Birchcliff Energy Ltd. Provides Operational Update and

CALGARY, ALBERTA--(Marketwired - March 18, 2015) -

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

Birchcliff Energy Ltd. ("Birchcliff" or the "Corporation") (TSX:BIR) is pleased to provide an operational update and announce its 2014 audited financial statements. The 2014 audited financial statements are consistent with the unaudited financial results contained in the press release issued by Birchcliff on February 11, 2015. The full text of the 2014 audited financial statements and the related management's discussion and analysis, as well as Birchcliff's Annual Information Form and Form 51-101F1 - Statement of Reserves Data and Other Oil and Gas Information for the year ended December 31, 2014, will be available on Birchcliff's website at www.birchcliffenergy.com and on SEDAR at www.sedar.com.

Certain information contained in this press release is repeated from Birchcliff's February 11, 2015 press release, including the 2014 financial and operational results and highlights from the 2014 Independent Reserves Evaluation and the 2014 Independent Montney/Doig Natural Gas Resource Assessment.

Birchcliff confirms that it expects average annual production in 2015 to be between 38,000 and 40,000 boe per day and that it expects average production for the first quarter of 2015 to be approximately 37,000 to 38,000 boe per day.

Jeff Tonken, President and Chief Executive Officer of Birchcliff, stated: "Birchcliff's production remains very strong while our cost structure continues to improve. With low base production declines, financial flexibility and a clearly focused asset base, we are well positioned to show annual production growth notwithstanding the most recent weak commodity price cycle. Our strategy of growth by the drill bit with repeatable, low-cost drilling opportunities provides for low-cost production and reserve additions, on a consistent year-over-year basis, giving Birchcliff the confidence that it can grow in these difficult times. Birchcliff expects its average annual production in 2015 will grow approximately 16% from 2014, all from the drill bit. Our goal is to continue to reduce our costs to effectively operate in a low commodity price environment to optimize our returns."

PRESS RELEASE HIGHLIGHTS

2015 Production Estimates

Average annual production for 2015 is expected to be between 38,000 and 40,000 boe per day, with plans to drill 25 (24.5 net) wells in 2015.
Current production is approximately 38,000 boe per day.
First quarter average production forecast to be approximately 37,000 to 38,000 boe per day, consisting of 85% natural gas, 11% light oil and 4% natural gas liquids.

2015 Operational Update

Exploration success in the Elmworth area in the Montney D4 Interval on the Montney/Doig Natural Gas Resource Play - A 100% working interest Montney/Doig horizontal natural gas well was drilled in the Elmworth area was recently completed and is expected to be brought on production by the end of March 2015.
Year-to-date drilling results include the drilling of 12 (11.5 net) wells, consisting of 9 (9.0 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 (0.5 net) Halfway horizontal light oil well in the Progress area and a 100% working interest Belloy vertical well drilled as a potential acid gas injection well in the Elmworth area.
Birchcliff currently has 2 drilling rigs working, both of which are in the Pouce Coupe area drilling Montney/Doig horizontal natural gas wells.

2014 Year-End Financial and Operational Results

Record average annual production of 33,734 boe per day, a 31% increase over 2013 average production of 25,829 boe per day. Production per common share increased 26% from 2013.
Record funds flow of $300.5 million ($2.03 per basic common share), a 72% increase from 2013.
Fifth consecutive year of earnings. Record net income of $114.3 million, a 75% increase from $65.4 million in 2013. Net income to common shareholders increased to $110.3 million ($0.75 per basic common share) in 2014 as compared to $61.4 million ($0.43 per basic common share) in 2013.
Operating costs of $5.22 per boe, down 8% from $5.68 per boe in 2013.
General and administrative costs of $1.81 per boe, down 17% from $2.19 per boe in 2013.
Top tier operating performance at Birchcliff's Pouce Coupe South Natural Gas Plant (the "PCS Gas Plant"). Operating costs averaged $0.42 per Mcfe in 2014 at the PCS Gas Plant.
Cash costs of $11.03 per boe (comprised of operating, transportation and marketing, general and administrative and interest costs), down 13% from $12.61 per boe in 2013.
Capital expenditures in 2014 were $450.9 million, which includes a $56.0 million strategic acquisition of a partner's 30% working interest in land and production in the Pouce Coupe area which closed in January of 2014.
Long-term bank debt of $469.0 million against available lines of credit of approximately $750 million. Total year-end debt, including the adjusted working capital deficit of $76.7 million, was $545.7 million.
Drilled a total of 57 (56.0 net) wells in 2014, consisting of:
- 37 (37.0 net) horizontal wells on Birchcliff's Montney/Doig Natural Gas Resource Play, which included 3 (3.0 net) exploration successes;
- 4 (4.0 net) Montney/Doig light oil horizontal wells, which were successful;
- 11 (11.0 net) horizontal wells on Birchcliff's Worsley Charlie Lake Light Oil Resource Play;
- 1 (1.0 net) horizontal well on Birchcliff's Progress Charlie Lake Light Oil Resource Play, which was an exploration success;
- 1 (1.0 net) horizontal well on Birchcliff's Upper Doig Light Oil Play, which was successful; and
- 3 (2.0 net) horizontal wells on Birchcliff's Halfway Light Oil Play, which were successful.
Undeveloped land base of 506,621.5 (478,295.1 net) acres at December 31, 2014, with a 94% average working interest.
Added 28,810.2 (28,426.2 net) acres of undeveloped land in 2014, substantially all at 100% working interest and all within Birchcliff's core area of the Peace River Arch of Alberta.
Birchcliff's potential net future horizontal drilling locations on the Montney/Doig Natural Gas Resource Play increased by 48% to 3,346.3 at December 31, 2014 from 2,254.4 at year-end 2013, predominantly as a result of Birchcliff's Montney D4 drilling success.

2014 Fourth Quarter Financial and Operational Results

Fourth quarter production averaged 37,704 boe per day, a 10% increase over production of 34,235 boe per day in the third quarter of 2014 and a 33% increase from 28,391 boe per day in the fourth quarter of 2013.
Quarterly funds flow of $61.7 million, an 18% decrease from the third quarter of 2014 and a 23% increase from the fourth quarter of 2013.
Net income of $17.1 million, a 43% decrease from the third quarter of 2014 and a 54% decrease from the fourth quarter of 2013.
Operating costs of $5.33 per boe, up 5% from $5.06 per boe in the third quarter of 2014 and down 2% from $5.44 per boe in the fourth quarter of 2013.
Capital expenditures of $109.7 million.
Drilled 15 (14.5 net) wells in the fourth quarter of 2014, comprised of 11 (11.0 net) Montney/Doig horizontal natural gas wells, 2 (2.0 net) Montney/Doig horizontal light oil wells, 1 (1.0 net) Charlie Lake horizontal light oil well and 1 (0.5 net) Halfway horizontal light oil well, all of which were successful.

2014 Exploration Successes

Exploration success in the Pouce Coupe area in the Montney D4 Interval on the Montney/Doig Natural Gas Resource Play - A new Birchcliff Montney interval has been proven commercial.
Exploration success in the Elmworth area in the Montney D4 Interval on the Montney/Doig Natural Gas Resource Play - A new Birchcliff Montney exploration area has been proven commercial.
Exploration success in the Pouce Coupe area in the Montney C Interval on the Montney/Doig Natural Gas Resource Play - The early results from this first well in a new Birchcliff Montney interval are encouraging.
Exploration success in the Progress area on the Charlie Lake Light Oil Resource Play - In our area immediately east of Pouce Coupe, a new Birchcliff Charlie Lake Light Oil exploration area has been proven commercial.

2014 Independent Reserves Evaluation

Proved developed producing reserves of 84.7 MMboe, a 37% increase from 62.0 MMboe at December 31, 2013. This represents an increase of 22.7 MMboe.
Birchcliff added 35.0 MMboe of proved developed producing reserves, a 56% increase over Birchcliff's proved developed producing reserves at December 31, 2013 after taking into account 2014 production of 12.3 MMboe.
Proved reserves of 282.3 MMboe, a 28% increase from 220.0 MMboe at December 31, 2013. This represents an increase of 62.3 MMboe.
Proved plus probable reserves of 465.0 MMboe, a 26% increase from 370.1 MMboe at December 31, 2013. This represents an increase of 94.9 MMboe. Birchcliff added 8.71 boe of proved plus probable reserves for each boe that was produced in 2014.
Proved developed producing reserve additions replaced 285% of 2014 production, proved reserve additions replaced 606% of 2014 production and proved plus probable reserve additions replaced 871% of 2014 production.
Reserve life index of 6.0 years on a proved developed producing basis, 19.8 years on a proved basis and 32.7 years on a proved plus probable basis, in each case assuming an average daily production rate of 39,000 boe per day.

2014 Finding, Development and Acquisition ("FD&A") Costs and Recycle Ratios

FD&A costs on a proved developed producing basis of $12.81 per boe.
FD&A costs on a proved basis of $6.03 per boe, excluding future development capital, and $11.56 per boe, including future development capital.
FD&A costs on a proved plus probable basis of $4.19 per boe, excluding future development capital, and $10.45 per boe, including future development capital.
Operating netback recycle ratio of 2.2 and funds flow netback recycle ratio of 1.9 based on FD&A costs and proved developed producing reserve additions.
Operating netback recycle ratio of 2.4 and funds flow netback recycle ratio of 2.1, in each case including future development costs, based on FD&A costs and proved reserve additions.
Operating netback recycle ratio of 2.7 and funds flow netback recycle ratio of 2.3, in each case including future development costs, based on FD&A costs and proved plus probable reserve additions.

