Birchcliff Energy Ltd. Announces Unaudited 2015 Year-End Financial Results and Material Reserves Additions and Provides an Operational Update

CALGARY, ALBERTA--(Marketwired - Feb. 10, 2016) -

NOT FOR DISTRIBUTION TO UNITED STATES NEWSWIRE SERVICES OR FOR DISSEMINATION IN THE UNITED STATES

Birchcliff Energy Ltd. ("Birchcliff") (BIR.TO) is pleased to announce its unaudited 2015 year-end and fourth quarter financial and operational results, with record annual average production of 38,950 boe per day and record low operating costs of $4.54 per boe in 2015, as well as highlights from its independent reserves evaluation effective December 31, 2015. Birchcliff is also pleased to provide an operational update.

Birchcliff estimates that its production for January 2016 averaged approximately 42,000 boe per day.

Jeff Tonken, President and Chief Executive Officer of Birchcliff, stated: "Our proved plus probable reserves increased 23% to 572.9 MMboe as at December 31, 2015. The future net revenue from these reserves (discounted at 10%) increased slightly to approximately $3.9 billion from $3.8 billion in 2014, notwithstanding materially lower commodity price forecasts.

Our proved developed producing reserves were added at $7.79 per boe during 2015. This means that we added proved developed producing reserves for approximately 2/3 of the funds flow netback we received on the sale of production, which is the true test of a low-cost finder and producer of oil and gas.

Our 2015 operational results are very strong, with record annual average production of 38,950 boe per day, a 15% increase from 2014, while total cash costs of $11.01 per boe were down 21% from 2014.

Birchcliff has proven that its business works at low commodity prices and our operational execution has been on budget and on time."

This press release contains forward-looking information within the meaning of applicable securities laws. Such forward-looking information is based upon certain expectations and assumptions and actual results may differ materially from those expressed or implied by such forward-looking information. For further information regarding the forward-looking information contained herein, see "Advisories - Forward-Looking Information". In addition, this press release contains references to "funds flow", "funds flow from operations", "funds flow per common share", "adjusted net income to common shareholders", "adjusted net loss to common shareholders", "netback", "operating netback", "estimated operating netback", "funds flow netback", "operating margin", "total cash costs" and "total debt", which do not have standardized meanings prescribed by generally accepted accounting principles ("GAAP"). For further information regarding these non-GAAP measures, including reconciliations to the most directly comparable GAAP measure, see "Non-GAAP Measures".

PRESS RELEASE HIGHLIGHTS

2015 Year-End Financial and Operational Results

• Record annual average production of 38,950 boe per day, a 15% increase from 2014 annual average production of 33,734 boe per day. Production consisted of 86% natural gas, 10% light oil and 4% NGL.

• Funds flow of $160.8 million ($1.06 per basic common share), a 47% decrease from $300.5 million ($2.03 per basic common share) in 2014.

• Net loss to common shareholders of $16.2 million ($0.11 per basic common share), a decrease from net income to common shareholders of $110.3 million ($0.75 per basic common share) in 2014.

• Adjusted net income to common shareholders of $1.8 million, which excludes two one-time, non-cash deferred income tax expense items in the aggregate amount of $18.0 million, which are non-operational in nature.

• Record low operating costs of $4.54 per boe, a 13% decrease from $5.22 per boe in 2014.

• Record low general and administrative expense of $1.61 per boe, an 11% decrease from $1.81 per boe in 2014.

• Record low total cash costs of $11.01 per boe (royalties, operating, transportation and marketing, general and administrative and interest expense), a 21% decrease from $14.02 per boe in 2014.

• Plant and field operating costs were approximately $0.31 per Mcfe ($1.90 per boe) in 2015 at Birchcliff's 100% owned natural gas plant located in the Pouce Coupe South area (the "PCS Gas Plant"), where Birchcliff processed 81% of its total corporate natural gas production and achieved an operating margin of 77%.

• Funds flow netback of $11.31 per boe, a 54% decrease from $24.40 per boe in 2014.

• Long-term bank debt of $622.1 million against available lines of credit of approximately $800 million. Total debt at December 31, 2015, including working capital deficit, was $643.6 million.

• Capital expenditures of $247.2 million.

• Birchcliff had an active drilling program during 2015 drilling a total of 32 (31.5 net) wells, consisting of:

  • 28 (28.0 net) Montney/Doig horizontal natural gas wells in the Pouce Coupe area;

  • 1 (1.0 net) Montney/Doig horizontal natural gas well in the Elmworth area;

  • 1 (1.0 net) Charlie Lake horizontal light oil well in the Progress area;

  • 1 (0.5 net) Halfway horizontal light oil well in the Progress area; and

  • 1 (1.0 net) Belloy vertical well drilled as an acid gas disposal well in the Elmworth area.

• Undeveloped land base of 426,012.6 (398,412.7 net) acres at December 31, 2015, with a 94% average working interest.

• As at December 31, 2015, Birchcliff has drilled an aggregate of 188 (187.9 net) Montney/Doig horizontal natural gas wells, continuing to optimize its execution.

• Birchcliff's potential net future horizontal drilling locations on the Montney/Doig Natural Gas Resource Play increased to 3,367.3 at December 31, 2015 from 3,346.3 at year-end 2014.

2015 Fourth Quarter Financial and Operational Results

• Record quarterly average production of 40,445 boe per day, a 5% increase from 38,433 boe per day in the third quarter of 2015 and a 7% increase from 37,704 boe per day in the fourth quarter of 2014. Production consisted of 87% natural gas, 9% light oil and 4% NGL.

• Funds flow of $33.7 million ($0.22 per basic common share), a 24% decrease from $44.6 million ($0.29 per basic common share) in the third quarter of 2015 and a 45% decrease from $61.7 million ($0.41 per basic common share) in the fourth quarter of 2014.

• Net loss to common shareholders of $10.3 million ($0.07 per basic common share), a decrease from net income to common shareholders of $3.8 million ($0.03 per basic common share) in the third quarter of 2015 and a decrease from net income to common shareholders of $16.1 million ($0.11 per basic common share) in the fourth quarter of 2014.

• Adjusted net loss to common shareholders of $0.1 million, which excludes a one-time, non-cash deferred income tax expense item of $10.2 million, which is non-operational in nature.

• Record low operating costs of $4.16 per boe, a 5% decrease from $4.39 per boe in the third quarter of 2015 and a 22% decrease from $5.33 per boe in the fourth quarter of 2014.

• Low general and administrative expense of $2.01 per boe, which is comparable to $2.02 per boe in the fourth quarter of 2014.

• Low total cash costs of $11.22 per boe (royalties, operating, transportation and marketing, general and administrative and interest expense), a 6% increase from $10.58 per boe in the third quarter of 2015 and a 14% decrease from $13.00 per boe in the fourth quarter of 2014.

• Funds flow netback of $9.06 per boe, a 28% decrease from $12.61 per boe in the third quarter of 2015 and a 49% decrease from $17.79 per boe in the fourth quarter of 2014.

• Capital expenditures of $33.5 million.

• Drilled 4 (4.0 net) wells in the fourth quarter of 2015, all of which were Montney/Doig horizontal natural gas wells in the Pouce Coupe area.

2015 Independent Reserves Evaluation

• Deloitte LLP ("Deloitte"), independent qualified reserves evaluators of Calgary, Alberta, prepared a reserves estimation and economic evaluation effective December 31, 2015 in respect of Birchcliff's oil and natural gas properties, which is contained in a report dated February 5, 2016 (the "2015 Reserves Evaluation").

• Birchcliff added 31.6 MMboe of proved developed producing reserves (for a total of 102.1 MMboe) during 2015, a 37% increase over Birchcliff's proved developed producing reserves as at December 31, 2014 after taking into account 2015 production of 14.2 MMboe.

• Proved developed producing reserves of 102.1 MMboe as at December 31, 2015, a 21% increase from 84.7 MMboe as at December 31, 2014. This represents an increase of 17.4 MMboe.

• Positive technical revisions accounted for 17% of the proved developed producing reserve additions in 2015, primarily due to the production performance of wells drilled in 2014.

• Proved reserves of 351.2 MMboe as at December 31, 2015, a 24% increase from 282.3 MMboe as at December 31, 2014. This represents an increase of 68.9 MMboe.

• Positive technical revisions accounted for 31% of the proved reserve additions in 2015. These positive revisions, which did not require any increase to future development capital ("FDC"), can be attributed to Deloitte's recognition of improved well production performance from Birchcliff's 2015, 2014 and 2013 drilling programs.

• Proved plus probable reserves of 572.9 MMboe as at December 31, 2015, a 23% increase from 465.0 MMboe as at December 31, 2014. This represents an increase of 107.9 MMboe. Birchcliff added 8.59 boe of proved plus probable reserves for each boe that was produced in 2015.

• Positive technical revisions accounted for 29% of the proved plus probable reserve additions in 2015. These positive revisions, which did not require any increase to FDC, can be attributed to Deloitte's recognition of improved well production performance from Birchcliff's 2015, 2014 and 2013 drilling programs.

• FDC per Montney/Doig horizontal natural gas well as estimated by Deloitte decreased to an average of $4.4 million per well as at December 31, 2015 from $5.3 million per well, which is a decrease of 17% compared to 2014 and is primarily due to the application of new technology, operational efficiencies and a reduction in service costs.

• Proved developed producing reserve additions during 2015 replaced 222% of 2015 production, proved reserve additions replaced 585% of 2015 production and proved plus probable reserve additions replaced 859% of 2015 production.

• Reserve life index of 6.9 years on a proved developed producing basis, 23.7 years on a proved basis and 38.7 years on a proved plus probable basis, in each case assuming an average daily production rate of 40,500 boe per day.

2015 Finding, Development and Acquisition Costs ("FD&A") and Recycle Ratios

• In 2015, Birchcliff spent $247.2 million of capital and the following table sets forth Birchcliff's 2015 FD&A costs for proved developed producing, proved and proved plus probable reserves:

FD&A Costs ($/boe)(1)
Excluding FDC
	Total FD&A - Proved Developed Producing	$7.79
	Total FD&A - Proved	$2.96
	Total FD&A - Proved Plus Probable	$2.02
Including FDC(2)
	Total FD&A - Proved	$2.28
	Total FD&A - Proved Plus Probable	$1.32

	(1)	See "Advisories - Oil and Gas Metrics" for a description of the methodology used to calculate FD&A costs.
	(2)	Includes the 2015 decrease in FDC from 2014 of $56.5 million on a proved basis and a decrease of $85.4 million on a proved plus probable basis, which decreases are primarily due to the application of new technology, operational efficiencies and a reduction in service costs.

• The following table sets forth Birchcliff's 2015 operating netback and funds flow netback recycle ratios for proved developed producing, proved and proved plus probable reserves:

Recycle Ratios(1)
		Operating Netback Recycle Ratio	Funds Flow Netback Recycle Ratio
Excluding FDC
	FD&A - Proved Developed Producing	1.9	1.5
	FD&A - Proved	4.9	3.8
	FD&A - Proved Plus Probable	7.2	5.6
Including FDC
	FD&A - Proved	6.4	5.0
	FD&A - Proved Plus Probable	11.0	8.6

	(1)	See "Advisories - Oil and Gas Metrics" for a description of the methodology used to calculate FD&A costs and recycle ratios.

2016 Production and Operational Update

• Birchcliff estimates that its production for January 2016 averaged approximately 42,000 boe per day.

• Birchcliff has drilled 2 (2.0 net) wells year-to-date, consisting of 1 (1.0 net) Montney/Doig horizontal natural gas well in the Pouce Coupe area and 1 (1.0 net) Charlie Lake horizontal light oil well in the Worsley area.

• Birchcliff currently has 2 drilling rigs at work, both of which are drilling Montney/Doig horizontal natural gas wells in the Pouce Coupe area.

2015 Audited Results to be Released

• Birchcliff expects to release its audited results for the year ended December 31, 2015 on March 16, 2016, along with the results of its independent Montney/Doig Natural Gas Resource Assessment.

