technical Revisions(2)		(1,190.2	)	(1,209.2	)	(142,706.1	)	4,404.5		(20,771.6	)
Discoveries(3)		0.0		0.0		0.0		0.0		0.0
Acquisitions(4)		0.6		30.3		2,840.5		40.6		519.7
Dispositions(5)		(44.2	)	(726.0	)	(12,879.9	)	(266.4	)	(2,578.2	)
Economic Factors(6)		(237.4	)	(3,394.9	)	(38,105.4	)	(887.4	)	(8,041.5	)
Production(7)		(1,615.8	)	(782.9	)	(127,708.1	)	(4,931.6	)	(27,962.6	)
Closing balance December 31, 2020		31,344.1		13,732.1		5,129,419.6		151,940.8		1,040,476.9

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

Key highlights include the following:

Extensions and Improved Recovery

Reserves were added due to the 34 wells that were brought on production pursuant to the Corporation’s successful 2020 Capital Program, which also resulted in the assignment of reserves to potential future drilling locations offsetting the new wells. In total, there were an additional 23 proved and 45 proved plus probable potential future drilling locations added, which had superior economic value at today’s commodity prices and therefore replaced several previously booked locations.

Technical Revisions

• The technical revisions in all reserves categories for light and medium crude oil were mainly a result of: (i) the positive performance of the existing producing oil wells after the installation of field infrastructure improvements in Gordondale; and (ii) future well location adjustments based on offsetting existing well performance, which had higher gas to oil ratios than forecasted last year.
• The technical revisions in all reserve categories for conventional natural gas were mainly the result of the suspension of a well in Elmworth.
• The technical revisions in all reserves categories for shale gas were mainly a result of: (i) the prioritized removal of 14 proved and 12 proved plus probable locations, which were replaced with potential future locations (extensions) that had superior reserves and economic value, or where the available plant capacity precluded their development within the time frame mandated by the COGE Handbook; (ii) increased gas shrinkage as a result of higher NGLs extraction in the Pouce Coupe Gas Plant and the AltaGas deep-cut sour gas processing facility in Gordondale (the “AltaGas Facility”); (iii) slight adjustments to the existing oil and gas wells and potential future oil and gas locations; and (iv) 7 proved and 9 proved plus probable locations that were removed due to field development plan changes.
• The technical revisions in all reserves categories for NGLs were mainly a result of: (i) increased condensate reserves from the 2020 drilling program and future locations in Pouce Coupe including the 14 well pad and offsetting potential future drilling locations in Pouce Coupe; and (ii) improved performance of the existing C3+ recoveries at the Pouce Coupe Gas Plant and the AltaGas Facility, notwithstanding the negative revision in shale gas reserves.

Acquisitions

Changes were the result of various minor acquisitions Birchcliff completed in the Pouce Coupe area in 2020.

Dispositions

Changes were the result of a non-core disposition Birchcliff completed in Gordondale in 2020.

Economic Factors

The forecast prices for each product type were generally lower in the 2020 IQRE Price Forecast than the 2019 IQRE Price Forecast, which resulted in the economic limit at the end of a well’s life being achieved earlier and therefore a reduction of the reserves volumes in all reserves categories. The reduced price forecast also resulted in the loss of reserves for 2 gross (2 net) proved undeveloped future shale gas locations, 4 gross (4 net) proved plus probable future shale gas locations and 1 gross (1 net) probable future conventional natural gas location, all in Elmworth, that did not generate a positive net present value at a 10% discount rate.

Future Development Costs

FDC reflects Deloitte’s 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$)		Proved Plus Probable (MM$)
2021	143.0		190.3
2022	552.3		552.9
2023	496.3		496.3
2024	691.3		726.7
2025	424.0		484.6
Thereafter	616.6		1,926.2
Total undiscounted	2,923.5		4,377.0

FDC for total proved reserves decreased by $157.0 million to $2.92 billion at December 31, 2020 from $3.08 billion at December 31, 2019. FDC for total proved plus probable reserves decreased by $41.8 million to $4.38 billion at December 31, 2020 from $4.42 billion at December 31, 2019. The decreases in FDC for both proved and proved plus probable reserves were largely due to: (i) the completion of the Inlet Liquids-Handling Facility and compressor installations and large trunk line in Gordondale; (ii) the removal of lower net present value future drilling locations related to the proved reserves as a result of the COGE Handbook mandated development time frame of 5 to 7 years within available plant capacity; and (iii) the removal of 2 gross (2 net) proved undeveloped future natural gas locations and 5 gross (5 net) proved plus probable future natural gas locations in Elmworth that were uneconomic.

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 $256 million (unescalated) for the continued expansion of the Pouce Coupe Gas Plant from the existing 340 MMcf/d to 660 MMcf/d of total throughput. The FDC for the expansions of the Pouce Coupe Gas Plant also include the costs of the related gathering pipelines and maintenance capital.