2014 Independent Montney/Doig Natural Gas Resource Assessment

A significant amount of resources that were categorized as prospective resources at the end of 2013 have been categorized by Deloitte LLP ("Deloitte"), Birchcliff's independent qualified reserves evaluator, as contingent resources at December 31, 2014. In addition, a portion of Birchcliff's contingent and prospective resources recognized at December 31, 2013 have been categorized as reserves at December 31, 2014.
On a best estimate basis, reflecting Birchcliff's working interest:
- total petroleum initially-in-place ("PIIP") of 50.1 Tcfe;
- contingent resources of 7.9 Tcfe, a 20.0% increase from December 31, 2013;
- total discovered PIIP of 20.7 Tcfe, a 17.8% increase from December 31, 2013;
- prospective resources of 13.7 Tcfe, a 13.3% decrease from December 31, 2013; and
- total undiscovered PIIP of 29.4 Tcfe, a 14.6% decrease from December 31, 2013.

2015 Capital Budget and Guidance

2015 capital budget of $266.7 million (including $59.0 million for infrastructure), with plans to drill 25 (24.5 net) wells.
Birchcliff expects average annual production in 2015 to be between 38,000 and 40,000 boe per day.
The 2015 capital budget has been reduced from Birchcliff's preliminary capital expenditure estimated range of $450 million to $500 million which was announced in November of 2014. Birchcliff will adjust its 2015 capital budget to respond to changes in commodity prices and other material changes in the assumptions underlying its 2015 budget.

2015 OUTLOOK

Birchcliff expects average production for the first quarter of 2015 to be approximately 37,000 to 38,000 boe per day, consisting of 85% natural gas, 11% light oil and 4% natural gas liquids.

Birchcliff expects average annual production in 2015 to be between 38,000 and 40,000 boe per day.

Birchcliff's 2015 capital budget is $266.7 million (including $59.0 million for infrastructure), with plans to drill 25 (24.5 net wells). Birchcliff has negotiated reductions in its service costs. Although it is too early to quantify, Birchcliff anticipates 10 to 15% cost reductions to its capital budget for 2015. For further details regarding Birchcliff's 2015 capital budget, see "2015 Capital Budget" in this press release.

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

2015 OPERATIONAL UPDATE

Exploration Success

Year-to-date, Birchcliff had a further exploration success in the Elmworth area in the Montney D4 interval on the Montney/Doig Natural Gas Resource Play. The Elmworth area encompasses the Sinclair area and was previously described by Birchcliff as the Elmworth/Sinclair area.

Exploration Success in the Elmworth Area in the Montney D4 Interval on the Montney/Doig Natural Gas Resource Play

Birchcliff recently drilled its second successful exploration well on the Montney/Doig Natural Gas Resource Play in its Elmworth area. This 100% working interest well has been drilled, completed and tested and is expected to be on production by the end of March 2015. In the fourth quarter of 2014, Birchcliff drilled its first successful Montney/Doig horizontal exploration well in its Elmworth area. The success of these two new wells in the Elmworth area has added significant potential future drilling locations and is expected to result in follow-up drilling by Birchcliff and significant future reserves additions.

Production and Drilling Results

Current production is approximately 38,000 boe per day.

Year-to-date drilling results include the drilling of 12 (11.5 net) wells, consisting of 9 (9.0 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 (0.5 net) Halfway horizontal light oil well in the Progress area and a 100% working interest Belloy vertical well drilled as a potential acid gas injection well in the Elmworth area.

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

2014 FINANCIAL AND OPERATIONAL HIGHLIGHTS

		Three months ended December 31,				Twelve months ended December 31,
		2014		2013		2014		2013
OPERATING
Average daily production
	Light oil - (barrels)	3,957		4,227		3,957		4,030
	Natural gas - (thousands of cubic feet)	192,499		138,132		169,852		125,712
	NGLs - (barrels)	1,664		1,142		1,469		847
	Total - barrels of oil equivalent (6:1)⁽¹⁾	37,704		28,391		33,734		25,829
Average sales price ($ CDN)⁽²⁾
	Light oil - (per barrel)	71.87		81.52		92.39		89.89
	Natural gas - (per thousand cubic feet)	3.91		3.81		4.74		3.41
	NGLs - (per barrel)	66.10		85.45		85.13		88.45
Total - barrels of oil equivalent(6:1)⁽¹⁾		30.43		34.10		38.39		33.52
NETBACK AND COST ($ per barrel of oil equivalent at 6:1)⁽¹⁾
	Petroleum and natural gas revenue⁽²⁾	30.44		34.11		38.41		33.59
	Royalty expense	(1.84	)	(2.68	)	(2.99	)	(2.92	)
	Operating expense	(5.33	)	(5.44	)	(5.22	)	(5.68	)
	Transportation and marketing expense	(2.39	)	(2.52	)	(2.43	)	(2.46	)
Netback⁽³⁾		20.88		23.47		27.77		22.53
	General & administrative expense, net	(2.02	)	(2.54	)	(1.81	)	(2.19	)
	Interest expense	(1.42	)	(1.77	)	(1.57	)	(2.28	)
	Other Income	-		-		-		0.44
	Realized gain on financial instruments	0.35		-		0.01		-
Funds flow netback⁽³⁾		17.79		19.16		24.40		18.50
	Stock-based compensation expense, net	(0.26	)	(0.37	)	(0.39	)	(0.43	)
	Depletion and depreciation expense	(11.17	)	(11.70	)	(11.07	)	(11.54	)
	Accretion expense	(0.16	)	(0.24	)	(0.20	)	(0.23	)
	Amortization of deferred financing fees	(0.06	)	(0.10	)	(0.08	)	(0.09	)
	Gain on sale of assets	0.91		12.93		0.26		3.58
	Unrealized gain (loss) on financial instruments	0.05		(0.15	)	0.03		(0.04	)
	Dividends on Series C preferred shares	(0.25	)	(0.33	)	(0.28	)	(0.20	)
	Income tax expense	(1.93	)	(5.01	)	(3.39	)	(2.61	)
Net income		4.92		14.19		9.28		6.94
	Dividends on Series A preferred shares	(0.29	)	(0.38	)	(0.32	)	(0.43	)
Net income to common shareholders		4.63		13.81		8.96		6.51
FINANCIAL
Petroleum and natural gas revenue ($000s)⁽²⁾		105,598		89,092		472,888		316,637
Funds flow from operations ($000s)⁽³⁾		61,717		50,060		300,498		174,361
	Per common share - basic ($)⁽³⁾	0.41		0.35		2.03		1.22
	Per common share - diluted ($)⁽³⁾	0.40		0.34		1.97		1.20
Net income ($000s)		17,053		37,062		114,304		65,417
Net income to common shareholders ($000s)		16,053		36,062		110,304		61,417
	Per common share - basic ($)	0.11		0.25		0.75		0.43
	Per common share - diluted ($)	0.10		0.25		0.72		0.42
Common shares outstanding (000s)
	End of period - basic	152,214		143,677		152,214		143,677
	End of period - diluted	166,302		163,548		166,302		163,548
	Weighted average common shares for period - basic	152,183		143,063		147,764		142,422
	Weighted average common shares for period - diluted	155,304		145,319		152,243		145,006
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		1,913
Capital expenditures, net ($000s)		109,682		18,188		450,932		215,770
Long-term bank debt ($000s)		469,033		393,967		469,033		393,967
Adj. working capital deficit ($000s)⁽³⁾		76,712		60,071		76,712		60,071
Total debt ($000s)⁽³⁾		545,745		454,038		545,745		454,038

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

2014 YEAR-END FINANCIAL AND OPERATIONAL RESULTS

2014 Production

Record production in 2014 averaged 33,734 boe per day, which is a 31% increase over 2013 average production of 25,829 boe per day. Production per common share increased 26% from 2013. This increase was achieved through the success of Birchcliff's capital drilling program and increased incremental production from new horizontal natural gas wells on the Montney/Doig Natural Gas Resource Play that are processed through Birchcliff's PCS Gas Plant.

Production consisted of approximately 84% natural gas and 16% crude oil and natural gas liquids in 2014. Approximately 78% of Birchcliff's natural gas production and 69% of corporate production was processed at the PCS Gas Plant during 2014.

The following table highlights Birchcliff's average annual production per day per common share growth since 2010.

	2010	2011	2012	2013	2014	Change Since 2010		Average Annual Growth
Average annual production (boe/day )	13,079	18,136	22,802	25,829	33,734	158	%	40	%
Production per day per million common shares⁽¹⁾(boe)	104.9	143.6	166.3	181.4	228.3	118	%	30	%

⁽¹⁾	Based on annual average production and weighted average basic common shares outstanding in the respective year.

2014 Funds Flow and Earnings

2014 funds flow was approximately $300.5 million ($2.03 per basic common share), a 72% increase from 2013. This increase was largely a result of a 35% increase in natural gas production, a 42% increase in the average AECO natural gas spot price from $3.17 per Mcf in 2013 to $4.50 per Mcf in 2014 and lower operating costs on a per unit basis. Primarily as a result of the decrease in commodity prices in the fourth quarter of 2014, funds flow for 2014 was less than our previous guidance of $331 million ($2.24 per basic common share) which was based, in part, on an AECO natural gas price of $4.50 per GJ ($4.75 per Mcf) and a WTI oil price of US$99.50 per bbl (Edmonton Par CDN$101.00 per bbl).

For the year ended 2014, Birchcliff had cash costs of $11.03 per boe (comprised of operating, transportation and marketing, general and administrative and interest costs), down 13% from $12.61 per boe in 2013.

Birchcliff had record net income of $114.3 million in 2014, a 75% increase from $65.4 million in 2013. Net income to common shareholders increased to $110.3 million ($0.75 per basic common share) in 2014 as compared to $61.4 million ($0.43 per basic common share) in 2013. This represents an 80% increase in net income to common shareholders from 2013 and is mainly due to increased natural gas production and higher realized natural gas prices.

This is Birchcliff's fifth consecutive year of earnings, which demonstrates that Birchcliff's repeatable, low-cost business continues to be successful and continues to generate positive returns for its shareholders.

2014 Debt and Capitalization

At December 31, 2014, Birchcliff's long-term bank debt was $469.0 million from available credit facilities of approximately $750 million leaving $281 million (37%) of unutilized capacity which provides significant financial flexibility. Total debt, including the adjusted working capital deficit of $76.7 million, was $545.7 million, as compared to $454.0 million at December 31, 2013.