2015 FINANCIAL AND OPERATIONAL HIGHLIGHTS

		Three months ended December 31,				Twelve months ended December 31,
		2015		2014		2015		2014
OPERATING
	Average daily production
	Light oil - (barrels)	3,530		3,957		3,707		3,957
	Natural gas - (thousands of cubic feet)	211,127		192,499		201,418		169,852
	NGL - (barrels)	1,727		1,664		1,673		1,469
	Total - barrels of oil equivalent (6:1)(1)	40,445		37,704		38,950		33,734
Average sales price ($ CDN)(2)
	Light oil - (per barrel)	49.36		71.87		53.68		92.39
	Natural gas - (per thousand cubic feet)	2.67		3.91		2.90		4.74
	NGL - (per barrel)	47.98		66.10		50.76		85.13
	Total - barrels of oil equivalent(6:1)(1)	20.28		30.43		22.31		38.39
NETBACK AND COST ($ per barrel of oil equivalent at 6:1)(1)
	Petroleum and natural gas revenue(2)	20.28		30.44		22.32		38.41
	Royalty expense	(0.94	)	(1.84	)	(0.81	)	(2.99	)
	Operating expense	(4.16	)	(5.33	)	(4.54	)	(5.22	)
	Transportation and marketing expense	(2.31	)	(2.39	)	(2.45	)	(2.43	)
Netback(3)		12.87		20.88		14.52		27.77
	General & Administrative expense, net	(2.01	)	(2.02	)	(1.61	)	(1.81	)
	Interest expense	(1.80	)	(1.42	)	(1.60	)	(1.57	)
	Realized gain on financial instruments	-		0.35		-		0.01
Funds flow netback(3)		9.06		17.79		11.31		24.40
	Stock-based compensation expense, net	(0.21	)	(0.26	)	(0.23	)	(0.39	)
	Depletion and depreciation expense	(9.66	)	(11.17	)	(10.35	)	(11.07	)
	Accretion expense	(0.15	)	(0.16	)	(0.16	)	(0.20	)
	Amortization of deferred financing fees	(0.06	)	(0.06	)	(0.06	)	(0.08	)
	Gain on sale of assets	1.80		0.91		0.52		0.26
	Unrealized gain on financial instruments	-		0.05		-		0.03
	Dividends on Series C preferred shares	(0.24	)	(0.25	)	(0.25	)	(0.28	)
	Income tax expense	(3.05	)	(1.93	)	(1.64	)	(3.39	)
Net income (loss)		(2.51	)	4.92		(0.86	)	9.28
	Dividends on Series A preferred shares	(0.26	)	(0.29	)	(0.28	)	(0.32	)
Net income (loss) to common shareholders		(2.77	)	4.63		(1.14	)	8.96
FINANCIAL
Petroleum and natural gas revenue ($000s)(2)		75,476		105,598		317,304		472,888
Funds flow from operations ($000s)(3)		33,697		61,717		160,756		300,498
	Per common share - basic ($)(3)	0.22		0.41		1.06		2.03
	Per common share - diluted ($)(3)	0.22		0.40		1.04		1.97
Net income (loss) ($000s)		(9,322	)	17,053		(12,160	)	114,304
Net income (loss) to common shareholders ($000s)		(10,322	)	16,053		(16,160	)	110,304
	Per common share - basic ($)	(0.07	)	0.11		(0.11	)	0.75
	Per common share - diluted ($)	(0.07	)	0.10		(0.10	)	0.72
Common shares outstanding (000s)
	End of period - basic	152,308		152,214		152,308		152,214
	End of period - diluted	167,817		166,302		167,817		166,302
	Weighted average common shares for period - basic	152,308		152,183		152,286		147,764
	Weighted average common shares for period - diluted	153,627		155,304		154,078		152,243
Dividends on Series A preferred shares ($000s)		1,000		1,000		4,000		4,000
Dividends on Series C preferred shares ($000s)		875		875		3,500		3,500
Capital expenditures, net ($000s)		33,533		109,682		247,207		450,932
Long-term bank debt ($000s)		622,074		469,033		622,074		469,033
Working capital deficit ($000s)		21,538		76,712		21,538		76,712
Total debt ($000s)(3)		643,612		545,745		643,612		545,745

	(1)	See "Advisories".
	(2)	Excludes the effect of hedges using financial instruments.
	(3)	See "Non-GAAP Measures".

2015 YEAR-END FINANCIAL AND OPERATIONAL RESULTS

All financial and operational information in this press release for the year-ended December 31, 2015 is based on Birchcliff's unaudited financial statements. These unaudited amounts may change upon the completion of Birchcliff's audited financial statements, which are scheduled to be released on March 16, 2016.

2015 Production

Record production in 2015 averaged 38,950 boe per day, a 15% increase from 2014 annual average production of 33,734 boe per day. Production per common share increased 12% from 2014. This production growth from 2014 was largely due to incremental production added from new Montney/Doig horizontal natural gas wells that were tied into the PCS Gas Plant, offset by natural well production declines and numerous transportation service curtailments on TransCanada's NGTL System that adversely impacted Birchcliff's production.

Production consisted of approximately 86% natural gas, 10% light oil and 4% NGL in 2015. Approximately 81% of Birchcliff's total corporate natural gas production and 73% of its total corporate production was processed at the PCS Gas Plant during 2015.

Birchcliff has consistently demonstrated significant growth in annual average production per common share. The following table highlights Birchcliff's annual average production per day per basic common share growth since 2011 year-over-year.

	2011	2012	2013	2014	2015	Change Since 2011	Average Annual Growth
Annual average production (boe/day)	18,136	22,802	25,829	33,734	38,950	115%	29%
Production per day per million common shares(1) (boe)	143.6	166.3	181.4	228.3	255.8	78%	20%

(1)

Based on annual average production and weighted average basic common shares outstanding in the respective year.

2015 Funds Flow

Funds flow in 2015 was $160.8 million ($1.06 per basic common share), a 47% decrease from $300.5 million ($2.03 per basic common share) in 2014. This decrease was largely due to a 42% decrease in the average realized oil and natural gas wellhead price.

2015 Net Loss to Common Shareholders

Birchcliff had a net loss of $12.2 million in 2015, a decrease from net income of $114.3 million in 2014. Birchcliff recorded a net loss to common shareholders of $16.2 million ($0.11 per basic common share), a decrease from net income to common shareholders of $110.3 million ($0.75 per basic common share) in 2014. These decreases were mainly attributable to lower funds flow as a result of the decrease in commodity prices.

2015 Adjusted Net Income to Common Shareholders

Birchcliff recorded adjusted net income to common shareholders of $1.8 million in 2015, after excluding: (i) a one-time, NON-CASH deferred income tax expense in the amount of $7.8 million that was recorded in the second quarter of 2015 as a result of the 2015 change in the Alberta corporate income tax rate from 10% to 12%; and (ii) a one-time, NON-CASH deferred income tax expense in the amount of $10.2 million that was recorded in the fourth quarter of 2015 as a result of the denial by the Tax Court of Canada (the "Trial Court") of Birchcliff's appeal of the reassessment by the Canada Revenue Agency (the "CRA") of Birchcliff's income tax filings in 2011 in connection with the tax pools available to Veracel Inc. (the "Reassessment"). Birchcliff has appealed the Trial Decision to the Federal Court of Appeal (the "Court of Appeal"). For more information on the Reassessment, please see "2016 Production Guidance and Operational Update - Update on the Veracel Reassessment".

Management has excluded these non-operational, deferred income tax items from net income to common shareholders as management believes that excluding such items better reflects the results generated by Birchcliff's principal business activities. See "Non-GAAP Measures".

2015 Operating Costs and General and Administrative Expense

Operating costs in 2015 were $4.54 per boe, a 13% decrease from $5.22 per boe in 2014. Operating costs per boe decreased from 2014 largely due to the continued cost benefits achieved from processing incremental volumes of natural gas through the PCS Gas Plant, the continued implementation of various cost saving and optimization initiatives and lower service costs due to reduced industry activity.

General and administrative expense in 2015 was $1.61 per boe, an 11% decrease from $1.81 per boe in 2014. This decrease results primarily from increased sales volumes during 2015, with the modest addition of new employees.

Birchcliff continued to focus on reducing its operating costs on a per boe basis during 2015. In the third quarter of 2015, Birchcliff implemented two meaningful operating cost reduction initiatives that are expected to further reduce costs over the long term at the PCS Gas Plant. The first initiative was the conversion of an existing standing vertical well near the PCS Gas Plant to a water disposal well and connecting it by pipeline to the PCS Gas Plant. This eliminated the related trucking costs and disposal fees for any produced disposable water at the PCS Gas Plant. The second initiative was the conversion in August 2015 of a fuel gas pipeline to a condensate service pipeline to connect the condensate stream from the PCS Gas Plant directly to Pembina's pipeline system. This eliminated related condensate trucking fees and better secured take away capacity for Birchcliff's produced condensate volumes.

2015 PCS Gas Plant Netbacks

Since the PCS Gas Plant first became operational in March 2010, Birchcliff has seen a significant reduction in its corporate operating costs on a per boe basis. During 2015, Birchcliff processed approximately 81% of its total corporate natural gas production through the PCS Gas Plant with an average plant and field operating cost of $0.31 per Mcfe ($1.90 per boe). The estimated operating netback at the PCS Gas Plant was $2.44 per Mcfe ($14.62 per boe), resulting in an operating margin of 77% in 2015.

The following table details Birchcliff's annual net production and estimated operating netback for wells producing to the PCS Gas Plant, on a production month basis.

Production Processed Through the PCS Gas Plant

		Twelve months ended December 31, 2015				Twelve months ended December 31, 2014				Twelve months ended December 31, 2013				Twelve months ended December 31, 2012
Average daily production, net to Birchcliff:
	Natural gas (Mcf)		163,641				132,808					91,666				59,327
	Oil & NGL (bbls)			1,287				1,065				527				204
Total boe (6:1)(1)				28,560				23,200				15,805				10,092
Sales liquids yield (bbls/MMcf)				7.9				8.0				5.7				3.4
% of corporate natural gas production				81%				78%				73%				56%
% of corporate production				73%				69%				61%				44%
AECO - C daily ($/Mcf)		$2.69				$4.50				$3.17				$2.39
Netback and cost:		$/Mcfe		$/boe		$/Mcfe		$/boe		$/Mcfe		$/boe		$/Mcfe		$/boe
	Petroleum and natural gas revenue	3.17		19.03		5.17		31.02		3.77		22.64		2.91		17.44
	Royalty expense	(0.11	)	(0.63	)	(0.24	)	(1.42	)	(0.16	)	(0.93	)	(0.11	)	(0.67	)
	Operating expense(2)	(0.31	)	(1.90	)	(0.42	)	(2.52	)	(0.37	)	(2.24	)	(0.35	)	(2.08	)
	Transportation and marketing expense	(0.31	)	(1.88	)	(0.30	)	(1.81	)	(0.25	)	(1.55	)	(0.23	)	(1.37	)
Estimated operating netback(3)		$2.44		$14.62		$4.21		$25.27		$2.99		$17.92		$2.22		$13.32
Operating margin(3)		77%		77%		81%		81%		79%		79%		76%		76%

	(1)	See "Advisories".
	(2)	Represents plant and field operating costs.
	(3)	See "Non-GAAP Measures".

2015 Total Cash Costs and Funds Flow Netbacks

During 2015, Birchcliff had total cash costs of $11.01 per boe, a 21% decrease from $14.02 per boe in 2014.

During 2015, Birchcliff had funds flow netback of $11.31 per boe, a 54% decrease from $24.40 per boe in 2014.

2015 Capital Expenditures

During 2015, Birchcliff had capital expenditures of $247.2 million, which is in line with Birchcliff's previous guidance regarding its 2015 capital expenditure program.

2015 Debt and Capitalization

Birchcliff has three-year term extendible revolving credit facilities in the aggregate principal amount of $800 million (the "Credit Facilities") with maturity dates of May 11, 2018, which are comprised of an extendible revolving syndicated term credit facility of $760 million (the "Syndicated Credit Facility") and an extendible revolving working capital facility of $40 million (the "Working Capital Facility"). The Credit Facilities contain no financial covenants.