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

Average Well Cost		December 31, 2020 (MM$)		December 31, 2019 (MM$)
Pouce Coupe		4.7		4.7
Gordondale		5.4		5.4

Reserves Replacement

The following table sets forth Birchcliff’s 2020 reserves replacement ratios:

Reserves Category		2020 Reserves Replacement, Excluding the Effects of Acquisitions and Dispositions(1)			2020 Reserves Replacement, Including the Effects of Acquisitions and Dispositions(1)
Proved Developed Producing		101	%		99	%
Total Proved		71	%		64	%
Total Proved Plus Probable		137	%		130	%

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

Reserves Life Index

The following table sets forth Birchcliff’s 2020 reserves life index:

Reserves Category		2020 Reserves Life Index(1)
Proved Developed Producing		7.2 years
Total Proved		24.2 years
Total Proved Plus Probable		36.1 years

^{(1)   Based on a forecast production rate of 79,000 boe/d, which represents the mid-point of Birchcliff’s annual average production guidance range for 2021. 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 2020 Deloitte 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	2020	2019	2020	2019	2020	2019	2020	2019	2020	2019	2020	2019
Proved Developed Producing	947.8	969.2	9,261.6	9,620.4	35,888.7	31,793.7	203,108.6	202,945.5	437(3)	410	434.7(3)	403.2
Total Proved	3,491.9	3,567.2	19,538.8	20,978.7	92,137.2	88,638.2	693,661.2	704,152.4	958	953	952.6	939.3
Total Proved Plus Probable	5,106.3	5,117.5	31,309.4	33,502.5	150,528.0	138,737.4	1,032,883.8	1,025,152.8	1,219	1,199	1,206.6	1,175.1

^{(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, 2020, the estimated FDC for Birchcliff’s reserves on its Montney/Doig Resource Play is $0 on a proved developed producing basis (as compared to $12.6 million at December 31, 2019), $2,921.1 million on a proved basis (as compared to $3,077.6 million at December 31, 2019) and $4,371.5 million on a proved plus probable basis (as compared to $4,409.8 million at December 31, 2019).
(3)   Does not include three 100% working interest proved non-producing wells.}

POTENTIAL FUTURE DRILLING OPPORTUNITIES ON THE MONTNEY/DOIG RESOURCE PLAY

Birchcliff’s operations are primarily concentrated in its core areas of Pouce Coupe and Gordondale. At December 31, 2020, Birchcliff held 227.7 (214.1 net) sections of contiguous land that have potential for the Montney/Doig Resource Play in Pouce Coupe and Gordondale. The 2020 Deloitte Reserves Report attributed proved plus probable reserves to 769.0 potential net future horizontal drilling locations in Pouce Coupe and Gordondale. Based on Birchcliff’s five year plan (announced on January 20, 2021), the Corporation is targeting drilling 158 wells in the next five years to achieve average annual production of 91,000 boe/d in 2025. In addition, at December 31, 2020, Birchcliff had approximately 3,065 potential net future horizontal drilling locations in Pouce Coupe and Gordondale that have not had any proved or probable reserves attributed to them by Deloitte. Over the past few years, Birchcliff has worked diligently to divest non-core properties and to direct its production to the Pouce Coupe Gas Plant and the AltaGas Facility, resulting in over 99% of Birchcliff’s production being associated with Pouce Coupe and Gordondale at December 31, 2020.

Birchcliff also owns 169.5 (169.5 net) sections of land in the Elmworth area of Alberta with potential for the Montney/Doig Resource Play. At December 31, 2020, the Corporation has approximately 3,300 potential net future horizontal drilling locations in Elmworth that have not had any proved or probable reserves attributed to them by Deloitte. See “2020 Year-End Reserves” and “Advisories – Drilling Locations”.

ABBREVIATIONS

AECO	benchmark price for natural gas determined at the AECO ‘C’ hub in southeast Alberta
bbl	barrel
bbls	barrels
bbls/d	barrels per day
Bcf	billion cubic feet
boe	barrel of oil equivalent
boe/d	barrel of oil equivalent per day
C3+	propane plus
condensate	pentanes plus (C5+)
F&D	finding and development
FD&A	finding, development and acquisition
FDC	future development costs
G&A	general and administrative
GAAP	generally accepted accounting principles for Canadian public companies which are currently IFRS
GJ	gigajoule
GJ/d	gigajoules per day
HH	Henry Hub
IFRS	International Financial Reporting Standards as issued by the International Accounting Standards Board
Mbbls	thousand barrels
Mboe	thousand barrels of oil equivalent
Mcf	thousand cubic feet
Mcf/d	thousand cubic feet per day
Mcfe	thousand cubic feet of gas equivalent
M$	thousands of dollars
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
NPV	net present value
NYMEX	New York Mercantile Exchange
P&NG	petroleum and natural gas
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 basic common share”, “free funds flow”, “transportation and other expense”, “operating netback”, “adjusted funds flow netback”, “adjusted working capital deficit”, “total cash costs” 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 operating working capital and “adjusted funds flow per basic common share” denotes adjusted funds flow divided by the basic weighted average number of common shares outstanding for the period. Birchcliff eliminates 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 is managed with Birchcliff’s capital budgeting process which considers available adjusted funds flow. Changes in non-cash operating working capital are eliminated in the determination of adjusted funds flow as the timing of collection and payment are variable and by excluding them from the calculation, the Corporation believes that it is able to provide a more meaningful measure of its operations and ability to generate cash on a continuing basis. Management believes that adjusted funds flow and adjusted funds flow per common share assist management and investors in assessing Birchcliff’s operating performance, as well as its ability to generate cash necessary to fund sustaining and/or growth capital expenditures, repay debt, settle decommissioning obligations and pay common share and preferred share dividends. 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.