Birchcliff expects that as a result of material reserve additions in 2014 in the proved developed producing category, its bank credit facilities will be increased during its normal credit review in May of 2015.

At December 31, 2014, Birchcliff had 152,214,206 basic common shares outstanding.

2014 Operating and G&A Costs

Operating costs in 2014 were $5.22 per boe, down 8% from $5.68 per boe in 2013. This reduction of operating costs on a per boe basis was largely due to the cost benefits achieved from processing increased volumes of natural gas through the PCS Gas Plant and implementation of various optimization initiatives.

General and administrative expenses of $1.81 per boe were down 17% from $2.19 per boe in 2013 and Birchcliff expects this trend to continue as Birchcliff increases production without having to add significant additional resources.

2014 Capital Expenditures

During the year ended December 31, 2014, Birchcliff had capital expenditures of $450.9 million, which includes a $56.0 million strategic acquisition of a partner's 30% working interest in land and production in the Pouce Coupe area which closed in January of 2014.

2014 PCS Gas Plant Netbacks

Processing natural gas at the PCS Gas Plant has materially improved Birchcliff's funds flow and net earnings since it first became operational in March 2010.

In 2014, operating costs for natural gas processed at the PCS Gas Plant averaged $0.42 per Mcfe and the estimated operating netback for Birchcliff's natural gas production flowing to the PCS Gas Plant was $4.21 per Mcfe, achieving an operating margin of 81%. In 2014, Birchcliff processed approximately 78% of its corporate natural gas production at the PCS Gas Plant.

The volume of high value liquids recovered at the PCS Gas Plant in 2014, which are primarily condensate, has increased to 8.0 bbls per MMcf from 5.7 bbls per MMcf compared to 2013.

The following table details Birchcliff's annual net production and 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, 2014						Twelve months ended December 31, 2013						Twelve months ended December 31, 2012
Average daily production, net to Birchcliff:
	Natural gas (Mcf)					132,808						91,666						59,327
	Oil & NGLs (bbls)					1,065						527						204
Total boe (6:1)⁽¹⁾						23,200						15,805						10,092
Sales liquids yield (bbls/MMcf)						8.0						5.7						3.4

% of corporate natural gas production						78	%					73	%					56	%
% of corporate production						69	%					61	%					44	%

AECO Average Spot Price ($/Mcf)		$	4.50					$	3.17					$	2.39

Netback and cost:			$/Mcfe			$/boe			$/Mcfe			$/boe			$/Mcfe			$/boe
	Petroleum and natural gas revenue		5.17			31.02			3.77			22.64			2.91			17.44
	Royalty expense		(0.24	)		(1.42	)		(0.16	)		(0.93	)		(0.11	)		(0.67	)
	Operating expense		(0.42	)		(2.52	)		(0.37	)		(2.24	)		(0.35	)		(2.08	)
	Transportation and marketing expense		(0.30	)		(1.81	)		(0.25	)		(1.55	)		(0.23	)		(1.37	)
Estimated operating netback⁽²⁾		$	4.21		$	25.27		$	2.99		$	17.92		$	2.22		$	13.32
Operating margin⁽²⁾			81	%		81	%		79	%		79	%		76	%		76	%

⁽¹⁾	See "Advisories".
⁽²⁾	See "Non-GAAP Measures".

As illustrated in the table below, after Birchcliff began processing natural gas at the PCS Gas Plant in early 2010, total corporate operating costs on a per boe basis have trended downward as increasing production volumes have been processed at the PCS Gas Plant.

To view accompanying graph, visit the following link: http://media3.marketwire.com/docs/997430-F1.pdf

2014 Drilling Program

Birchcliff's 2014 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 employs the evolving technology utilized by leaders in the industry regarding horizontal well drilling and the related multi-stage fracture stimulation technology.

During 2014, Birchcliff drilled 57 (56.0 net) wells, consisting of 37 (37.0 net) natural gas wells and 20 (19.0 net) oil wells. The natural gas wells are all Montney/Doig horizontal wells. The oil wells included 4 (4.0 net) Montney/Doig horizontal oil wells, 11 (11.0 net) Worsley Charlie Lake horizontal light oil wells, 1 (1.0 net) Progress Charlie Lake horizontal light oil well, 3 (2.0 net) Halfway horizontal light oil wells and 1 (1.0 net) Upper Doig horizontal light oil well. All horizontal wells drilled in 2014 utilized recent advancements in multi-stage fracture stimulation technology.

2014 Land

Birchcliff's undeveloped land base at December 31, 2014 was 506,621.5 (478,295.1 net) acres, with a 94% average working interest. During 2014, Birchcliff added 28,810.2 (28,426.2 net) acres, or 45.0 (44.4 net) sections of undeveloped land, substantially all at 100% working interest, and all in Birchcliff's core area of the Peace River Arch of Alberta.

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. Substantially all of the new land has been purchased without partners at 100% working interest.

Birchcliff continued to strategically add lands on resource plays during 2014. The following table summarizes Birchcliff's land holdings on the following resource plays at December 31, 2014.

Resource Play Land Holdings

		December 31, 2014
Resource Play		Working Interest		Gross (acres)	Net (acres)
Montney/Doig Natural Gas Resource Play
	Basal Doig/Upper Montney Interval	94.5	%	195,264	184,579
	Montney D4 Interval	97.6	%	184,704	180,288
	Montney D1 Interval	96.9	%	202,304	195,968
	Montney C Interval	96.9	%	202,304	195,968
Charlie Lake Light Oil Resource Play		93.7	%	173,440	162,496
Duvernay Resource Play		100.0	%	132,160	132,160
Nordegg Resource Play		86.6	%	426,240	368,930
Banff/Exshaw Resource Play		99.3	%	364,160	361,744

2014 FOURTH QUARTER FINANCIAL AND OPERATIONAL RESULTS

Fourth quarter production averaged 37,704 boe per day, which is a 10% increase over production of 34,235 boe per day in the third quarter of 2014 and a 33% increase from 28,391 boe per day in the fourth quarter of 2013. Production per common share increased 25% from the fourth quarter of 2013 and 8% from the third quarter of 2014.

Production consisted of approximately 85% natural gas and 15% crude oil and natural gas liquids in the fourth quarter of 2014.

Funds flow was $61.7 million, which is an 18% decrease from $75.0 million in the third quarter of 2014 and a 23% increase from $50.1 million the fourth quarter of 2013. The decrease in funds flow from the third quarter of 2014 was largely a result of a 10% decrease in the average AECO natural gas spot price and a 24% decrease in the Edmonton Par oil spot price, offset by an 11% increase in natural gas production. The increase in funds flow from the fourth quarter of 2013 was largely a result of a 39% increase in natural gas production and a 2% increase in the average AECO natural gas spot price, offset by a 15% decrease in the Edmonton Par oil spot price.

Birchcliff had net income of $17.1 million in the fourth quarter of 2014, a 43% decrease from the third quarter of 2014 and a 54% decrease from the fourth quarter of 2013. Net income to common shareholders decreased to $16.1 million ($0.11 per basic common share) in the fourth quarter of 2014 as compared to $28.7 million in the third quarter of 2014 and $36.1 million in the fourth quarter of 2013.

Operating costs per boe were $5.33 per boe, up 5% from $5.06 per boe in the third quarter of 2014 and down 2% from $5.44 per boe in the fourth quarter of 2013.

Capital expenditures in the fourth quarter were $109.7 million.

Drilling activities during the fourth quarter of 2014 resulted in 15 (14.5 net) wells, comprised of 11 (11.0 net) natural gas wells and 4 (3.5 net) oil wells. The 11 (11.0 net) natural gas wells were all Montney/Doig horizontal natural gas wells. The oil wells included 2 (2.0 net) Montney/Doig horizontal light oil wells, 1 (1.0 net) Charlie Lake horizontal light oil well and 1 (0.5 net) Halfway horizontal light oil well. All the horizontal wells drilled in the fourth quarter of 2014 utilized multi-stage fracture stimulation technology.

2014 EXPLORATION SUCCESSES

Birchcliff was very successful with its exploration program in 2014 with four material discoveries. Three of the discoveries were on the Montney/Doig Natural Gas Resource Play which Birchcliff continues to delineate both geographically and stratigraphically. The fourth discovery was on the Charlie Lake Light Oil Resource Play in the Progress area immediately east of Pouce Coupe.

Exploration Success in the Pouce Coupe Area in the Montney D4 Interval on the Montney/Doig Natural Gas Resource Play - A New Birchcliff Montney Interval Has Been Proven Commercial

The first exploration success was in Birchcliff's development area of Pouce Coupe where Birchcliff drilled a successful horizontal well in a new interval of the Montney/Doig Natural Gas Resource Play in which Birchcliff had not previously drilled horizontal wells. This exploration success was drilled in the Montney D4 interval and the well was brought on production in the third quarter of 2014. This well and associated future drilling locations were attributed reserves at December 31, 2014 by Deloitte. The success of this new well in the Montney D4 interval has added significant potential future drilling locations and is expected to result in follow-up drilling by Birchcliff and significant future reserves additions. 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 develops this new Montney D4 interval.

Exploration Success in the Elmworth Area in the Montney D4 Interval on the Montney/Doig Natural Gas Resource Play - A New Birchcliff Montney Exploration Area Has Been Proven Commercial

The second exploration success on the Montney/Doig Natural Gas Resource Play was Birchcliff's first horizontal well drilled in Birchcliff's Elmworth area and it was also in the Montney D4 interval. This well was brought on production in the fourth quarter of 2014. This well and associated future drilling locations were attributed reserves at December 31, 2014 by Deloitte. The success of this new well in the Elmworth area has added significant potential future drilling locations and is expected to result in follow-up drilling by Birchcliff and significant future reserves additions.