At December 31, 2015, Birchcliff's long-term bank debt was $622.1 million from available credit facilities of approximately $800 million, which provides Birchcliff with financial flexibility. Total debt, including working capital deficit, was $643.6 million, as compared to $545.7 million at December 31, 2014.

The Credit Facilities are subject to a semi-annual review of the borrowing base limit by Birchcliff's syndicate of lenders, which limit is directly impacted by the value of Birchcliff's oil and natural gas reserves. Birchcliff may each year, at its option, request an extension to the maturity date of the Syndicated Credit Facility and the Working Capital Facility, or either of them, for an additional period of up to three years from May 11 of the year in which the extension request is made. Birchcliff currently expects that as a result of the continued deterioration in commodity prices, the aggregate limit of the Credit Facilities will remain at $800 million during the normal credit review in May 2016. Furthermore, Birchcliff currently expects that it will request an extension to the maturity date from May 11, 2018 to May 11, 2019.

At December 31, 2015, Birchcliff had 152,307,539 basic common shares, 2,000,000 perpetual cumulative redeemable 5-year rate reset preferred shares, Series A (the "Series A Preferred Shares") and 2,000,000 perpetual cumulative redeemable preferred shares, Series C (the "Series C Preferred Shares") outstanding.

The Series A Preferred Shares do not have a fixed maturity date and are not redeemable at the option of the holders thereof. Subject to the provisions of the Series A Preferred Shares, the Series A Preferred Shares are redeemable at the option of Birchcliff on September 30, 2017 and on September 30 in every fifth year thereafter. The dividend rate in respect of the Series A Preferred Shares will reset on September 30, 2017 and every five years thereafter. For further details regarding the terms of the Series A Preferred Shares, please see the provisions of the Series A Preferred Shares, a copy of which is available under Birchcliff's profile at www.sedar.com.

The Series C Preferred Shares do not have a fixed maturity date. Subject to the provisions of the Series C Preferred Shares, the Series C Preferred Shares are redeemable by Birchcliff on and after June 30, 2018 and the Series C Preferred Shares are redeemable by the holders thereof on and after June 30, 2020. The dividend rate for the Series C Preferred Shares is a fixed dividend rate and does not reset. For further details regarding the terms of the Series C Preferred Shares, please see the provisions of the Series C Preferred Shares, a copy of which is available under Birchcliff's profile at www.sedar.com.

2015 Drilling Program

Birchcliff's 2015 drilling program was focused on its two proven resource plays, the Montney/Doig Natural Gas Resource Play and the Charlie Lake Light Oil Resource Play. Birchcliff actively employed the evolving technology utilized by the industry regarding horizontal well drilling and the related multi-stage fracture stimulation technology.

Birchcliff had an active drilling program during 2015 drilling a total of 32 (31.5 net) wells, consisting of 28 (28.0 net) Montney/Doig horizontal natural gas wells in the Pouce Coupe area, 1 (1.0 net) Montney/Doig horizontal natural gas well in the Elmworth area, 1 (1.0 net) Charlie Lake horizontal light oil well in the Progress area, 1.0 (0.5 net) Halfway horizontal light oil well in the Progress area and 1.0 (1.0 net) Belloy vertical well drilled as an acid gas disposal well in the Elmworth area. All of the horizontal wells drilled in 2015 utilized multi-stage fracture stimulation technology.

2015 Land

Birchcliff's land base primarily consists of large contiguous blocks of high working interest acreage located near facilities owned and/or operated by Birchcliff or near third party infrastructure.

Birchcliff's undeveloped land base at December 31, 2015 was 426,012.6 (398,412.7 net) acres, with a 94% average working interest.

The following table summarizes Birchcliff's land holdings on the following resource plays at December 31, 2015.

Resource Play Land Holdings as at December 31, 2015

Resource Play		Working Interest	Gross (acres)	Net (acres)
Montney/Doig Natural Gas Resource Play
	Basal Doig/Upper Montney Interval	94.8%	198,336	187,968
	Montney D4 Interval	97.8%	187,776	183,680
	Montney D1 Interval	97.0%	203,136	197,120
	Montney C Interval	97.0%	203,136	197,120
Charlie Lake Light Oil Resource Play		93.3%	146,880	137,133
Duvernay Resource Play		100.0%	73,120	73,120
Nordegg Resource Play		86.0%	405,440	348,528
Banff/Exshaw Resource Play		98.9%	230,400	227,984

2015 FOURTH QUARTER FINANCIAL AND OPERATIONAL RESULTS

2015 Q4 Production

Record fourth quarter production averaged 40,445 boe per day, a 5% increase from production of 38,433 boe per day in the third quarter of 2015 and a 7% increase from 37,704 boe per day in the fourth quarter of 2014. Production per common share increased 7% from the fourth quarter of 2014 and 5% from the third quarter of 2015. Production consisted of approximately 87% natural gas, 9% light oil and 4% NGL in the fourth quarter of 2015.

2015 Q4 Funds Flow

Funds flow was $33.7 million ($0.22 per basic common share), a 24% decrease from $44.6 million ($0.29 per basic common share) in the third quarter of 2015 and a 45% decrease from $61.7 million ($0.41 per basic common share) in the fourth quarter of 2014. These decreases were largely due to a 12% and a 33% decrease, respectively, in the average realized oil and natural gas wellhead price.

2015 Q4 Net Loss to Common Shareholders

Birchcliff had a net loss of $9.3 million, a decrease from net income of $4.8 million in the third quarter of 2015 and a decrease from net income of $17.1 million in the fourth quarter of 2014. Birchcliff recorded a net loss to common shareholders of $10.3 million ($0.07 per basic common share), a decrease from net income to common shareholders of $3.8 million ($0.03 per basic common share) in the third quarter of 2015 and a decrease from net income to common shareholders of $16.1 million ($0.11 per basic common share) in the fourth quarter of 2014.

2015 Q4 Adjusted Net Loss to Common Shareholders

Birchcliff recorded adjusted net loss to common shareholders of $0.1 million in the fourth quarter of 2015, after excluding a one-time, NON-CASH deferred income tax expense item in the amount of $10.2 million as a result of the denial by the Trial Court of Birchcliff's appeal of the Reassessment. See also "2016 Production Guidance and Operational Update - Update on the Veracel Reassessment" and "Non-GAAP Measures".

2015 Q4 Operating Costs and General and Administrative Expense

Operating costs were $4.16 per boe, a 5% decrease from $4.39 per boe in the third quarter of 2015 and a 22% decrease from $5.33 per boe in the fourth quarter of 2014.

General and administrative expense was $2.01 per boe, which is comparable to $2.02 per boe in the fourth quarter of 2014.

2015 Q4 Capital Expenditures

Capital expenditures in the fourth quarter were $33.5 million.

2015 Q4 Drilling

Drilling activities during the fourth quarter of 2015 were focused on Birchcliff's Montney/Doig Natural Gas Resource Play and consisted of 4 (4.0 net) wells, all of which were Montney/Doig horizontal natural gas wells in Pouce Coupe area. All of the horizontal wells drilled in the fourth quarter of 2015 utilized multi-stage fracture stimulation technology.

2015 INDEPENDENT RESERVES EVALUATION

Deloitte, Birchcliff's independent qualified reserves evaluator, prepared the 2015 Reserves Evaluation and also prepared reserves estimations and economic evaluations effective December 31, 2014 (the "2014 Reserves Evaluation") and December 31, 2013. Reserves data contained herein as at December 31, 2015, 2014 and 2013 are extracted from the relevant evaluation. The 2015 Reserves Evaluation and the prior reserves evaluations 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") that were in effect at the relevant time.

Numbers presented in the tables below may not total due to rounding. The estimates of reserves and future net revenues contained in this press release were prepared by Deloitte.

NI 51-101 requires a reporting issuer to disclose its reserves in accordance with the product types contained in NI 51-101, which product types include light crude oil and medium crude oil (combined), conventional natural gas, shale gas and NGL. "Shale gas" as defined in NI 51-101 means natural gas: (i) contained in dense organic-rich rocks, including low-permeability shales, siltstones and carbonates, in which the natural gas is primarily adsorbed on the kerogen or clay minerals; and (ii) that usually requires the use of hydraulic fracturing to achieve economic production rates.

With respect to Birchcliff's natural gas reserves attributable to its Montney/Doig Natural Gas Resource Play, such reserves would most closely fit within the category of shale gas as opposed to conventional natural gas; however, the dominant storage mechanism is gas stored in the pore space with contributions from gas adsorbed to kerogen, clay minerals and bitumen. Birchcliff considers that its natural gas reserves attributable to the Montney/Doig Natural Gas Resource Play to be low permeability gas resources or "tight gas" (as such term is defined in the COGE Handbook), a generic term that includes "basin-centred", "deep gas" and "shale gas". Although reservoirs usually consist of low permeability sandstones, siltstones, or shales, they may also contain carbonates. Although a small amount of gas may also be present in natural fractures, extensive hydraulic fracturing is invariably required to produce the "tight gas". The trapping mechanisms may be the same for conventional reservoirs, adsorption on kerogen or clays, or relative permeability effects. "Shale gas" is the NI 51-101 product type that most closely matches the natural gas from Birchcliff's Montney/Doig Natural Gas Resource Play.

For additional information regarding the presentation of Birchcliff's reserves disclosure, please see "Disclosure of Oil and Gas Reserves" and "Advisories" contained herein.

Reserves Summary

The following table summarizes Deloitte's estimates of Birchcliff's gross oil, natural gas and NGL reserves at December 31, 2015 and December 31, 2014, using the Deloitte forecast price assumptions in effect at the applicable reserves evaluation date.

Summary of Oil, Natural Gas and NGL Reserves
Reserves Category	Dec 31, 2015 (MMboe)	Dec 31, 2014 (MMboe)	Increase from Dec 31, 2014
Proved Developed Producing	102.1	84.7	21%
Total Proved	351.2	282.3	24%
Probable	221.7	182.7	21%
Total Proved Plus Probable	572.9	465.0	23%

Birchcliff's proved plus probable reserves are comprised of 85% shale gas, 4% conventional natural gas, 6% light crude oil and medium crude oil (combined) and 5% NGL.

Net Present Values of Future Net Revenue

The following table is a summary of the net present values of future net revenue associated with Birchcliff's reserves at December 31, 2015, before deducting future income tax expense and calculated at various discount rates. The net present values of future net revenue attributable to Birchcliff's reserves are based on Deloitte's December 31, 2015 forecast price assumptions of commodity prices (the "2015 Deloitte Price Forecast"). The Deloitte Price Forecast can be found at http://www2.deloitte.com/ca/en/pages/resource-evaluation-and-advisory/topics/resource-evaluation-and-advisory.html.

Net Present Values of Future Net Revenue Before Income Taxes(1)(2)
		Discounted Rate per Annum
Reserves Category		0% (MM$)	5% (MM$)	8% (MM$)	10% (MM$)	15% (MM$)	20% (MM$)
Proved
	Developed Producing	2,099.5	1,486.5	1,254.6	1,134.6	913.9	765.4
	Developed Non-Producing	434.1	230.4	169.2	140.5	93.2	65.5
	Undeveloped	4,575.0	2,399.3	1,669.0	1,316.1	722.1	372.7
Total Proved		7,108.6	4,116.2	3,092.8	2,591.2	1,729.2	1,203.6
Probable		6,097.7	2,619.1	1,682.4	1,276.2	668.5	361.8
Total Proved Plus Probable		13,206.3	6,735.3	4,775.2	3,867.4	2,397.7	1,565.3

	(1)	Estimates of future net revenue, whether discounted or not, do not represent fair market value.
	(2)	Future net revenue is before provision for interest, debt servicing and general and administrative expense and after the deduction of royalties, operating costs, development costs and abandonment and reclamation costs. Abandonment and reclamation costs have been estimated by Deloitte in the 2015 Reserve Report, are attributed to all existing and future wells that were assigned reserves and do not include abandonment and reclamation costs for wells and facilities to which no reserves were assigned.