“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 further generate shareholder returns through a number of initiatives, including but not limited to, potential debt repayment, common share repurchases, future dividend increases and acquisitions.

The following table provides a reconciliation of cash flow from operating activities, as determined in accordance with GAAP, to adjusted funds flow and free funds flow for the periods indicated:

	Three months ended December 31,				Twelve months ended December 31,
($000s)	2020		2019		2020		2019
Cash flow from operating activities	71,431		85,557		188,180		327,066
Change in non-cash operating working capital	(6,269	)	(5,058	)	(5,977	)	5,153
Decommissioning expenditures	1,347		442		2,323		2,285
Adjusted funds flow	66,509		80,941		184,526		334,504
F&D capital expenditures	(41,291	)	(56,800	)	(287,967	)	(256,395	)
Free funds flow	25,218		24,141		(103,441	)	78,109

“Transportation and other expense” denotes transportation expense plus marketing purchases minus marketing revenue. Birchcliff may enter into certain marketing purchase and sales arrangements with the objective of reducing any available transportation and/or fractionation fees associated with its take-or-pay commitments. Management believes that transportation and other expense assists management and investors in assessing Birchcliff’s total cost structure related to transportation activities.

“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. 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 operating results by isolating the impact of production volumes 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,
	2020				2019				2020				2019
	($000s	)	($/boe	)	($000s	)	($/boe	)	($000s	)	($/boe	)	($000s	)	($/boe	)
Petroleum and natural gas revenue	158,283		21.88		164,759		22.97		528,505		18.90		613,559		21.56
Royalty expense	(6,522	)	(0.90	)	(8,263	)	(1.15	)	(18,204	)	(0.65	)	(27,452	)	(0.96	)
Operating expense	(21,942	)	(3.03	)	(21,977	)	(3.06	)	(82,357	)	(2.95	)	(87,903	)	(3.09	)
Transportation and other expense	(35,690	)	(4.94	)	(32,278	)	(4.51	)	(138,014	)	(4.93	)	(126,135	)	(4.44	)
Operating netback	94,129		13.01		102,241		14.25		289,930		10.37		372,069		13.07
G&A, net	(8,028	)	(1.11	)	(9,035	)	(1.26	)	(24,615	)	(0.88	)	(26,815	)	(0.94	)
Interest expense	(8,652	)	(1.20	)	(5,852	)	(0.82	)	(26,067	)	(0.93	)	(25,073	)	(0.88	)
Realized gain (loss) on financial instruments	(11,819	)	(1.63	)	(6,565	)	(0.92	)	(59,665	)	(2.13	)	13,673		0.48
Other income	879		0.12		152		0.03		4,943		0.17		650		0.02
Adjusted funds flow netback	66,509		9.19		80,941		11.28		184,526		6.60		334,504		11.75

The reconciliation for the operating netback of the Pouce Coupe Gas Plant is provided under the heading “Q4 and Full-Year 2020 Unaudited Financial and Operational Results – Pouce Coupe Gas Plant Netbacks”.

“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 current portion of financial instruments and capital securities. Management believes that adjusted working capital deficit assists management and investors in assessing Birchcliff’s short-term 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, 2020		December 31, 2019
Working capital deficit	93,988		100,199
Financial instrument – current liability	(23,479	)	(26,949	)
Capital securities – current liability	(39,930	)	(49,845	)
Adjusted working capital deficit	30,579		23,405

“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, 2020		December 31, 2019
Revolving term credit facilities	731,372		609,177
Adjusted working capital deficit	30,579		23,405
Total debt	761,951		632,582

PRESENTATION OF OIL AND GAS RESERVES

Deloitte prepared the 2019 Deloitte Reserves Report, the 2019 Consolidated Reserves Report and the 2020 Deloitte Reserves Report. McDaniel prepared the 2019 McDaniel Reserves Report. In addition, Deloitte and McDaniel prepared reserves evaluations in respect of Birchcliff’s oil and natural gas properties effective December 31, 2018. 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. 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, ultimate reserves recovery, the timing and amount of capital expenditures, 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 these reasons, estimates of the economically recoverable oil, natural gas and NGLs reserves attributable to any particular group of properties, the 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. Birchcliff’s actual production, revenue, 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 evaluator 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, unless otherwise stated all references to “reserves” are to Birchcliff’s gross company reserves (Birchcliff’s working interest (operating or non-operating) share before deduction of royalties and without including any royalty interests of Birchcliff).

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

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.