In addition, Birchcliff had previously drilled three vertical stratigraphic tests in the Elmworth area that has helped delineate the potential of the Montney/Doig Natural Gas Resource Play in this area. As a result of this success in the Elmworth area, Birchcliff is now planning for significant operations and future growth in this area.

Exploration Success in the Pouce Coupe Area in the Montney C Interval on the Montney/Doig Natural Gas Resource Play - The Early Results From this First Well in a New Birchcliff Montney Interval are Encouraging

The third exploration success on the Montney/Doig Natural Gas Resource Play was also in Birchcliff's development area of Pouce Coupe, where Birchcliff drilled a successful horizontal well in a new interval for Birchcliff, the Montney C which is the lowermost interval of the play in this area. This well and associated future drilling locations were attributed reserves at December 31, 2014 by Deloitte based on completion test data from late December 2014. The results of this new well in the Montney C interval are encouraging and are expected to result in follow-up drilling by Birchcliff and the addition of significant potential future drilling locations and significant future reserves additions. This well was brought on production in the fourth quarter of 2014 and the production profile to date is very encouraging. Birchcliff holds 316.1 (306.2 net) sections of land that have potential for the Montney C interval.

Exploration Success in the Progress Area on the Charlie Lake Light Oil Resource Play - In Our Area Immediately East of Pouce Coupe, A New Birchcliff Charlie Lake Light Oil Exploration Area Has Been Proven Commercial

Birchcliff drilled its first Charlie Lake exploration horizontal well in the Progress area in the fourth quarter of 2014. The well was drilled, cased and completed utilizing recent advancements in multi-stage fracture stimulation technology. The well was brought on production in December of 2014 and produced at an average rate of 300 barrels of oil per day and 1.8 MMcf per day for a total of 600 boe per day with a 35% water cut for the first 30 days of production. Birchcliff has acquired a significant contiguous land block on this project totalling 26.5 (25.75 net) sections. With the success of the well, Birchcliff is currently planning a 3-D geophysical program to be acquired in the first quarter of 2015 to help delineate this exploration success.

Significant Future Drilling Opportunities on the Montney/Doig Natural Gas Resource Play

As at December 31, 2014, Birchcliff holds 288.6 (281.7 net) sections of land with potential for the new Montney D4 interval. With a development plan of 4 wells per section per interval, Birchcliff's two exploration successes in the Montney D4 have added 1,126.8 net potential future horizontal drilling locations. In addition, Birchcliff holds 305.1 (288.4 net) sections of land with potential for the Basal Doig/Upper Montney interval and 316.1 (306.2 net) sections which have potential for the Montney D1 interval. Birchcliff's total land holdings on these three intervals as at December 31, 2014 are 909.9 (876.3 net) sections.

On full development of four horizontal wells per section per interval, Birchcliff has 3,505.2 net existing horizontal wells and potential net future horizontal drilling locations in respect of these three commercial intervals. With 159 (158.9 net) horizontal locations drilled at the end of 2014, there remains 3,346.3 potential net future horizontal drilling locations as at December 31, 2014, up from 2,254.4 net at year-end 2013. This does not include any future horizontal drilling locations for the Montney C interval.

Substantial upside exists with respect to the 3,505.2 net existing horizontal wells and potential future horizontal drilling locations. The 2014 Reserves Evaluation has attributed proved plus probable reserves to 598.8 net existing wells and future horizontal drilling locations (of which 443.9 net wells are potential future locations). The remaining 2,906.4 net potential future horizontal drilling locations have not yet had any reserves attributed to them by Deloitte.

2014 INDEPENDENT RESERVES EVALUATION

Deloitte, independent qualified reserves evaluators of Calgary, Alberta, prepared a reserves estimation and economic evaluation effective December 31, 2014 in respect of Birchcliff's oil and natural gas properties, which is contained in a report dated January 30, 2015 (the "2014 Reserves Evaluation"). Deloitte also prepared reserves estimations and economic evaluations effective December 31, 2013 (the "2013 Reserves Evaluation") and December 31, 2012. Reserves estimates stated herein as at December 31, 2014, 2013 and 2012 are extracted from the relevant evaluation. The 2014 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").

At December 31, 2014, Deloitte estimated that Birchcliff had 465.0 MMboe of proved plus probable reserves and 282.3 MMboe of proved reserves. Birchcliff's proved plus probable reserves are comprised of 87.6% natural gas, 7.7% light oil and 4.7% natural gas liquids.

Reserves Summary

The following table summarizes Deloitte's estimates of Birchcliff's working interest (gross) oil and natural gas reserves at December 31, 2014 and December 31, 2013, using the Deloitte forecast price assumptions in effect at the applicable reserves evaluation date.

Summary of Oil and Natural Gas Reserves⁽¹⁾⁽²⁾

Reserves Category	Dec 31, 2014 (MMboe)	Dec 31, 2013 (MMboe)	Increase from Dec 31, 2013
Proved Developed Producing	84.7	62.0	36.8	%
Total Proved	282.3	220.0	28.3	%
Probable	182.7	150.0	21.8	%
Total Proved Plus Probable	465.0	370.1	25.7	%

⁽¹⁾	See "Disclosure of Oil and Gas Reserves and Resources" and "Advisories".
⁽²⁾	Numbers may not total due to rounding.

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, 2014 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 is based on Deloitte's December 31, 2014 forecast price assumptions of commodity prices, which can be found at http://www.ajmdeloitte.ca/price-forecasts.html.

Net Present Values of Future Net Revenue Before Income Taxes^(1)(2)(3)(4)

		Discounted Rate per Annum
Reserves Category		0%	5%	8%	10%	15%	20%
Proved		(MM$)	(MM$)	(MM$)	(MM$)	(MM$)	(MM$)
	Developed Producing	2,285.7	1,672.5	1,438.3	1,316.1	1,088.6	932.6
	Developed Non-Producing	276.3	191.1	157.7	140.1	107.2	84.8
	Undeveloped	3,867.9	2,097.4	1,479.6	1,174.4	645.9	321.2
Total Proved		6,429.9	3,961.0	3,075.6	2,630.5	1,841.7	1,338.6
Probable		5,525.7	2,386.4	1,534.7	1,163.6	604.7	320.0
Total Proved Plus Probable		11,955.6	6,347.4	4,610.4	3,794.1	2,446.4	1,658.6

⁽¹⁾	See "Disclosure of Oil and Gas Reserves and Resources".
⁽²⁾	Estimates of future net revenue, whether discounted or not, do not represent fair market value.
⁽³⁾	Future net revenue is after deduction of estimated costs of abandonment and reclamation of existing and future wells and does not include costs of abandonment and reclamation of facilities.
⁽⁴⁾	Numbers may not total due to rounding.

The net present value of the proved developed producing reserves (at a 10% discount rate) increased 35% to $1.3 billion as a result of increased reserves volumes recognized in the 2014 Reserves Evaluation, notwithstanding the oil price forecast for the years 2015 through 2019 decreased by 14% and the natural gas price forecast for these years increased by 3%.

Similarly, the net present value of the proved plus probable reserves (at a 10% discount rate) increased 19% to $3.8 billion.

The natural gas price forecast used by Deloitte in the 2014 Reserves Evaluation for the years 2015 through 2019 is approximately $0.11 per MMbtu higher on average than the forecast used by Deloitte for the same period in the 2013 Reserves Evaluation. The Edmonton Par price oil price forecast used by Deloitte in the 2014 Reserves Evaluation for the years 2015 through 2019 is approximately $12.87 per barrel lower than the forecast used by Deloitte for the same period in the 2013 Reserves Evaluation. The pentanes plus price forecast is down by $22.38 per barrel in this time period.
From the 2013 Reserves Evaluation to the 2014 Reserves Evaluation, Birchcliff had:

285% reserve replacement on a proved developed producing basis, including reserves added through acquisitions. Birchcliff added 2.85 boe of proved developed producing reserves for each boe that was produced during the year (calculated by dividing 2014 proved developed producing reserves additions before production by total production in 2014).
606% reserve replacement on a proved basis, including reserves added through acquisitions. Birchcliff added 6.06 boe of proved reserves for each boe that was produced during the year (calculated by dividing 2014 proved reserves additions before production by total production in 2014).
871% reserve replacement on a proved plus probable basis, including reserves added through acquisitions. Birchcliff added 8.71 boe of proved plus probable reserves for each boe that was produced during the year (calculated by dividing 2014 proved plus probable reserves additions before production by total production in 2014).

Reserve Life Index

Birchcliff's reserve life index is 6.0 years on a proved developed producing basis, 19.8 years on a proved basis and 32.7 years on a proved plus probable basis, in each case using reserves estimates by Deloitte at December 31, 2014 and assuming an average daily production rate of 39,000 boe per day.

Reserves on the Montney/Doig Natural Gas Resource Play

Deloitte estimated at December 31, 2014, Birchcliff had 412.3 MMboe of proved plus probable reserves attributed to horizontal wells on the Montney/Doig Natural Gas Resource Play. This is an increase of 29% from 319.2 MMboe proved plus probable reserves attributed to horizontal wells on the Montney/Doig Natural Gas Resource Play at December 31, 2013.

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⁾⁽²⁾
	Natural Gas (Bcf)		Light Oil and Natural Gas Liquids (Mbbl)		Total (Mboe)		Existing Horizontal Wells and Future Horizontal Well Locations				Net Future Capital (MM$)
	Natural Gas (Bcf)		Light Oil and Natural Gas Liquids (Mbbl)		Total (Mboe)		Gross		Net		Net Future Capital (MM$)
Reserves Category	2014	2013	2014	2013	2014	2013	2014	2013	2014	2013	2014⁽³⁾	2013⁽⁴⁾
Proved Developed Producing	413.9	291.6	4,110.0	1,940.6	73,094.8	50,538.1	155	117	154.9	105.2	0.0	1.25
Total Proved	1,453.6	1,113.0	12,933.9	8,202.1	255,208.2	193,704.5	443	384	432.2	330.9	1,712.1	1,306.1
Total Proved Plus Probable	2,343.2	1,828.0	21,798.2	14,550.3	412,336.2	319,214.6	622	549	598.8	470.8	2,769.4	2,146.2

⁽¹⁾	See "Disclosure of Oil and Gas Reserves and Resources" and "Advisories".
⁽²⁾	Estimates of reserves and future net revenue for reserves relating to 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.
⁽³⁾	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. These throughput volumes utilized by Deloitte are less than the design capacities of the proposed expansions of Phase V to 260 MMcf per day and Phase VI to 320 MMcf per day which incorporate recent design efficiencies.
⁽⁴⁾	Includes approximately $68.2 million of capital for the expansion of the PCS Gas Plant to 240 MMcf per day of total capacity, together with the related gathering pipelines, sales pipeline expansion and compression, plus $32.2 million of capital for the expansion of the PCS Gas Plant to 270 MMcf per day of total capacity.