The net present value of the proved plus probable reserves (at a 10% discount rate) was approximately $3.9 billion, a 2% increase from 2014. This increase is a result of the 23% increase in reserves volumes recognized in the 2015 Reserves Evaluation, offset by the significant decrease in oil and gas prices contained in the 2015 Deloitte Price Forecast as compared to 2014.

The net present value of the proved developed producing reserves (at a 10% discount rate) was approximately $1.1 billion, a 14% decrease compared to 2014. This decrease is a result of the significant decrease in oil and gas prices contained in the 2015 Deloitte Price Forecast as compared to 2014, notwithstanding the 21% increase in reserves volumes recognized in the 2015 Reserves Evaluation.

The natural gas price forecast and the oil and pentanes plus price forecasts for the years 2016 through 2020 as contained in the 2015 Deloitte Price Forecast decreased by 35% and 22%, respectively, compared to the 2014 Deloitte forecast price assumptions. The natural gas price forecast used by Deloitte in the 2015 Reserves Evaluation for the years 2016 through 2020 is approximately $1.64 per MMbtu lower on average than the forecast used by Deloitte for the same period in the 2014 Reserves Evaluation. The Edmonton Par oil price and the pentanes plus price forecasts used by Deloitte in the 2015 Reserves Evaluation for the years 2016 through 2020 are approximately $19.07 per bbl lower than the forecasts used by Deloitte for the same period in the 2014 Reserves Evaluation.

Positive Technical Revisions

Positive technical revisions accounted for 17% of the proved developed producing reserve additions, 31% of the proved reserve additions and 29% of the proved plus probable reserve additions in 2015.

These positive revisions for proved and proved plus probable reserves, which did not require any increase to FDC, can be attributed to Deloitte's recognition of improved well production performance from Birchcliff's 2015, 2014 and 2013 drilling programs. These technical revisions primarily resulted from the continued advancement of Birchcliff's drilling and completion technologies and improved well production performance on some of its existing wells. Improved well performance, coupled with reduced well costs, aid Birchcliff in having top tier capital efficiencies.

Reserve Replacement

From the 2014 Reserves Evaluation to the 2015 Reserves Evaluation, Birchcliff had:

• 222% reserve replacement on a proved developed producing basis, including reserves disposed. Birchcliff added 2.22 boe of proved developed producing reserves for each boe that was produced during the year (calculated by dividing 2015 proved developed producing reserves additions before production by total production in 2015).

• 585% reserve replacement on a proved basis, including reserves disposed. Birchcliff added 5.85 boe of proved reserves for each boe that was produced during the year (calculated by dividing 2015 proved reserves additions before production by total production in 2015).

• 859% reserve replacement on a proved plus probable basis, including reserves disposed. Birchcliff added 8.59 boe of proved plus probable reserves for each boe that was produced during the year (calculated by dividing 2015 proved plus probable reserves additions before production by total production in 2015).

The following table sets forth for each category of reserves the 2015 reserve replacement ratios calculated by dividing the reserves additions before production by total production in 2015.

Reserve Replacement Ratios

Reserves Category	2015 Reserve Replacement Ratio
Proved Developed Producing	222%
Total Proved	585%
Total Proved Plus Probable	859%

See "Advisories" for a description of the methodology used to calculate reserve replacement.

Reserve Life Index

Birchcliff's reserve life index is 6.9 years on a proved developed producing basis, 23.7 years on a proved basis and 38.7 years on a proved plus probable basis, in each case using reserves estimates by Deloitte at December 31, 2015 and assuming an average daily production rate of 40,500 boe per day. See "Advisories" for a description of the methodology used to calculate reserve life index.

Reserves on the Montney/Doig Natural Gas Resource Play

Deloitte estimated at December 31, 2015, that Birchcliff had 516.8 MMboe of proved plus probable reserves attributed to horizontal wells on the Montney/Doig Natural Gas Resource Play. This is an increase of 25% from 412.3 MMboe proved plus probable reserves attributed to horizontal wells on the Montney/Doig Natural Gas Resource Play at December 31, 2014.

The following tables summarize Deloitte's estimates of reserves attributable to Birchcliff's horizontal wells on the Montney/Doig Natural Gas Resource Play, the number of horizontal wells to which reserves were attributed and the future capital associated with such reserves.

Montney/Doig Natural Gas Resource Play Reserves Data⁽¹⁾

			Light Crude Oil and Medium Crude Oil and				Existing Horizontal Wells and Future Horizontal Well Locations				Net Future Development
	Shale Gas (Bcf)(2)		NGL Combined (Mbbl)(3)		Total (Mboe)		(Gross)		(Net)		Capital (MM$)
Reserves Category	2015	2014	2015	2014	2015	2014	2015	2014	2015	2014	2015(4)	2014(5)
Proved Developed Producing	525.8	413.9	4,752.5	4,110.0	92,379.7	73,094.8	185	155	184.9	154.9	0.0	0.0
Total Proved	1,842.0	1,453.6	14,756.4	12,933.9	321,752.4	255,208.2	516	443	505.2	432.2	1,623.7	1,712.1
Total Proved Plus Probable	2,945.7	2,343.2	25,865.7	21,798.2	516,821.4	412,336.2	723	622	698.8	598.8	2,667.7	2,769.4

	(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)	With respect to Birchcliff's natural gas reserves attributable to its Montney/Doig Natural Gas Resource Play, such reserves would most closely fit within the category of shale gas as such term is defined in NI 51-101.
	(3)	Light crude oil and medium crude oil (combined) and NGL have been combined in the table above as the NGL reserves are not material.
	(4)	Includes approximately $57 million of capital for the Phase V expansion of the PCS Gas Plant to 260 MMcf per day of total throughput, plus $45.8 million of capital for the Phase VI expansion of the PCS Gas Plant to 340 MMcf per day of total throughput, plus $46.5 million of capital for additional pipelines and compression projects during 2016 to 2018, all in the proved category. Also includes approximately $84.3 million of capital for the Phase VII expansion of the PCS Gas Plant to 420 MMcf per day of total throughput, plus $17.9 million of capital for additional pipeline and compression projects during 2018 and 2019, all in the probable category.
	(5)	Includes approximately $97 million of capital for the Phase V expansion of the PCS Gas Plant to 240 MMcf per day of total throughput, together with the related gathering pipelines, sales pipeline expansion and compression, plus $61 million of capital for the Phase VI expansion of the PCS Gas Plant to 300 MMcf per day of total throughput, plus $56 million of capital for additional pipelines and compression projects during 2016 to 2020, all in the proved category. Also includes approximately $89 million of capital for the Phase VII expansion of the PCS Gas Plant to 360 MMcf per day of total throughput in the probable category.

Montney/Doig Land and Horizontal Natural Gas Well Data
	Dec 31, 2015		Dec 31, 2014		Dec 31, 2013
	Gross	Net	Gross	Net	Gross	Net
Number of sections to which Deloitte attributed proved plus probable reserves	150.6	145.9	139.6	133.7	129.6	114.9
For existing and future horizontal wells, number of well locations to which Deloitte attributed proved plus probable reserves	723	698.8	622	598.8	549	470.8
For existing and future horizontal wells, average number of net well locations per net section to which Deloitte attributed proved plus probable reserves	4.8(1)		4.5(2)		4.1(3)
For existing horizontal wells, average remaining proved plus probable reserves attributed by Deloitte, plus cumulative production	5.3 Bcfe(4)		4.9 Bcfe(4)		4.9 Bcfe
For future horizontal wells, average remaining proved plus probable reserves attributed by Deloitte	4.7 Bcfe		4.3 Bcfe		4.2 Bcfe
Average cost per well, forecast by Deloitte	$4.4 million		$5.3 million		$5.2 million

	(1)	For existing and future horizontal wells, the average number of net well locations per net section to which Deloitte attributed proved plus probable reserves is 3.1 for the Basal Doig/Upper Montney interval and 3.1 for the Montney D1 interval.
	(2)	For existing and future horizontal wells, the average number of net well locations per net section to which Deloitte attributed proved plus probable reserves is 3.1 for the Basal Doig/Upper Montney interval and 2.9 for the Montney D1 interval.
	(3)	For existing and future horizontal wells, the average number of net well locations per net section to which Deloitte attributed proved plus probable reserves is 3.2 for the Basal Doig/Upper Montney interval and 2.9 for the Montney D1 interval.
	(4)	Does not include the four Montney horizontal light oil wells in Section 17-078-11W6M.

Deloitte has attributed Montney/Doig proved plus probable reserves to 150.6 (145.9 net) sections of land. Deloitte has attributed reserves: (i) in the Montney D1 interval to 131.3 (127.9 net) sections of land, an increase of 12.7 net sections of land from 2014; (ii) in the Montney D4 interval to 22 (22.0 net) sections of land, an increase of 15.0 net sections of land from 2014; (iii) in the Montney C interval to 2 (2.0 net) sections of land, which is unchanged from 2014; and (iv) in the Basal Doig/Upper Montney interval to 94.3 (90.7 net) sections of land, an increase of 10.7 net sections of land from 2014. There are now 84 (82.4 net) sections to which Deloitte has attributed reserves to both the Basal Doig/Upper Montney interval and the Montney D1 interval.

Management believes that the ultimate recovery from Birchcliff's Montney/Doig horizontal natural gas wells will continue to improve year-over-year as production declines continue to flatten. In addition, as drilling and completion technologies continue to improve, recovery factors and production rates in this unconventional reservoir should also improve.

Reserves on the Charlie Lake Light Oil Resource Play - Worsley Area

At December 31, 2015, Deloitte estimated that in the Worsley Charlie Lake light oil pool, Birchcliff had 41.1 MMboe proved plus probable reserves and 21.9 MMboe of proved reserves. This continues the growth trend for Birchcliff's Worsley Charlie Lake reserves since July 1, 2007 (being the effective date of the acquisition of this property), when reserves were estimated at 15.1 MMboe on a proved plus probable basis and 11.3 MMboe on a proved basis. The reserves continue to increase and Birchcliff is pleased to report that the Worsley Charlie Lake light oil pool continues to be a top quality asset.

History of Reserves Estimated for the Worsley Charlie Light Oil Lake Pool (MMboe)(1)

Reserves Category	Dec 31, 2015	Dec 31, 2014	Dec 31, 2013	Dec 31, 2012	Dec 31, 2011	Dec 31, 2010	Dec 31, 2009	Dec 31, 2008	Dec 31, 2007	July 1, 2007
Proved	21.9	20.5	19.6	19.6	18.8	18.8	18.3	17.5	15.0	11.3
Proved Plus Probable	41.1	40.2	38.9	34.7	31.3	28.2	26.3	24.6	21.2	15.1

(1)

Estimates of reserves for individual properties may not reflect the same confidence level as estimates of reserves for all properties due to the effects of aggregation.

2015 FINDING AND DEVELOPMENT COSTS

During 2015, Birchcliff's finding and development ("F&D") costs were $257 million and its FD&A costs were $246 million. The following table sets forth Birchcliff's estimates of its F&D costs per boe and FD&A costs per boe, excluding FDC and including FDC, on a proved developed producing, proved and proved plus probable basis.