Montney/Doig Land and Horizontal Natural Gas Well Data

	Dec 31, 2014		Dec 31, 2013		Dec 31, 2012
	Gross	Net	Gross	Net	Gross	Net
Number of sections to which Deloitte attributed proved plus probable reserves	139.6	133.7	129.6	114.9	114.3	98.3
For existing and future horizontal wells, number of well locations to which Deloitte attributed proved plus probable reserves	622	598.8	549	470.8	472	397.5
For existing and future horizontal wells, average number of net well locations per net section to which Deloitte attributed proved plus probable reserves	4.5⁽¹⁾		4.1⁽²⁾		4.1⁽³⁾
For existing horizontal wells, average remaining recoverable proved plus probable reserves attributed by Deloitte, plus cumulative production	4.9 Bcfe⁽⁴⁾		4.9 Bcfe		4.8 Bcfe
For future horizontal wells, average remaining recoverable proved plus probable reserves attributed by Deloitte	4.3 Bcfe		4.2 Bcfe		4.1 Bcfe
Average cost per well, forecast by Deloitte	$5.3 million		$5.2 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 2.9 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 3.2 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 139.6 (133.7 net) sections of land. Drilling success during 2014 and the acquisition of a partner's 30% working interest completed in January of 2014 added material reserve assignments. Deloitte has attributed reserves in the Montney D1 interval to 118.6 (115.2 net) sections of land, an increase of 22.7 net sections of land from 2013. Deloitte has attributed reserves in the Montney D4 interval to 7 (7.0 net) sections of land and in the Montney C interval to 2 (2.0 net) sections of land. Deloitte has attributed reserves in the Basal Doig/Upper Montney interval to 84.1 (80.0 net) sections of land. There are now 65.1 (63.5 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, 2014, Deloitte estimated that in the Worsley Charlie Lake light oil pool, Birchcliff had 40.2 MMboe proved plus probable reserves and 20.5 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. Both the original oil in place and the estimated reserves continue to grow 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 Lake Light Oil Pool (MMboe)⁽¹⁾⁽²⁾

Reserves Category	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	20.5	19.6	19.6	18.8	18.8	18.3	17.5	15.0	11.3
Proved Plus Probable	40.2	38.9	34.7	31.3	28.2	26.3	24.6	21.2	15.1

⁽¹⁾	See "Disclosure of Oil and Gas Reserves and Resources" and "Advisories".
⁽²⁾	Estimates of reserves relating to individual properties may not reflect the same confidence level as estimates of reserves for all properties due to the effects of aggregation.

2014 FINDING AND DEVELOPMENT COSTS

During 2014, Birchcliff's finding and development ("F&D") costs were $396.6 million and its FD&A costs were $449.4 million. The following table sets forth Birchcliff's estimates of its F&D costs per boe and FD&A costs per boe, excluding future development capital and including future development capital, on a proved developed producing, proved and proved plus probable basis.

Finding and Development Costs ($/boe)⁽¹⁾
Excluding Future Development Capital		2014		2013		2012		Three Year Average
	F&D - Proved Developed Producing	$	13.40	$	14.94	$	12.34	$	13.43
	F&D - Proved	$	8.29	$	5.85	$	7.77	$	7.29
	F&D - Proved Plus Probable	$	5.96	$	4.11	$	6.09	$	5.33
	Total FD&A - Proved Developed Producing⁽²⁾	$	12.81	$	12.71	$	12.33	$	12.64
	Total FD&A - Proved⁽²⁾	$	6.03	$	4.91	$	7.83	$	6.16
	Total FD&A - Proved Plus Probable⁽²⁾	$	4.19	$	3.46	$	5.89	$	4.38
Including Future Development Capital^(3)(4)(5)
	F&D - Proved	$	13.51	$	9.39	$	11.10	$	11.38
	F&D - Proved Plus Probable	$	12.57	$	9.03	$	11.99	$	11.14
	Total FD&A - Proved⁽²⁾	$	11.56	$	8.29	$	10.91	$	10.49
	Total FD&A - Proved Plus Probable⁽²⁾	$	10.45	$	8.60	$	11.56	$	10.19

⁽¹⁾	See "Advisories - Finding and Development Costs" for an explanation of the methodology used to calculate F&D costs.
⁽²⁾	Based upon FD&A costs, net of acquisition costs and disposition proceeds, and reserve additions, net of reserves disposed of.
⁽³⁾	Includes the increase in future development capital for 2014 over 2013 of $413.0 million on a proved basis and $671.9 million on a proved plus probable basis.
⁽⁴⁾	Includes the increase in future development capital for 2013 over 2012 of $147.1 million on a proved basis and $316.7 million on a proved plus probable basis.
⁽⁵⁾	Includes the increase in future development capital for 2012 over 2011 of $117.4 million on a proved basis and $287.5 million on a proved plus probable basis.

Deloitte's estimates of future development costs are $1.87 billion on a proved basis and $3.18 billion on a proved plus probable basis which are primarily the capital costs required to drill undeveloped locations. The estimates also include approximately $303 million for the expansion of the PCS Gas Plant to 360 MMcf per day of total throughput, together with the related gathering pipelines, sales pipeline expansion and compression and approximately $228 million on future drilling capital related to the acquisition of a partner's working interest in land and production in the Pouce Coupe area in 2014 on a proved plus probable basis.

For each future Montney/Doig horizontal natural gas well to which reserves were assigned in the 2014 Reserves Evaluation, an average of $5.3 million of drill, case, complete and tie-in costs were included as compared to an average of $5.2 million included in the 2013 Reserves Evaluation.

2014 RECYCLE RATIOS

The following table shows Birchcliff's recycle ratio for operating and funds flow netback, 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
Recycle Ratios⁽¹⁾		2014	2013	2014	2013
Excluding Future Development Capital
	F&D - Proved Developed Producing	2.1	1.5	1.8	1.2
	FD&A - Proved Developed Producing	2.2	1.8	1.9	1.5
	F&D - Proved	3.3	3.8	2.9	3.2
	FD&A - Proved	4.6	4.6	4.0	3.8
	F&D - Proved Plus Probable	4.7	5.5	4.1	4.5
	FD&A - Proved Plus Probable	6.6	6.5	5.8	5.3
Including Future Development Capital
	F&D - Proved	2.1	2.4	1.8	2.0
	FD&A - Proved	2.4	2.7	2.1	2.2
	F&D - Proved Plus Probable	2.2	2.5	1.9	2.0
	FD&A - Proved Plus Probable	2.7	2.6	2.3	2.2

⁽¹⁾	See "Advisories - Finding and Development Costs" for the methodology used in the calculation of F&D costs used in these recycle ratios.
⁽²⁾	See "Non-GAAP Measures".

During 2014, the average WTI price of crude oil was US$92.99 per barrel and the average price of natural gas at AECO was CDN$4.50 per Mcf. Operating netback per boe was $27.77 in 2014 and $22.53 in 2013. Funds flow netback per boe was $24.40 in 2014 and $18.50 in 2013.

2014 INDEPENDENT MONTNEY/DOIG NATURAL GAS RESOURCE ASSESSMENT

Deloitte conducted an independent review and audit of resources effective December 31, 2014, in respect of Birchcliff lands that have potential for the Montney/Doig Natural Gas Resource Play, which is contained in a report dated January 30, 2015 (the "2014 Resource Assessment"). Deloitte also prepared a resource assessment effective December 31, 2013 (the "2013 Resource Assessment"). The 2014 Resource Assessment and 2013 Resource Assessment were prepared in accordance with the standards contained in the COGE Handbook and NI 51-101.

Resource estimates stated herein as at December 31, 2014 and 2013 are extracted from the relevant assessment and reflect only Birchcliff's working interest share of resources for its lands in the area covered by the resource assessment (the "Study Area"). The resource assessments do not include Birchcliff's Charlie Lake Light Oil Resource Play or any of Birchcliff's other properties.

Montney/Doig Natural Gas Resource Assessment Summary

The following table summarizes Deloitte's estimates of Birchcliff's working interest share of gross volumes of its natural gas resources on the Montney/Doig Natural Gas Resource Play at December 31, 2014 and December 31, 2013, on a best estimate case.

Summary of Montney/Doig Natural Gas Resources⁽¹⁾

	Best Estimate Case
	Dec 31, 2014 (Bcfe)	Dec 31, 2013 (Bcfe)	Change from Dec 31, 2013
Total PIIP	50,132.6	52,036.4	(3.7	%)
Total Undiscovered PIIP	29,406.1	34,443.3	(14.6	%)
Prospective Resources	13,707.2	15,809.9	(13.3	%)
Total Discovered PIIP	20,726.4	17,593.2	17.8	%
Contingent Resources	7,851.7	6,547.8	20.0	%

⁽¹⁾	See "Disclosure of Oil and Gas Reserves and Resources", "Advisories - Discovered Resources" and "Advisories - Undiscovered Resources".

As a result of Birchcliff's 2014 exploration successes and the drilling by offsetting competitors, a significant amount of resources that were categorized as prospective resources at the end of 2013 have been categorized by Deloitte as contingent resources. Comparing the 2014 Resource Assessment to the 2013 Resource Assessment, contingent resources increased from 6.5 Tcfe to 7.9 Tcfe (a 20.0% increase), accompanied by a 13.3% decrease of prospective resources. Similarly, total discovered PIIP increased from 17.6 Tcfe to 20.7 Tcfe (a 17.8% increase), accompanied by a 14.6% decrease in total undiscovered PIIP.

Background to the Montney/Doig Natural Gas Resource Assessment

Birchcliff holds significant high working interest acreage in large contiguous blocks on the Montney/Doig Natural Gas Resource Play in the Peace River Arch area of Alberta. Birchcliff's lands are proximal to the PCS Gas Plant and to third-party gathering and processing infrastructure.

The Study Area assessed by Deloitte is comprised of the Doig Phosphate, Basal Doig, and Montney formations in the Montney/Doig Deep Basin Area of Northwest Alberta ranging from Townships 69 to 81, Ranges 2 to 13W6. The Study Area is further bounded in a northwest - southeast direction by the Montney/Doig deep basin edges and covered a total of 332.6 gross sections of land held by Birchcliff at December 31, 2014, which includes:

305.1 (288.4 net) sections, with a 94.5% working interest, which have potential for the Basal Doig/Upper Montney interval;
316.1 (306.2 net) sections, with a 96.9% working interest, which have potential for the Montney D1 interval; and
288.6 (281.7 net) sections, with a 97.6% working interest, which have potential for the Montney D4 interval.

As at December 31, 2014, Birchcliff's total land holdings on the three intervals described above are 909.9 (876.3 net) sections. On full development of four horizontal wells per section per interval, Birchcliff has 3,505.2 net existing horizontal wells and potential future drilling locations. With 159 (158.9 net) horizontal locations drilled at the end of 2014, there remains 3,346.3 potential net future horizontal drilling locations. See "2014 Exploration Successes - Significant Future Drilling Opportunities on the Montney/Doig Natural Gas Resource Play".

Deloitte utilized probabilistic methods to generate high, best, and low estimates of reserves and resources volumes. Results from the 2014 Resource Assessment are presented in the following table for Birchcliff's working interest share of gross volumes. Proved, proved plus probable and proved plus probable plus possible reserves determined by the 2014 Reserves Evaluation are included in this table for completeness; however, reserves were not the focus of the 2014 Resource Assessment.

Summary of Birchcliff Reserves and Resources^(1)(2)(3)


Resource Class				Reserves and Resource Volumes(Bcfe)
Resource Class				Low Estimate Case	Best Estimate Case	High Estimate Case
Discovered			Cumulative Production⁽⁴⁾	216.3	216.3	216.3
			Remaining Reserves⁽⁴⁾⁽⁵⁾	1,535.7	2,481.1	3,573.0
			Surface Loss/Shrinkage	52.8	82.3	117.8
		Total Commercial		1,804.9	2,779.8	3,907.1
			Contingent Resources⁽⁴⁾	5,080.2	7,851.7	12,790.2
			Unrecoverable⁽⁶⁾	8,453.4	10,095.0	10,811.0
		Total Sub-commercial		13,533.6	17,946.7	23,601.2
	Total Discovered PIIP			15,338.4	20,726.4	27,508.2
Undiscovered			Prospective Resources⁽⁴⁾	8,645.5	13,707.2	21,665.9
			Unrecoverable⁽⁶⁾	12,348.3	15,698.9	18,798.5
	Total Undiscovered PIIP			20,993.8	29,406.1	40,464.4
Total PIIP				36,332.2	50,132.6	67,972.7

⁽¹⁾	See "Disclosure of Oil and Gas Reserves and Resources" and "Advisories".
⁽²⁾	All reserves and resources are gross volumes at December 31, 2014, which are equal to Birchcliff's working interest share before deduction of royalties and without including any royalties held by Birchcliff.
⁽³⁾	Numbers may not total due to rounding.
⁽⁴⁾	Natural gas liquids and sales gas volumes combined at a ratio of 1 barrel equals 6 Mcfe.
⁽⁵⁾	Includes reserves assigned to both vertical and horizontal Montney/Doig wells. The low estimate reflects the estimate of proved reserves contained in the 2014 Reserves Evaluation. The best estimate reflects the estimate of proved plus probable reserves contained in the 2014 Reserves Evaluation. The high estimate reflects the estimate of proved plus probable plus possible reserves contained in the 2014 Reserves Evaluation.
⁽⁶⁾	Unrecoverable includes surface loss/shrinkage on volumes of contingent resources and prospective resources.

For a description of the specific contingencies which prevent the contingent resources from being classified as reserves and the significant positive and negative factors relevant to the estimates of Birchcliff's resources, please see "Disclosure of Oil and Gas Reserves and Resources - Contingencies and Positive and Negative Factors".

2015 CAPITAL BUDGET AND UPDATED GUIDANCE FOR 2015

Birchcliff is very pleased to announce its 2015 capital budget of $266.7 million (including $59.0 million for infrastructure). Birchcliff expects to drill 25 (24.5 net) wells in 2015. Details of the budget are as follows:

2015 Capital Budget

		Gross Wells	Net Wells	Net Capital (MM$)
Drilling & Development
	Montney D1 Horizontal Gas Wells	14.0	14.0	90.8
	Montney D4 Horizontal Gas Wells	4.0	4.0	25.4
	Basal Doig/Upper Montney Horizontal Gas Wells	3.0	3.0	19.2
	Montney C Horizontal Gas Wells	1.0	1.0	5.8
	Charlie Lake Horizontal Light Oil Wells	1.0	1.0	5.1
	Halfway Horizontal Light Oil Wells	1.0	0.5	2.2
	Other Wells	1.0	1.0	3.2
	2014 Carry Forward Capital⁽¹⁾	-	-	13.0
Total Drilling & Development⁽²⁾		25.0	24.5	164.7
Infrastructure⁽³⁾				59.0
Production Optimization				18.1
Land & Seismic				11.0
Acquisition & Dispositions				(0.7	)
Other				14.6
Total Net Capital				266.7

⁽¹⁾	Primarily, completion, equipping and tie-in costs associated with 4 (3.5 net) wells rig released at the end of 2014.
⁽²⁾	On a drill, case, complete, equip and tie-in basis.
⁽³⁾	Includes approximately $50 million of capital in 2015 for the PCS Gas Plant Phase V expansion.

Birchcliff expects 2015 annual production to average between 38,000 and 40,000 boe per day.
Birchcliff's 2015 capital budget accomplishes the following:

Achieves approximately 16% year-over-year average production growth.
Forecasts year-end reserves growth in all categories.
Maintains Birchcliff's financial flexibility.
Supports and progresses our strategic exploration projects.
Funds key infrastructure required for future growth.

In 2014, Birchcliff had the benefit of a recycle ratio of 2 times on the basis of proved developed producing reserve additions. Accordingly, capital spent in the 2015 budget is anticipated to result in reserve additions and positive returns for Birchcliff's shareholders based on Birchcliff's commodity price assumptions.

Birchcliff's mature base production has low declines which translates into less capital required to maintain production, thereby allowing Birchcliff to grow even though commodity prices have severely weakened.

Birchcliff expects to fund its 2015 capital program primarily using internally generated funds flow and available credit facilities. The capital expenditures program maintains a strong balance sheet and significant financial flexibility. These expectations are based on a forecast average WTI price of US$60.00 per barrel of oil and AECO price of CDN$3.00 per GJ of natural gas during 2015. Birchcliff will adjust its 2015 capital budget to respond to changes in commodity prices and other material changes in the assumptions underlying its 2015 budget.

Birchcliff's preliminary guidance for 2015 which was announced in November of 2014 indicated that Birchcliff would be targeting exit production for 2015 of approximately 48,000 to 50,000 boe per day with capital expenditures required to achieve such a production target expected to be approximately $450 million to $500 million (which included approximately $110 million of infrastructure investment). This preliminary guidance was based on a forecast WTI price of US$90.00 per barrel of oil and AECO price of CDN$4.00 per GJ of natural gas during 2015. In view of current commodity prices, Birchcliff has established a more conservative capital budget for 2015.

2019 FIVE YEAR PLAN

Birchcliff updates its five year plan in the fall of each year. Birchcliff's 2019 Five Year Plan announced in November of 2014 targeted a 2019 exit production rate of approximately 100,000 boe per day, comprised of approximately 522 MMcf per day of natural gas and 13,000 barrels per day of oil and natural gas liquids (which are comprised substantially of condensate). Birchcliff currently owns and controls the land base necessary to achieve the production targets contemplated by the 2019 Five Year Plan, allowing it to execute the program without relying on land, asset or corporate acquisitions.

In view of current commodity prices, Birchcliff now expects that some of the capital expenditures and growth contemplated in its 2019 Five Year Plan will be delayed unless commodity prices significantly improve. Birchcliff will continue to adjust its capital expenditure program to respond to changes in commodity prices and other material changes in the assumptions underlying its 2019 Five Year Plan. When its 2019 Five Year Plan was announced, Birchcliff indicated that the ratio of year end debt to one year's forward funds flow was expected to remain fairly consistent based on the production rates and commodity price assumptions contained in the 2019 Five Year Plan. Birchcliff now expects that the ratio of year end debt to one year's forward funds flow will change as a result of changes in commodity prices.

See "Advisories - Forward-Looking Information" for the production rates and commodity price assumptions contained in the 2019 Five Year Plan.

UPDATE ON THE PCS GAS PLANT

The PCS Gas Plant is currently processing approximately 155 MMcf per day of sales gas. The Phase IV expansion of the PCS Gas Plant, which expanded processing capacity to 180 MMcf per day from 150 MMcf per day, was completed in September of 2014 on budget and on time.

Phase V Expansion Delayed

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. Birchcliff had previously announced that start-up of Phase V would occur late in the fourth quarter of 2015. As a result of weak commodity prices and a reduced capital budget, management of Birchcliff has determined to delay the field assembly and construction work of the Phase V expansion of the PCS Gas Plant. Birchcliff currently expects to rebid the field assembly and construction work of the Phase V expansion after Q1 2015 which is anticipated to result in cost savings due to the continued reduction in demand for labour, services and materials. As a result, the timing of the field assembly and construction and start-up for Phase V is currently uncertain and is expected to be determined later in 2015.