F&D and FD&A Costs ($/boe)(1)
Excluding FDC		2015	2014	2013	Three Year Average
	F&D - Proved Developed Producing	$8.11	$13.40	$14.94	$11.64
	F&D - Proved	$3.09	$8.29	$5.85	$5.21
	F&D - Proved Plus Probable	$2.06	$5.96	$4.11	$3.60
	Total FD&A - Proved Developed Producing	$7.79	$12.81	$12.71	$10.89
	Total FD&A - Proved	$2.96	$6.03	$4.91	$4.52
	Total FD&A - Proved Plus Probable	$2.02	$4.19	$3.46	$3.12
Including FDC(2)(3)(4)
	F&D - Proved	$2.41	$13.51	$9.39	$7.22
	F&D - Proved Plus Probable	$1.55	$12.57	$9.03	$6.32
	Total FD&A - Proved	$2.28	$11.56	$8.29	$7.02
	Total FD&A - Proved Plus Probable	$1.32	$10.45	$8.60	$6.23

	(1)	See "Advisories - Oil and Gas Metrics" for a description of the methodology used to calculate F&D and FD&A costs.
	(2)	Includes the 2015 decrease in FDC from 2014 of $56.5 million on a proved basis and $85.4 million on a proved plus probable basis, which decreases are primarily due to the application of new technology, operational efficiencies and a reduction in service costs.
	(3)	Includes the 2014 increase in FDC from 2013 of $413.0 million on a proved basis and $671.9 million on a proved plus probable basis.
	(4)	Includes the 2013 increase in FDC from 2012 of $147.1 million on a proved basis and $316.7 million on a proved plus probable basis.

Changes in forecast FDC occur annually as a result of development activities, acquisition and disposition activities and capital cost estimates that reflect Deloitte's best estimate of what it will cost to bring the proved and proved plus probable reserves on production.

Deloitte's estimates of FDC are $1.81 billion on a proved basis, a decrease from $1.87 billion for 2014, and $3.09 billion on a proved plus probable basis, a decrease from $3.18 billion for 2014. These FDC costs are primarily the capital costs required to drill, complete, equip and tie-in undeveloped locations. The estimates also include approximately $252 million on a proved plus probable basis for the expansion of the PCS Gas Plant to 420 MMcf per day of total throughput, together with the related gathering pipelines, sales pipeline expansion and compression, which is down from the $303 million in the 2014 Reserves Evaluation due to the capital that has already been spent and the design efficiencies that have lowered costs for the Phase VI expansion.

Deloitte's estimates of the FDC per Montney/Doig horizontal natural gas well to which reserves were assigned in the 2015 Reserves Evaluation decreased 17% to an average of $4.4 million per well as at December 31, 2015, compared to $5.3 million contained in the 2014 Reserves Evaluation. This decrease is primarily due to the application of new technology, operational efficiencies and a reduction in service costs.

2015 RECYCLE RATIOS

The following table shows Birchcliff's recycle ratios for operating and funds flow netbacks, which are calculated in each case by dividing the average operating netback per boe or funds flow netback per boe, as the case may be, by each of the F&D costs and the FD&A costs.

Recycle Ratios(1)
		Operating Netback(2) Recycle Ratio		Funds Flow Netback(2) Recycle Ratio
		2015	2014	2015	2014
Excluding FDC
	F&D - Proved Developed Producing	1.8	2.1	1.4	1.8
	FD&A - Proved Developed Producing	1.9	2.2	1.5	1.9
	F&D - Proved	4.7	3.3	3.7	2.9
	FD&A - Proved	4.9	4.6	3.8	4.0
	F&D - Proved Plus Probable	7.0	4.7	5.5	4.1
	FD&A - Proved Plus Probable	7.2	6.6	5.6	5.8
Including FDC
	F&D - Proved	6.0	2.1	4.7	1.8
	FD&A - Proved	6.4	2.4	5.0	2.1
	F&D - Proved Plus Probable	9.3	2.2	7.3	1.9
	FD&A - Proved Plus Probable	11.0	2.7	8.6	2.3

	(1)	See "Advisories" for a description of the methodology used to calculate F&D costs, FD&A costs and recycle ratios.
	(2)	See "Non-GAAP Measures".

During 2015, the average WTI price of crude oil was US$48.80 per bbl and the average price of natural gas at AECO was CDN$2.69 per Mcf. Operating netback per boe was $14.52 in 2015, compared to $27.77 in 2014. Funds flow netback per boe was $11.31 in 2015, compared to $24.40 in 2014.

2016 PRODUCTION GUIDANCE AND OPERATIONAL UPDATE

Current Production Update and Production Guidance for 2016

Birchcliff estimates that its production for January 2016 averaged approximately 42,000 boe per day.

Based on Birchcliff's recently announced capital expenditure program of $140 million (the "2016 Capital Program"), which is discussed in further detail below, Birchcliff expects its annual average production in 2016 to be between 40,000 and 41,000 boe per day, which represents a range of 3% to 5% growth over Birchcliff's annual average production of 38,950 boe per day in 2015.

2016 Capital Program

The 2016 Capital Program is designed to achieve modest production growth, while further progressing the Phase V expansion of the PCS Gas Plant. Details of the 2016 Capital Program are as follows:

2016 Capital Program
		Gross Wells	Net Wells	Capital ($millions)
Drilling & Development
	Montney D1 Horizontal Gas Wells	8.0	8.0	34.1
	Basal Doig/Upper Montney Horizontal Gas Wells	4.0	4.0	17.0
	Montney D4 Horizontal Gas Wells	2.0	2.0	8.1
	Charlie Lake Horizontal Light Oil Wells	1.0	1.0	2.5
	2015 Carry Forward Capital(1)	-	-	5.2
Total Drilling & Development(2)		15.0	15.0	66.9
Facilities & Infrastructure(3)				39.5
Production Optimization				13.5
Land & Seismic				5.5
Other				14.6
Total Capital				$140.0 million

	(1)	Primarily completion, equipping and tie-in costs associated with 2 (2.0 net) wells rig released at the end of 2015.
	(2)	On a drill, case, complete, equip and tie-in basis.
	(3)	Includes approximately $24.9 million of capital in 2016 for the PCS Gas Plant Phase V expansion.

Birchcliff expects to fund the 2016 Capital Program using internally generated funds flow and not increase its 2016 year-end debt over year-end 2015. The 2016 Capital Program is projected to be less than Birchcliff's expected funds flow for 2016, based on a forecast average WTI price of US$40.00 per barrel of oil and a forecast average AECO price of CDN$2.50 per GJ of natural gas during 2016. As the 2016 Capital Program is projected to be less than Birchcliff's expected funds flow for 2016, this will provide Birchcliff with continued financial flexibility and protect its balance sheet.

For further details regarding the 2016 Capital Program, please see Birchcliff's press release dated January 21, 2016.

Update on Natural Gas Transportation Capacity

Virtually all of Birchcliff's natural gas production is transported on TransCanada's NGTL System in Alberta pursuant to both firm and interruptible service agreements. Throughout 2015 and into 2016, interruptible service has been suspended and transportable volumes have been curtailed from time to time to as low as 85% of Birchcliff's firm service entitlements as a result National Energy Board ordered pipeline integrity testing procedures and other operational issues with TransCanada's NGTL System.

Birchcliff currently has in place firm service contracts that in the aggregate provide transportation capacity slightly above the processing capacity of its own processing facilities and sufficient transportation capacity to meet its processing commitments at third party processing facilities. Additional firm transportation of 20 MMcf per day is contracted to become available to Birchcliff in April 2016 and Birchcliff expects to have firm transportation capacity sufficient to transport the majority of the increased production volumes that are expected to result from the proposed Phase V expansion of the PCS Gas Plant discussed below.

Update on the PCS Gas Plant

The PCS Gas Plant has a processing capacity of 180 MMcf per day of raw gas and is currently processing natural gas at or near maximum capacity.

Engineering, procurement and fabrication work is underway for the Phase V expansion of the PCS Gas Plant which will increase processing capacity to 260 MMcf per day from 180 MMcf per day. The 2016 Capital Program includes approximately $24.9 million of capital for the Phase V expansion of the PCS Gas Plant. Birchcliff currently estimates that approximately $30 million will be required to complete the field construction of the Phase V expansion. Birchcliff currently expects that the Phase V expansion will be completed in 2017, subject to an improvement in commodity prices and general economic conditions. The completion of Phase V of the PCS Gas Plant will be timed to coincide with the drilling of additional Montney/Doig horizontal natural gas wells to fill or partially fill the expanded PCS Gas Plant, so that operational momentum will not be lost and ensuring capital is only spent when required.

In addition, the design and licencing work is complete for the Phase VI expansion of the PCS Gas Plant which will increase processing capacity to 340 MMcf per day from 260 MMcf per day. Birchcliff currently expects that the Phase VI expansion will be completed in late 2018 or early 2019, depending primarily on commodity prices and general economic conditions.

Update on Drilling

The 2016 Capital Program is focused on Birchcliff's two proven resource plays, the Montney/Doig Natural Gas Resource Play and the Charlie Lake Light Oil Resource Play. The 2016 Capital Program contemplates the drilling of 15 (15.0 net) wells, consisting of 14 (14.0 net) Montney/Doig horizontal natural gas wells in the Pouce Coupe area and 1 (1.0 net) Charlie Lake horizontal light oil well at Worsley. The 14 Montney/Doig wells will be on three pads - one 2-well pad and two 6-well pads. All three pads are already tied-in to Birchcliff's infrastructure system, minimizing equipping and tie-in costs.

Birchcliff has drilled 2 (2.0 net) wells year-to-date, consisting of 1 (1.0 net) Montney/Doig horizontal natural gas wells in the Pouce Coupe area and 1 (1.0 net) Charlie Lake horizontal light oil well in the Worsley area. The Charlie Lake horizontal light oil well was drilled to continue 18 sections of land that could have expired and also to extend the pool to the northeast.

Birchcliff currently has 2 drilling rigs at work, both of which are drilling Montney/Doig horizontal natural gas wells in the Pouce Coupe area.

Birchcliff actively employs the evolving technology utilized by the industry regarding horizontal well drilling and the related multi-stage fracture stimulations. Birchcliff is currently utilizing multi-well pad drilling which allows it to reduce its per well costs as well as to reduce its environmental footprint.

Montney/Doig Natural Gas Resource Play

Over Birchcliff's 11 years of focused multi-disciplinary efforts on the Montney/Doig Natural Gas Resource Play, it has learned a great deal about this complex reservoir and how to optimally drill, case, complete and produce horizontal wells utilizing recent horizontal drilling and multi-stage fracture stimulation technology. Birchcliff has continued to improve its results by reducing its costs on a per boe basis and increasing its production and reserves per well. Birchcliff continues to expand the Montney/Doig Natural Gas Resource Play both geographically and stratigraphically.

Specific completion enhancements that Birchcliff has been employing over the past three years have resulted in significant individual well performance improvements. As a result of the strong production performance from Birchcliff's Montney/Doig horizontal natural gas wells drilled in 2015, 2014 and 2013 and the new reserves established by its 2015 drilling program, Birchcliff achieved material increases to its proved developed producing, total proved and proved plus probable reserves on many of its existing producing wells and material reserves additions to its related future undeveloped drilling locations at year-end 2015. See "2015 Independent Reserves Evaluation".

Birchcliff has achieved long-term reductions in both its operating and capital costs as a result of the hard work of its people, the advancement of horizontal drilling and completion technologies, the implementation of operating and capital cost reduction initiatives and efficient project execution. In addition, the collapse in oil prices and continued low natural gas prices have led to shorter-term cost reductions in most aspects of its business.

Exploration and Development Activities in the Montney D4 Interval in the Elmworth and Pouce Coupe Areas

In July 2014, Birchcliff drilled its first exploration well in the Montney D4 interval in the Pouce Coupe area. As at December 31, 2015, Birchcliff has drilled a total of seven 100% working interest wells in the Montney D4 interval. Five of these wells are in the Pouce Coupe area and the remaining two are in the Elmworth area. The Montney D4 interval is prospective over most of Birchcliff's Pouce Coupe land base where Birchcliff has existing infrastructure and its scalable PCS Gas Plant. This infrastructure is expected to result in development and operational efficiencies and cost savings as Birchcliff continues to develop the Montney D4 interval.

In the fourth quarter of 2014, Birchcliff drilled its first successful Montney/Doig horizontal exploration well in the Montney D4 interval in the Elmworth area. Birchcliff subsequently drilled its second successful horizontal exploration well in the Elmworth area in the Montney D4 interval in the first quarter of 2015, which was brought on production in June 2015. The success of these two Montney D4 wells in the Elmworth area has added significant potential future drilling locations to Birchcliff's inventory and is expected to result in follow-up drilling by Birchcliff and future additions to its reserves volumes.

As part of Birchcliff's future growth plans for its Montney/Doig Natural Gas Resource Play, it is continuing to prove up the play in the Elmworth area and in the next few years it intends to construct and operate a 100% owned natural gas plant in the Elmworth area (the "Elmworth Gas Plant"). Birchcliff has commenced the preliminary planning for this plant and a critical requirement is a nearby acid gas disposal well which Birchcliff drilled in the first quarter of 2015. In the second and third quarters of 2015, Birchcliff conducted successful injectivity tests on the well and is preparing the required regulatory application for an acid gas disposal scheme.

Land and Potential Future Drilling Locations

Birchcliff's land activities during 2015 on the Montney/Doig Natural Gas Resource Play included the acquisition of 20 sections, all at 100% working interest, 9 sections of which were in the heart of its Pouce Coupe area and 11 sections of which were in its Elmworth area. As at December 31, 2015, Birchcliff held 333.9 sections of land that have potential for the Montney/Doig Natural Gas Resource Play. Of these lands, 309.9 (293.7 net) sections have potential for the Basal Doig/Upper Montney interval, 317.4 (308.0 net) sections have potential for the Montney D1 interval and 293.4 (287.0 net) sections have potential for the Montney D4 interval. As at December 31, 2015, Birchcliff's total land holdings on these three intervals were 920.8 (888.8 net) sections.

On full development of four horizontal wells per section per drilling interval, Birchcliff has 3,555.2 net existing horizontal wells and potential net future horizontal drilling locations in respect of the Basal Doig/Upper Montney, Montney D1 and Montney D4 intervals as at December 31, 2015. With 188 (187.9 net) horizontal locations drilled at the end of 2015, there remains 3,367.3 potential net future horizontal drilling locations as at December 31, 2015, up from 3,346.3 net at year end 2014. This does not include any potential net future horizontal drilling locations for the other three prospective Montney intervals, the Montney C, the Montney D2 and the Montney D3.

Substantial upside exists with respect to the 3,552.2 net existing horizontal wells and potential net future horizontal drilling locations. The 2015 Reserves Evaluation attributed proved reserves to 505.2 net existing wells and potential net future horizontal drilling locations (of which 320.3 net wells are potential future drilling locations) and proved plus probable reserves to 698.8 net existing wells and potential net future horizontal drilling locations (of which 513.9 net wells are potential future drilling locations). The remaining 2,853.4 potential net future horizontal drilling locations have not yet had any proved or probable reserves attributed to them by Deloitte.

See "Advisories - Drilling Locations".

Charlie Lake Light Oil Resource Play

Exploration and Development Activities in the Worsley Area

Due to low oil prices during 2015, Birchcliff did not conduct any drilling activities on its Worsley property. Birchcliff did spend significant time and effort optimizing the existing wells, existing waterflood and infrastructure to assist with production profiles and reduce decline rates.

Early in 2016, Birchcliff drilled a Charlie Lake horizontal light oil well that will continue 18 sections of land and delineate the pool to the northeast. Additional activities during 2016 include the conversion of 2 wells in the waterflood area to injectors to further enhance the waterflood scheme.

Exploration and Development Activities in the Progress Area

In the fourth quarter of 2014, Birchcliff drilled its first successful 100% working interest Charlie Lake horizontal exploration well in the Progress area, which was brought on production in December 2014. This well produced at an average rate of 300 bbls per day of light oil and 1.8 MMcf per day of natural gas for a total of 600 boe per day for the first 30 days of production. As at January 31, 2016, this well was producing at an average rate of 45 bbls per day of light oil and 0.72 MMcf per day of natural gas for a total of 165 boe per day with a 39% water cut.

In the second quarter of 2015, Birchcliff drilled its second successful 100% working interest Charlie Lake horizontal light oil exploration well in its Progress area, which was brought on production in August 2015. This well produced at an average rate of 85 bbls per day of light oil and 2.2 MMcf per day of natural gas for a total of 450 boe per day for the first 30 days of production. As at January 31, 2016, this well was producing at an average rate of 83 bbls per day of light oil and 4.0 MMcf per day of natural gas for a total of 750 boe per day with a 46% water cut.

As at December 31, 2015, Birchcliff held 28 (27.5 net) sections of land in the Progress area on the Charlie Lake Light Oil Resource Play, compared to 26.5 (25.75 net) sections as at December 31, 2014. In the first quarter of 2015, Birchcliff acquired a new 3-D seismic program in the Progress area to help delineate its Charlie Lake Light Oil Resource Play exploration success. The results of this seismic program are very encouraging and support management's belief that a significant amount of Birchcliff's lands have potential for this play.

Birchcliff is currently developing a full scale development plan for its Progress Charlie Lake Light Oil Resource Play.

See "Advisories - Initial Production Rates".

Update on the Veracel Reassessment

Neither the Trial Decision nor an unsuccessful outcome of the appeal to the Court of Appeal will result in any current cash taxes payable by Birchcliff. As discussed above, the Trial Court denied Birchcliff's appeal of the Reassessment. The Reassessment was based on the CRA's position that the tax pools available to Veracel Inc. ("Veracel"), prior to its amalgamation with Birchcliff, ceased to be available to Birchcliff after Birchcliff and Veracel amalgamated on May 31, 2005 (the "Veracel Transaction"). Birchcliff appealed the Reassessment to the Trial Court and the trial of that appeal occurred in November 2013. On October 1, 2015, the Trial Court issued its decision (the "Trial Decision") and dismissed Birchcliff's appeal on the basis of the general anti-avoidance rule contained in the Income Tax Act (Canada). Birchcliff has appealed the Trial Decision to the Court of Appeal and expects that appeal to be heard in 2016. Management continues to believe that its tax position is appropriate and will be upheld by the Court of Appeal; however, Birchcliff has decided to record a deferred income tax expense in the amount of $10.2 million in the fourth quarter as a result of the Trial Decision being rendered. See "2015 Year-End Financial and Operational Results" and "2015 Fourth Quarter Financial and Operational Results".

PRESIDENT'S REMARKS

Jeff Tonken, President and Chief Executive Officer of Birchcliff, stated:

"Our proved plus probable reserves increased 23% to 572.9 MMboe as at December 31, 2015. The future net revenue from these reserves (discounted at 10%) increased slightly to approximately $3.9 billion from $3.8 billion in 2014, notwithstanding materially lower commodity price forecasts.

Our proved developed producing reserves were added at $7.79 per boe during 2015. This means that we added proved developed producing reserves for approximately 2/3 of the funds flow netback we received on the sale of production, which is the true test of a low-cost finder and producer of oil and gas.

Our 2015 operational results are very strong, with record annual average production of 38,950 boe per day, a 15% increase from 2014, while total cash costs of $11.01 per boe were down 21% from 2014.

Birchcliff has proven that its business works at low commodity prices and our operational execution has been on budget and on time.

Financial and Operating Results

We had record annual average production of 38,950 boe per day, which represents a 15% increase over our 2014 annual average production of 33,734 boe per day. We achieved this record production notwithstanding the fact that our production was adversely impacted by the numerous firm and interruptible service curtailments on TransCanada's NGTL System that occurred during 2015.

Funds flow was $160.8 million, a 46% decrease from 2014, which is largely a result of the decrease in commodity prices. After excluding certain one-time, non-operational, deferred income tax expense items in the aggregate amount of $18.0 million, we recorded adjusted net income to common shareholders of $1.8 million in 2015. Net loss to common shareholders was $16.2 million.

We had record low operating costs of $4.54 per boe and record low general and administrative expense of $1.61 per boe during 2015, which we believe are some of the lowest in our industry. Our operating costs were down 13% and our general and administrative expense was down 11% from 2014. Operating costs per boe decreased from 2014 largely due to the continued cost benefits achieved from processing incremental volumes of natural gas through our PCS Gas Plant, the continued implementation of various cost saving and optimization initiatives and lower service costs due to reduced industry activity. General and administrative expense decreased from 2014 largely due to increased sales volumes during 2015, with the modest addition of new employees.

We continued to achieve drilling success on our Montney/Doig Natural Gas Resource Play during 2015. We drilled a second successful horizontal exploration well in the Elmworth area in the Montney D4 interval in the first quarter of 2015, which was brought on production in June 2015. In total, we have 3,367.3 potential net future horizontal drilling locations on our Montney/Doig Natural Gas Resource Play as at December 31, 2015.

As a result of the strong production performance from our Montney/Doig horizontal natural gas wells drilled in 2015, 2014 and 2013 and the new reserves established by our 2015 drilling program, we achieved material increases to our proved developed producing, total proved and proved plus probable reserves volumes at year-end 2015.

Positive technical revisions accounted for 17% of the proved developed producing reserve additions, 31% of the proved reserve additions and 29% of the proved plus probable reserve additions in 2015. These positive revisions for proved and proved plus probable reserves, which did not require any increase to FDC, can be attributed to Deloitte's recognition of improved well production performance from our 2015, 2014 and 2013 drilling programs. These technical revisions primarily resulted from the continued advancement of our drilling and completion technologies and improved well production performance on some of our existing wells. Improved well performance, coupled with reduced well costs, support Birchcliff in having top tier capital efficiencies.

We achieved the above while posting an operating netback recycle ratio of 1.9 times and a funds flow netback recycle ratio of 1.5 times on our proved developed producing reserves. We have proven our business is economically viable in the current commodity price environment and our operational execution has been on budget and on time.

Outlook for 2016

With respect to 2016, our board of directors recently approved our capital expenditure program in the amount of $140 million which is focused on protecting our balance sheet, maintaining production and continued investment in the Phase V expansion of our 100% owned Pouce Coupe South gas plant and related infrastructure to position us for future growth. We expect that our capital expenditure program for 2016 will be less than our estimated funds flow for the year, thereby protecting our balance sheet and maintaining financial flexibility. As a result of our high quality asset base, our forecast base production decline is low at approximately 20% for 2016 which gives us the ability to spend very little money to keep production flat. We are forecasting our 2016 annual average production to be 40,000 to 41,000 boe per day, which is anticipated to result in a year-over-year production increase of approximately 3% to 5%.

Based on our 2016 Capital Program, our costs to drill, case, complete, equip and tie-in our Montney/Doig horizontal natural gas wells are expected to average approximately $4.0 million per well during 2016. The combination of these decreased capital costs and the improved well performance that we are now realizing is expected to have a positive effect on our capital efficiencies and internal rates of return.

If in 2017 commodity prices remain low, we believe we could spend approximately $90 million of capital and run flat between 40,000 to 41,000 boe per day.

Our $800 million revolving credit facilities have a three-year term to May 11, 2018 and contain no financial covenants. As at December 31, 2015, our long-term bank debt was $622.1 million from available credit facilities of approximately $800 million, which provides us with financial flexibility.

These attributes have positioned us to withstand the collapse in commodity prices. As a result of operating essentially all of our production and having virtually 100% working interests and control of our infrastructure, we have the flexibility to speed up or slow down our capital expenditures very quickly. This operational flexibility becomes very important when commodity prices change quickly.

We remain focused on our strategy, growth by the drill bit, in our core area of the Peace River Arch of Alberta. We continue to use the same services, in the same area, directed by the same experienced Birchcliff personnel, which provides consistency, repeatability and reliability in our operations.

We thank Mr. Seymour Schulich, our largest shareholder, for his advice, unwavering commitment and his ongoing financial support. Mr. Schulich holds 42 million common shares representing 27.6% of the current issued and outstanding common shares. His purchase of 2 million common shares in December 2015 at $3.90 per share is a recent example of his extraordinary commitment to Birchcliff when our stock and industry is under serious pressure from the negative sentiment from low commodity prices.

On behalf of our management team and our board of directors, I thank all of our staff for their hard work and dedication to the achievement of our corporate goals. Thank you to all of our shareholders for your continued support and trust in all of us at Birchcliff."

(Signed) A. Jeffery Tonken

President and Chief Executive Officer

Birchcliff Energy Ltd.