Phase VI Expansion Delayed

Preliminary planning and permitting work has been initiated for the Phase VI expansion of the PCS Gas Plant which is designed to increase processing capacity to 320 MMcf per day from 260 MMcf per day. Birchcliff had previously announced that start-up of Phase VI would occur in late 2016. As a result of the delay of the Phase V expansion due to weak commodity prices and a reduced capital budget as discussed above, the timing of the construction and start-up of Phase VI is currently uncertain and will be determined at a later date.

IN MEMORIAM - WERNER (VERN) A. SIEMENS

On March 2, 2015, Werner (Vern) A. Siemens, a founding shareholder and Director of Birchcliff, passed away at the age of 78.

"Vern was an important member of the Birchcliff family and he will be sadly missed" said Jeff Tonken, President and CEO of Birchcliff. "Vern was an experienced oilman, a dedicated and diligent director whose strong leadership has been invaluable to Birchcliff. Prior to his involvement with Birchcliff, Vern was a founding shareholder and Director of each of Stampeder Exploration Ltd., Big Bear Exploration Ltd. and Case Resources Ltd. Vern was a team player and extremely knowledgeable about matters surrounding a well-run business. Vern's insight, character and warmth, will be dearly missed by his many friends at Birchcliff, as well as his friends and colleagues throughout the industry and our community. On behalf of the entire Birchcliff organization, I would like to extend our heartfelt condolences to Vern's wife Denise, his daughter Elaine and her husband Duncan, his son Craig and his wife Suzanne, his grandchildren and his extended family and friends around the globe."

Vern's long and varied business career included many Executive roles over three decades with Agra Industries Ltd., where he established himself as a very successful businessman. Vern also served as a volunteer, Director, President and General Manager of the Calgary Stampeder Football Club during its rebuilding years from 1985 to 1990.

We grieve the loss of a valued business associate and a wonderful friend, who through his life's work, left this world a better place.

PRESIDENT'S REMARKS

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

"I am pleased to report that our first quarter average production has been strong and should be near the high end of our guidance of 37,000 to 38,000 announced on February 11, 2015. Our low-cost operated production should buffer the effect of the weakness in commodity prices at a time when the industry is in crisis.

Our capital and cash costs continue to decrease. Our drilling results to date in 2015 are very positive.

We continue to have material exploration success on the Montney/Doig Natural Gas Resource Play in 2015. We recently drilled our second successful Montney D4 horizontal well in the Elmworth area and the well is planned to be on production by the end of March 2015.

Birchcliff is positioned to withstand the recent collapse in commodity prices. Our mature base production decline rate is low. This means that we do not require significant capital to keep our production flat. Further, as a result of low finding and developments costs coupled with low operating costs, we can still make a profit at low commodity prices while replacing production. In short, our profit margins have been reduced but we expect to continue to make money.

Accordingly, we have approved a budget which results in 16% year-over-year average production growth, which we anticipate will result in profitable additions to our reserves in all categories and maintain financial flexibility.

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 and as result, we can continue to maintain financial flexibility at all times.

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 will continue to execute on our long-term business plan notwithstanding the difficult commodity price environment and we look forward to a good year in 2015.

After reviewing industry results to date, I believe Birchcliff's results are in the top decile of the industry.

We thank Mr. Seymour Schulich, our largest shareholder, for his advice, unwavering commitment and his ongoing financial support. Mr. Schulich holds 40 million common shares representing 26.3% of the current issued and outstanding common shares.

On behalf of our Management Team and Directors, I again thank all of our staff for their hard work and dedication to the achievement of our corporate goals and all of our shareholders for their continued support and trust in all of us at Birchcliff.

We look forward to another excellent year."

NON-GAAP MEASURES

This press release uses "funds flow", "funds flow from operations", "funds flow per common share", "netback", "operating netback", "estimated operating netback", "funds flow netback", "operating margin", "cash costs", "adjusted working capital deficit" and "total debt" which do not have standardized meanings prescribed by generally accepted accounting principles ("GAAP") and therefore may not be comparable to similar measures presented by other companies where similar terminology is used. Management utilizes funds flow, funds flow from operations, funds flow per common share, netback, operating netback, estimated operating netback, funds flow netback, operating margin and cash costs as key measures to assess the Corporation's efficiency and its ability to generate the cash necessary to fund future growth through capital investments, pay dividends on preferred shares and repay debt. Management uses adjusted working capital deficit and total debt as key measures to assess the liquidity of the Corporation.

"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. The following table sets out the reconciliation of cash flow from operating activities, as determined in accordance with IFRS, to funds flow from operations.

		Three months ended				Twelve months ended
		December 31				December 31
($000s)		2014		2013		2014		2013
Cash flow from operating activities		77,513		52,209		309,901		170,356
Adjustments:
	Decommissioning expenditures	263		72		1,663		557
	Changes in non-cash working capital	(16,059	)	(2,221	)	(11,066	)	3,448
Funds flow from operations		61,717		50,060		300,498		174,361

"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 related 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 other cash income sources.

"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.

"Cash costs" are comprised of operating, transportation and marketing, general and administrative and interest costs.

"Adjusted working capital deficit" is calculated as current assets minus current liabilities excluding the effects of financial instruments. The following table reconciles current assets minus current liabilities to adjusted working capital deficit.

As at, ($000s)		December 31, 2014	December 31, 2013
	Working capital deficit	76,712	60,450
	Fair value of financial instruments	-	826
	Deferred premium on financial instruments	-	(1,205	)
Adjusted working capital deficit		76,712	60,071

"Total debt" is calculated as the revolving term credit facilities plus non-revolving term credit facilities as they appear on the Corporation's statements of financial position plus adjusted working capital deficit. The following table reconciles the non-revolving term credit facilities plus the revolving credit facilities to total debt.

As at, ($000s)		December 31, 2014	December 31, 2013
	Non-revolving term credit facilities	129,476	127,144
	Revolving term credit facilities	339,557	266,823
	Long-term bank debt	469,033	393,967
	Adjusted working capital deficit	76,712	60,071
Total debt		545,745	454,038

DISCLOSURE OF OIL AND GAS RESERVES AND RESOURCES

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.

Resources and Production

Resources encompasses all petroleum quantities that originally existed on or within the earth's crust in naturally occurring accumulations, including discovered and undiscovered (recoverable and unrecoverable) plus quantities already produced. "Total resources" is equivalent to "total PIIP". Resources are classified in the following categories:

Total PIIP is that quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered.
Discovered PIIP is that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production. The recoverable portion of discovered PIIP includes production, reserves and contingent resources; the remainder is unrecoverable.
Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies.
Undiscovered PIIP is that quantity of petroleum that is estimated, on a given date, to be contained in accumulations yet to be discovered. The recoverable portion of undiscovered PIIP is referred to as prospective resources; the remainder is unrecoverable.
Undiscovered unrecoverable PIIP is that portion of undiscovered PIIP which is estimated, as of a given date, not to be recoverable by future development projects. A portion of these quantities may become recoverable in the future as commercial circumstances change or technological developments occur; the remaining portion may never be recovered due to the physical/chemical constraints represented by subsurface interaction of fluids and reservoir rock.
Prospective resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects.
Unrecoverable is that portion of discovered and undiscovered PIIP quantities which is estimated, as of a given date, not to be recoverable by future development projects. A portion of these quantities may become recoverable in the future as commercial circumstances change or technological developments occur; the remaining portion may never be recovered due to the physical/chemical constraints represented by subsurface interaction of fluids and reservoir rocks.
Production is the cumulative quantity of petroleum that has been recovered at a given date.

Uncertainty Ranges

Uncertainty Ranges are described by the COGE Handbook as low, best, and high estimates for reserves and resources as follows:

Low Estimate: This is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. If probabilistic methods are used, there should be at least a 90% probability (P90) that the quantities actually recovered will equal or exceed the low estimate.
Best Estimate: This is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50% probability (P50) that the quantities actually recovered will equal or exceed the best estimate.
High Estimate: This is considered to be an optimistic estimate of the quantity that will actually be recovered. It is unlikely that the actual remaining quantities recovered will exceed the high estimate. If probabilistic methods are used, there should be at least a 10% probability (P10) that the quantities actually recovered will equal or exceed the high estimate.

Contingencies and Positive and Negative Factors

The specific contingencies which prevent the classification of the Corporation's contingent resources as reserves are as follows:

While there is substantial development in certain stratigraphic units in certain geographic regions within the Study Area, this is not the case for all stratigraphic units or all geographic regions over the entire Study Area and, as a result, most stratigraphic units in some geographic regions of the Study Area are considered to be in the early stages of development.
Deloitte has utilized a four mile radius from existing production or a confirmed test as well as interpreted geological continuity to assign discovered PIIP and contingent resources for each stratigraphic unit, while reserves (up to and including proved plus probable plus possible) are generally assigned to lands that are no more than one mile from the confirmed production or test. In these cases, the contingency is described as the self-imposed limitations of Birchcliff, its partners, and other operators to develop the resources in a timely manner as a result of other priorities and strategic opportunities that may limit capital deployment.
The lack of access to markets resulting from a general lack of infrastructure capacity in certain geographic areas within the Study Area.
Manpower, both internal and third party, required to develop and produce a resource of this size is limited and there is a finite amount of exploitation and/or development that can take place each year.
Regulatory approvals, particularly related to downspacing in the Montney, will be required prior to development proceeding beyond 4 wells per section. It is not expected that the Alberta Energy Regulator will withhold this approval.

Significant positive factors relevant to the estimate of the Corporation's resources include: (i) the relatively dense well control on and around Birchcliff's lands, the associated evaluation data, and Birchcliff's well calibrated and evidenced models of stratigraphy, petrophysics and hydrodynamics used in the resource assessment model; and (ii) Birchcliff's six year history of generating technical resource assessment models annually, with reasonably consistent best estimates of resources and petroleum in place over respective lands. These models are directly used internally by Birchcliff in support of exploration, land evaluation and well approval processes.