ABBREVIATIONS

AECO	physical storage and trading hub for natural gas on the TransCanada Alberta transmission system which is the delivery point for various benchmark Alberta index prices
bbl	barrel
bbls	barrels
Bcf	billion cubic feet
Bcfe	billion cubic feet of gas equivalent
boe	barrel of oil equivalent
F&D	finding and development
FD&A	finding, development and acquisition
FDC	future development capital
GJ	gigajoule
IFRS	International Financial Reporting Standards
Mbbl	thousand barrels
Mboe	thousand barrels of oil equivalent
Mcf	thousand cubic feet
Mcfe	thousand cubic feet of gas equivalent
MMboe	million barrels of oil equivalent
MMbtu	million British Thermal Units
MMcf	million cubic feet
NGL	natural gas liquids
WTI	West Texas Intermediate oil at Cushing, Oklahoma, the benchmark for North American crude oil pricing
000s	thousands
$000s	thousands of dollars
MM$	millions of dollars

NON-GAAP MEASURES

This press release uses "funds flow", "funds flow from operations", "funds flow per common share", "adjusted net income to common shareholders", "adjusted net loss to common shareholders", "netback", "operating netback", "estimated operating netback", "funds flow netback", "operating margin", "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.

"Funds flow" and "funds flow from operations" denote cash flow from operating activities before the effects of decommissioning expenditures and changes in non-cash working capital. "Funds flow per common share" denotes funds flow divided by the basic or diluted weighted average number of common shares outstanding for the period. Management believes that funds flow, funds flow from operations and funds flow per common share assists 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, pay dividends on preferred shares and repay debt. The following table provides a reconciliation of cash flow from operating activities, as determined in accordance with IFRS, to funds flow from operations:

		Three months ended December 31,				Twelve months ended December 31,
($000s)		2015		2014		2015	2014
Cash flow from operating activities		44,786		77,513		148,797	309,901
Adjustments:
	Decommissioning expenditures	247		263		893	1,663
	Change in non-cash working capital	(11,336	)	(16,059	)	11,066	(11,066	)
Funds flow from operations		33,697		61,717		160,756	300,498

"Adjusted net income (loss) to common shareholders" is calculated as net income (loss) to common shareholders, as determined in accordance with IFRS, after excluding: (i) a one-time, non-cash deferred income tax expense in the amount of $7.8 million that was recorded in the second quarter of 2015 as a result of the 2015 change in the Alberta corporate income tax rate from 10% to 12%; and (ii) a one-time, non-cash deferred income tax expense in the amount of $10.2 million that was recorded in the fourth quarter of 2015 as a result of the denial by the Trial Court of Birchcliff's appeal of the Reassessment in connection with the tax pools available to Veracel. See "2016 Production Guidance and Operational Update - Update on the Veracel Reassessment". Management has excluded these non-operational, deferred income tax items from net income to common shareholders as management believes that excluding such items better reflects the results generated by Birchcliff's principal business activities. The following table provides a reconciliation of net income (loss) to common shareholders, as determined in accordance with IFRS, to adjusted net income to common shareholders:

		Three months ended December 31,			Twelve months ended December 31,
($000s)		2015		2014	2015		2014
Net income (loss) to common shareholders		(10,322	)	16,053	(16,160	)	110,304
Adjustments:
	Denial by the Trial Court of the Reassessment Appeal	10,208		-	10,208		-
	Change in Alberta corporate income tax rates	-		-	7,759		-
Adjusted net income (loss) to common shareholders		(114	)	16,053	1,807		110,304

The deferred income tax adjustments shown in the table above have no impact on the current cash taxes payable by Birchcliff.

"Netback" and "operating netback" denote petroleum and natural gas revenue less royalties, less operating expenses and less transportation and marketing expenses. "Estimated operating netback" of the PCS Gas Plant (and the components thereof) is based upon certain cost allocations and accruals directly attributable to the PCS Gas Plant and related wells and infrastructure on a production month basis. "Funds flow netback" denotes petroleum and natural gas revenue less royalties, less operating expenses, less transportation and marketing expenses, less net general and administrative expenses, less interest expenses 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. Management believes that netback, operating netback, estimated operating netback and funds flow netback assists 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.

"Operating margin" for the PCS Gas Plant is calculated by dividing the estimated 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 PCS Gas Plant and Birchcliff's ability to generate operating cash flows (equal to petroleum and natural gas revenue less royalties, less operating expenses and less transportation and marketing expenses).

"Total cash costs" are comprised of royalties, operating, transportation and marketing, general and administrative and interest expense. Management believes that total cash costs assists management and investors in assessing Birchcliff's overall cash cost structure.

"Total debt" is calculated as the revolving term credit facilities plus non-revolving term credit facilities plus 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 non‐revolving term credit facilities plus the revolving term credit facilities, as determined in accordance with IFRS, to total debt:

As at,($000s)		December 31, 2015	December 31, 2014
	Non-revolving term credit facilities	-	129,476
	Revolving term credit facilities	622,074	339,557
	Long-term bank debt	622,074	469,033
	Working capital deficit	21,538	76,712
Total debt		643,612	545,745

DISCLOSURE OF OIL AND GAS RESERVES

Reserve 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.
  
  

• "Possible reserves" are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves.

Development and Production Status of Reserves

Each of the reserves categories (proved, probable and possible) may be divided into developed and undeveloped categories:

• "Developed reserves" are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g., when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and non-producing.
  
  

  • "Developed producing reserves" are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.
    
    

  • "Developed non-producing reserves" are those reserves that either have not been on production, or have previously been on production but are shut-in and the date of resumption of production is unknown.
    
    

• "Undeveloped reserves" are those reserves expected to be recovered from known accumulations where a significant expenditure (e.g., when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves category (proved, probable, possible) to which they are assigned.
  
  In multi-well pools it may be appropriate to allocate total pool reserves between the developed and undeveloped categories or to subdivide the developed reserves for the pool between developed producing and developed non-producing. This allocation should be based on the estimator's assessment as to the reserves that will be recovered from specific wells, facilities, and completion intervals in the pool and their respective development and production status.

Levels of Certainty for Reported Reserves

The qualitative certainty levels referred to in the definitions above are applicable to "individual reserves entities", which refers to the lowest level at which reserves calculations are performed, and to "reported reserves", which refers to the highest level sum of individual entity estimates for which reserves estimates are presented. Reported reserves should target the following levels of certainty under a specific set of economic conditions:

	•	at least a 90% probability that the quantities actually recovered will equal or exceed the estimated proved reserves;
	•	at least a 50% probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves; and
	•	at least a 10% probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable plus possible reserves.

A quantitative measure of the certainty levels pertaining to estimates prepared for the various reserves categories is desirable to provide a clearer understanding of the associated risks and uncertainties. However, the majority of reserves estimates are prepared using deterministic methods that do not provide a mathematically derived quantitative measure of probability. In principle, there should be no difference between estimates prepared using probabilistic or deterministic methods.

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.

Forecast Prices and Costs

"Forecast prices and costs" means future prices and costs that are:

(a)	generally accepted as being a reasonable outlook of the future;
(b)	if, and only to the extent that, there are fixed or presently determinable future prices or costs to which Birchcliff is legally bound by a contractual or other obligation to supply a physical product, including those for an extension period of a contract that is likely to be extended, those prices or costs rather than the prices and costs referred to in paragraph (a).

ADVISORIES

Unaudited Numbers: Birchcliff's annual audit of its financial statements is not yet complete and accordingly, all financial amounts referred to in this press release are unaudited.

Currency: All amounts in this press release are stated in Canadian dollars unless otherwise specified.

Boe Conversions: Boe amounts have been calculated by using the conversion ratio of 6 Mcf of natural gas to 1 bbl of oil. Boe amounts may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf to 1 bbl 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.

Mcfe and Bcfe Conversions: Mcfe and Bcfe amounts have been calculated by using the conversion ratio of 1 bbl of oil to 6 Mcf of natural gas. Mcfe and Bcfe amounts may be misleading, particularly if used in isolation. A conversion ratio of 1 bbl to 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 Conversion: $1.00 per MMbtu equals $1.00 per Mcf based on a standard heat value Mcf.

Reserve Estimates and Forecast Prices: Deloitte prepared the 2015 Reserves Evaluation, the 2014 Reserves Evaluation and a reserves estimation and economic evaluation effective December 31, 2013. In addition, Deloitte or its predecessors, AJM Deloitte and AJM Petroleum Consultants, prepared reserves evaluations in respect of Birchcliff's oil and natural gas properties effective December 31, 2012, 2011, 2010, 2009, 2008 and 2007. 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 the quantities of reserves and the future net revenues attributed to those reserves. There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. The recovery and reserves estimates of Birchcliff's oil, natural gas and NGL reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual oil, natural gas and NGL reserves may be greater than or less than the estimates provided herein and variances could be material.

Gross Company Reserves: In this press release, all references to "reserves" are to Birchcliff's gross company reserves.

Reserves for Portion of Properties: 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.

Future Net Revenue: Estimates of future net revenue, whether discounted or not, do not represent fair market value.

Oil and Gas Metrics: This press release contains metrics commonly used in the oil and gas industry, including netback, reserve life index, recycle ratio, reserve replacement, F&D costs and FD&A costs. These oil and gas metrics do not have do not have any standardized meanings and may not be comparable to similar measures presented by other companies where similar terminology is used and should not be used to make comparisons. As a result, readers are cautioned as to the reliability of such metrics.

• Reserve life index is calculated by dividing reserves estimated by Deloitte at December 31, 2015 by 40,500 boe per day, which production rate represents the mid-point of Birchcliff's annual average production guidance range for 2016. Reserve 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 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.
  
  

• Reserve 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. Reserve 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 acquisition and dispositions. FD&A costs are calculated in the same manner as F&D costs but include the effect 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 Deloitte, Birchcliff's independent qualified reserves evaluator, 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 potential drilling locations in three categories: (i) proved locations; (ii) probable locations; and (iii) unbooked locations. Proved locations and probable locations are proposed drilling locations identified in the 2015 Reserves Evaluation that have proved and/or probable reserves, as applicable, attributed to them in the 2015 Reserves Evaluation. 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 do not have proved or probable reserves attributed to them. Of the 3,552.2 net existing horizontal wells and potential net future horizontal drilling locations identified herein, 505.2 are proved locations, 698.8 are probable locations and 2,853.4 are unbooked locations. Unbooked locations are potential locations that have been identified by management based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that Birchcliff will drill all unbooked drilling locations and if drilled, there is no certainty that such locations will result in additional proved or probable reserves, resources or production. The drilling locations on which Birchcliff actually drills wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional geological, geophysical and reservoir information that is obtained and other factors. While certain of the unbooked drilling locations have been derisked by drilling existing wells in relative 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 therefore there is 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 and other short-term production rates for any wells are not determinative of the rates at which such wells will continue to produce and decline thereafter and are not necessarily indicative of the long‐term performance or the ultimate recovery of such wells. Such rates may be based on field estimates and may be based on limited data available at the time. Readers are cautioned not to place reliance on such rates in calculating aggregate production for Birchcliff or the assets for which such rates are provided.

Operating Costs: References in this press release to "operating costs" exclude transportation and marketing costs.

Forward-Looking Information: This press release contains forward-looking information within the meaning of applicable Canadian securities laws. Forward-looking information relates to future events or future performance and is based upon Birchcliff's current internal expectations, estimates, projections, assumptions and beliefs. All information other than historical fact is forward-looking information. Information relating to reserves is forward-looking as it involves the implied assessment, based on certain estimates and assumptions, that the reserves exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future. Words such as "plan", "expect", "project", "intend", "believe", "anticipate", "estimate", "estimated", "forecast", "may", "will", "potential", "proposed" and other similar words that convey certain events or conditions "may" or "will" occur are intended to identify forward-looking information.

In particular, this press release contains forward-looking information relating to: Birchcliff's plans and other aspects of its anticipated future operations, management focus, strategies and priorities; expected results from Birchcliff's portfolio of oil and gas assets and results of operations; estimates of future drilling locations and opportunities; estimates of reserves and the net present values of future net revenue associated with Birchcliff's reserves; price forecasts; future development capital; reserve life index; decline rates and Birchcliff's forecast base production decline rate for 2016, which decline rate gives Birchcliff the ability to spend very little money to keep production flat; Birchcliff's expectation that two operating cost reduction initiatives that it has implemented are expected to further reduce costs over the long term at the PCS Gas Plant; Birchcliff's expectation that the Credit Facilities will remain at $800 million during Birchcliff's normal credit review in May 2016 and that it will request an extension to the maturity date from May 11, 2018 to May 11, 2019; the 2016 Capital Program, including planned capital expenditures, Birchcliff's plan to drill a total of 15 (15.0 net) wells, Birchcliff's expectation that it will fund the 2016 Capital Program using internally generated funds flow and not increase its 2016 year-end debt over year-end 2015, the objectives of and anticipated results from the 2016 Capital Program, including anticipated production growth and financial flexibility, and Birchcliff's expectation that the 2016 Capital Program will be less than expected funds flow for 2016; Birchcliff's flexibility to adjust the level of its capital expenditures and Birchcliff's financial and operational flexibility; Birchcliff's proposed exploration and development activities and the timing thereof, including wells to be drilled; Birchcliff's production guidance for 2016, including its estimates of its annual average production for 2016 and 2016 annual average production growth; proposed expansions of the PCS Gas Plant, including the anticipated processing capacities of the PCS Gas Plant after such expansions, the anticipated timing of such expansions and the estimated cost to achieve such expansions; statements that additional firm transportation of 20 MMcf per day is contracted to become available to Birchcliff in April 2016 and that Birchcliff expects to have firm transportation capacity sufficient to transport the majority of the increased production volumes that are expected to result from the proposed Phase V expansion of the PCS Gas Plant; Birchcliff's expectation that infrastructure in the Pouce Coupe area will result in development and operational efficiencies and cost savings with respect to the development of the Montney D4 interval; the success of Birchcliff's two Montney D4 wells in the Elmworth area is expected to result in follow-up drilling by Birchcliff and future additions to its reserves volumes;
Birchcliff's future growth plans for the Elmworth area, including Birchcliff's intention to construct and operate the Elmworth Gas Plant and the anticipated timing thereof; management's belief that the ultimate recovery from Birchcliff's Montney/Doig horizontal natural gas wells will continue to improve year-over-year as production declines continue to flatten; expectations that as drilling and completion technologies continue to improve, recovery factors and production rates in the Montney/Doig Natural Gas Resource Play should also improve; Birchcliff's expectation that it will release its audited results for the year ended December 31, 2015 on March 16, 2016, along with the results of its independent Montney/Doig Natural Gas Resource Assessment; statements with respect to the Reassessment, including Birchcliff's expectation that its appeal to the Court of Appeal will be heard in 2016 and management's belief that its tax position is appropriate and will be upheld by the Court of Appeal; Birchcliff's costs to drill, case, complete, equip and tie-in its Montney/Doig horizontal natural gas wells are expected to average approximately $4.0 million per well during 2016; the combination of decreased capital costs and the improved well performance that Birchcliff is now realizing is expected to have a positive effect on its capital efficiencies and internal rates of return; and Birchcliff's belief that if in 2017 commodity prices remain low, it could spend approximately $90 million of capital and run flat between 40,000 to 41,000 boe per day.

The forward-looking information contained in this press release is based upon certain expectations and assumptions, including: prevailing and future commodity prices, currency exchange rates, interest rates, inflation rates, royalty rates and tax rates; the state of the economy and the exploration and production business; the economic and political environment in which Birchcliff operates; the regulatory framework regarding royalties, taxes and environmental laws; anticipated timing and results of capital expenditures; the sufficiency of budgeted capital expenditures to carry out planned operations; results of operations; operating, transportation, marketing and general and administrative costs; the performance of existing and future wells, well production rates and well decline rates; well drainage areas; success rates for future drilling; reserves and resource volumes and Birchcliff's ability to replace and expand oil and gas reserves through acquisition, development or exploration; the impact of competition; the availability of, demand for and cost of labour, services and materials; Birchcliff's ability to access capital; the ability to obtain financing on acceptable terms; the ability to obtain any necessary regulatory approvals in a timely manner; the ability of Birchcliff to secure adequate transportation for its products; and Birchcliff's ability to market oil and gas. In addition, Birchcliff has made the following key assumptions with respect to certain forward-looking information contained in this press release:

• With respect to estimates of reserves volumes and the net present values of future net revenue associated with Birchcliff's reserves, the key assumption is the validity of the data used by Deloitte in their independent reserves evaluations.
  
  

• With respect to statements regarding decline rates, the key assumption is the validity of the geological and other technical interpretations performed by Birchcliff's technical staff.
  
  

• With respect to statements that the Credit Facilities will remain at $800 million during Birchcliff's normal credit review in May 2016, the key assumptions are that: commodity prices do not further deteriorate from current levels; the criteria applied by Birchcliff's syndicate of bank lenders remains consistent with historical practice; and the bank syndicate's forecast of commodity prices are consistent with the forecast used by Deloitte in the preparation of the 2015 Reserves Evaluation.
  
  

• With respect to statements regarding the 2016 Capital Program, including Birchcliff's expectation that the 2016 Capital Program will be less than expected funds flow for 2016, the key assumption is that Birchcliff realizes the annual average production target of 40,000 to 41,000 boe per day and the commodity prices upon which the 2016 Capital Program is based, being an expected annual average WTI price of US$40.00 per barrel of oil and an AECO price of CDN$2.50 per GJ of natural gas during 2016 with an exchange rate of $CDN/$US of 1.40. Birchcliff will monitor economic conditions and commodity prices and, where deemed prudent, will adjust the 2016 Capital Program to respond to changes in commodity prices and other material changes in the assumptions underlying the 2016 Capital Program.
  
  

• With respect to statements of future wells to be drilled and estimates of future drilling locations and opportunities, the key assumptions are: the validity of the geological and other technical interpretations performed by Birchcliff's technical staff, which indicate that commercially economic volumes can be recovered from Birchcliff's lands as a result of drilling future wells; and that commodity prices and general economic conditions warrant proceeding with the drilling of such wells.
  
  

• With respect to estimates as to Birchcliff's annual average production for 2016 and 2016 annual average production growth, the key assumptions are that: the 2016 Capital Program will be carried out as currently contemplated; no unexpected outages occur in the infrastructure that Birchcliff relies on to produce its wells and that any transportation service curtailments or unplanned outages that occur will be short in duration or otherwise insignificant; the construction of new infrastructure meets timing expectations; existing wells continue to meet production expectations; and future wells scheduled to come on production meet timing, production and capital expenditure expectations.
  
  

• With respect to statements regarding proposed expansions of the PCS Gas Plant, including the anticipated processing capacities of the PCS Gas Plant after such expansions and the anticipated timing of such expansions, the key assumptions are that: future drilling is successful; there is sufficient labour, services and equipment available; Birchcliff will have access to sufficient capital to fund those projects; and commodity prices and general economic conditions warrant proceeding with the construction of such facilities and the drilling of associated wells.
  
  

• With respect to statements regarding Birchcliff's intention to construct and operate the Elmworth Gas Plant and the timing thereof, the key assumptions are that: future drilling in the Elmworth area is successful; the acid gas disposal well drilled by Birchcliff is capable of handling the volumes of acid gas to be produced at the plant and complies with all regulatory requirements; there is sufficient labour, services and equipment available; Birchcliff will have access to sufficient capital to fund the Elmworth Gas Plant; and commodity prices and general economic conditions warrant proceeding with the construction of the Elmworth Gas Plant and the drilling of associated wells.
  
  

• With respect to statements that the success of Birchcliff's two Montney D4 wells in the Elmworth area is expected to result in follow‐up drilling by Birchcliff and future reserves additions, the key assumptions are that: future drilling is successful; there is sufficient labour, services and equipment available; Birchcliff will have access to sufficient capital to fund such future drilling; and commodity prices and general economic conditions warrant proceeding with such future drilling. In addition, statements regarding future reserve additions assume that in conducting its reserves evaluation, Birchcliff's independent reserves evaluator will concur with Birchcliff's internal technical interpretations.
  
  

• With respect to Birchcliff's expectation that infrastructure in the Pouce Coupe area will result in development and operational efficiencies and cost savings with respect to the development of the Montney D4 interval, the key assumption is that such infrastructure will be in proximity to the wells proposed to be drilled in that area.
  
  

• With respect to statements regarding management's belief that its tax position with respect to the Veracel Transaction is appropriate and will be upheld by the Court of Appeal, the key assumption is the validity of Birchcliff's interpretation of how the Income Tax Act (Canada) applies to the Veracel Transaction.
  
  

• With respect to Birchcliff's belief that if in 2017 commodity prices remain low, it could spend approximately $90 million of capital and run flat between 40,000 to 41,000 boe per day, the key assumptions are that: drilling results in 2017 will be consistent with historical drilling results; and drilling, completion, equipping and tie-in costs do not exceed current levels.

Undue reliance should not be placed on forward-looking information, as there can be no assurance that the plans, intentions, expectations or assumptions upon which they are based will occur. Although Birchcliff believes that the expectations and assumptions reflected in the forward-looking information are reasonable, there can be no assurance that such expectations will prove to be correct. As a consequence, actual results may differ materially from those anticipated.

Forward-looking information necessarily involves both known and unknown risks and uncertainties that could cause actual results to differ materially from those anticipated, including, but not limited to: general economic, market and business conditions which will, among other things, impact the demand for and market prices of Birchcliff's products and Birchcliff's access to capital; volatility of crude oil and natural gas prices; fluctuations in currency and interest rates; operational risks and liabilities inherent in oil and natural gas operations; uncertainties associated with estimating oil and natural gas reserves and resources; the accuracy of oil and natural gas reserves estimates and estimated production levels as they are affected by exploration and development drilling and estimated decline rates; geological, technical, drilling, construction and processing problems; uncertainty of geological and technical data; changes in tax laws, crown royalty rates, environmental laws and incentive programs relating to the oil and gas industry and other actions by government authorities, including changes to the royalty and carbon tax regimes and the imposition or reassessment of taxes; the cost of compliance with current and future environmental laws; political uncertainty and uncertainty associated with government policy changes; uncertainties and risks associated with pipeline restrictions and outages to third-party infrastructure that could cause disruptions to production; the inability to secure adequate production transportation for Birchcliff's products; the occurrence of unexpected events such as fires, equipment failures and other similar events affecting Birchcliff or other parties whose operations or assets directly or indirectly affect Birchcliff; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; stock market volatility; loss of market demand; environmental risks, claims and liabilities; incorrect assessments of the value of acquisitions and exploration and development programs; shortages in equipment and skilled personnel; uncertainties associated with the outcome of litigation or other proceedings involving Birchcliff; competition for, among other things, capital, acquisitions of reserves, undeveloped lands, equipment and skilled personnel; and uncertainties associated with credit facilities and counterparty credit risk.

The foregoing list of risk factors is not exhaustive. Additional information on these and other risk factors that could affect operations or financial results are included in Birchcliff's most recent Annual Information Form and in other reports filed with Canadian securities regulatory authorities. Forward-looking information is based on estimates and opinions of management at the time the information is presented. Birchcliff is not under any duty to update the forward-looking information after the date of this press release to conform such information to actual results or to changes in Birchcliff's plans or expectations, except as otherwise required by applicable securities laws.

Any "financial outlook" contained in this press release, as such term is defined by applicable securities laws, is provided for the purpose of providing information about management's current expectations and plans relating to the future. Readers are cautioned that reliance on such information may not be appropriate for other purposes.

About Birchcliff:

Birchcliff is a Calgary, Alberta-based intermediate oil and gas company with operations concentrated within its one core area, the Peace River Arch of Alberta. Birchcliff's common shares and cumulative redeemable preferred shares, Series A and Series C are listed for trading on the Toronto Stock Exchange under the symbols "BIR", "BIR.PR.A" and "BIR.PR.C", respectively.