Significant possible positive and negative variations in all relevant reservoir properties and parameters considered, between and away from well control, are directly incorporated in the probabilistic assessment methods used, and reflected in the high (p10) and low (p90) estimates.

A potentially significant negative factor relevant to the estimate is the uncertainty associated with Birchcliff's assumptions about the geometry (i.e. height and width) of hydraulic fracture stimulations and the associated recovery factors. While these assumptions are consistent with Birchcliff's investigations to date and with the production profiles of producing wells with significant production histories, these geometries and associated recovery factors are not necessarily known with certainty.

ADVISORIES

Boe Conversions: Barrel of oil equivalent ("boe") amounts have been calculated by using the conversion ratio of six thousand cubic feet (6 Mcf) of natural gas to one barrel of oil (1 bbl). 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.

Mcfe, Bcfe and Tcfe Conversions: Thousands of cubic feet of gas equivalent ("Mcfe"), billions of cubic feet of gas equivalent ("Bcfe") and trillions of cubic feet of gas equivalent ("Tcfe") amounts have been calculated by using the conversion ratio of one barrel of oil (1 bbl) to six thousand cubic feet (6 Mcf) of natural gas. Mcfe, Bcfe and Tcfe 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.

MMbtu Pricing Conversion: $1.00 per MMbtu equals $1.00 per Mcf based on a standard heat value Mcf.

Gross Company Reserves: In this press release, all references to "reserves" are to the Corporation's gross company reserves, meaning Birchcliff's working interest (operating or non-operating) share before deduction of royalties and without including any royalty interests of Birchcliff.

Possible Reserves: Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable reserves.

Reserves for Portion of Properties: With respect to the disclosure of reserves contained herein relating to portions of the Corporation'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.

Finding and Development Costs: With respect to disclosure of finding and development costs disclosed in this press release:

The amounts of finding and development and/or acquisition costs contained in the table and the disclosure set forth above for each of the years 2014, 2013 and 2012 are calculated by dividing the total of the net amount of the particular costs noted in each line incurred during such year by the amounts of additions to proved developed producing reserves, total proved reserves and total proved plus probable reserves during such year that resulted from the expenditure of such costs.
In calculating the amounts of finding and development and/or acquisition costs for a year, the changes during the year in estimated future development costs and in estimated reserves are based upon the evaluations of Birchcliff's reserves prepared by Deloitte 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 future development costs generally will not reflect total finding and development costs related to reserves additions for that year.
Finding and development costs both including and excluding acquisitions and dispositions have been presented in this press release. While NI 51-101 requires that the effects of acquisitions and dispositions be excluded, FD&A costs have been presented because acquisitions and dispositions can have a significant impact on the Corporation's ongoing reserve replacement costs and excluding these amounts could result in an inaccurate portrayal of the Corporation's cost structure.

Reserve Life Index, Recycle Ratios and Reserve Replacement: Reserve life index is calculated by dividing reserves estimated by Deloitte at December 31, 2014 by the average production in the applicable period. 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. 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.

Discovered Resources: With respect to the discovered resources (including contingent resources) described in this press release, there is no certainty that it will be commercially viable to produce any portion of the resources.

Undiscovered Resources: With respect to the undiscovered resources (including prospective resources) described in this press release, there is no certainty that any portion of the resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources.

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

Initial Production Rates: Any disclosure in this press release of an initial production rate for any well is not indicative of the long-term performance of such well or the rate at which such well will continue production thereafter.

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 the Corporation's current internal expectations, estimates, projections, assumptions and beliefs. All information other than historical fact is forward-looking information. Information relating to reserves and resources is forward-looking as it involves the implied assessment, based on certain estimates and assumptions, that the reserves and resources exist in the quantities estimated and that they will be commercially viable to produce 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: the Corporation's plans and other aspects of its anticipated future operations, management focus, strategies and priorities; expected results from the Corporation's portfolio of oil and gas assets and results of operations; estimates of reserves and resource volumes; the net present values of future net revenue associated with the Corporation's reserves; production rates and recovery factors; decline rates; estimates of future drilling locations and opportunities; exploration and development activities including wells to be drilled, completed, equipped and tied-in; the Corporation's forecast average production for the first quarter of 2015, including expected commodity mix, and the Corporation's forecast average annual production for 2015; the Corporation's expectation of its average annual production growth; the Corporation's 2015 capital budget including planned 2015 capital spending, the Corporation's plans to drill 25 (24.5 net) wells, the anticipated sources of funding for the Corporation's 2015 capital budget and the production growth, year-end reserves growth and positive returns for shareholders anticipated to result from the Corporation's capital program; the Corporation's expectation that it will see cost reductions to its 2015 capital budget; the Corporation's 2019 Five Year Plan including estimated production targets and the expected commodity mix with respect to the Corporation's 2019 exit production; the financial and operational flexibility of the Corporation; the Corporation's expectation that it will adjust its capital expenditure program to respond to changes in commodity prices and other material changes in the assumptions underlying its 2015 budget or 2019 Five Year Plan; the Corporation's expectation that some of the capital expenditures and growth contemplated in the 2019 Five Year Plan will be delayed unless commodity prices significantly improve;
the Corporation's expectation with respect to future ratios of year end debt to forward funds flow; proposed expansions of the PCS Gas Plant including the anticipated processing capacities of the PCS Gas Plant after such expansions, the anticipated costs and timing of such expansions, the anticipated timing of the field construction and start-up of such expansions and the Corporation's plan to rebid the field assembly and construction work of the Phase V expansion after Q1 2015, which is anticipated to result in cost savings due to the continued reduction in demand for labour, services and material; the success of new wells in the Montney D4 and C intervals are expected to result in follow-up drilling by the Corporation and significant future reserves additions and, with respect to the Montney C interval, the addition of potential future drilling locations; the 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 Corporation's plans for significant operations and growth in the Elmworth area; the Corporation's expectation that general and administrative costs per boe will continue to decrease; and the Corporation's expectation that the Corporation's bank credit facilities will be increased during its normal credit review in May of 2015.

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 and applicable royalty rates and tax laws; the state of the economy and the exploration and production business; reserve and resource volumes; anticipated timing and results of capital expenditures; the sufficiency of budgeted capital expenditures to carry out planned expenditures; results of operations; operating and general and administrative costs; the performance of existing and future wells and well production rates; well drainage areas; success rates for future drilling; the impact of competition; the availability and demand for labour, services and materials; the Corporation's ability to access capital; and the Corporation's ability to market oil and gas. In addition, the Corporation has made the following key assumptions with respect to certain forward-looking information contained in this press release:

With respect to estimates of reserves and resource volumes and the net present values of future net revenue associated with the Corporation's reserves, the key assumption is the validity of the data used by Deloitte in their independent reserves evaluations and resource assessments.
With respect to statements of future wells to be drilled, completed, equipped and tied-in, estimates of future drilling locations and opportunities, statements as to decline rates of the Corporation's wells and statements as to future growth in the Elmworth area, the key assumption is the validity of the geological and other technical interpretations performed by the Corporation's technical staff, which indicate that commercially economic volumes can be recovered from the Corporation's lands as a result of drilling future wells.
With respect to estimates as to average production for the first quarter of 2015, the average annual production in 2015 and the estimated production targets in the 2019 Five Year Plan, the key assumptions are that: no unexpected outages occur in the infrastructure that the Corporation relies on to produce its wells; 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 and production expectations.
With respect to estimates as to future capital spending and sources of funding for the 2015 capital budget, the key assumption is that the Corporation realizes the average annual production target and the commodity prices as set forth in the disclosures relating to the Corporation's 2015 capital budget. With respect to the Corporation's expectation that it will see cost reductions to its 2015 capital budget, the key assumption is that service providers will reduce the cost of their services to the Corporation and other industry participants which will result in savings to the Corporation.
With respect to statements regarding proposed expansions of the PCS Gas Plant, the anticipated processing capacities of the PCS Gas Plant after such expansions, the anticipated costs and timing of such expansions and the anticipated timing of the field construction and start-up of such expansions, the key assumptions are that: future drilling is successful; there is an availability of sufficient labour, services and equipment; the Corporation will have access to sufficient capital to fund those projects; and commodity prices warrant proceeding with the construction of such facilities and the drilling of associated wells.
With respect to the Corporation's expectation that the rebidding of the field assembly and construction work of the Phase V expansion after Q1 2015 is anticipated to result in cost savings due to the continued reduction in demand for labour, services and material, the key assumption is that service providers will reduce the costs of their services to the Corporation and other industry participants which will result in savings to the Corporation.
With respect to statements that the success of new wells in the Montney D4 and C intervals are expected to result in follow-up drilling by the Corporation and significant future reserves and, with respect to the Montney C interval, the addition of potential future drilling locations, the key assumptions are that: there is an availability of sufficient labour, services and equipment; the Corporation will have access to sufficient capital to fund such future drilling; commodity prices warrant proceeding with such future drilling; and future drilling is successful. In addition, statements regarding future reserve additions assume that in conducting its reserves evaluation, the Corporation's independent reserves evaluator will concur with the Corporation's internal technical interpretations.
With respect to the Corporation'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 the Corporation's expectation that its bank credit facilities will be increased during its normal credit review in May of 2015, the key assumption is that the criteria applied by the Corporation'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 2014 Reserves Evaluation.
The key assumptions utilized in the 2019 Five Year Plan are set out in the following table:

	2015	2016	2017	2018	2019
Annual exit production (boe per day)	49,000	64,000	72,000	82,000	100,000
Light oil - WTI Cushing (US$/bbl)	90.00	90.00	90.00	90.00	90.00
Light oil - Edmonton Par (CDN/$bbl)	91.00	91.00	91.00	91.00	91.00
Natural gas - AECO - C daily (CDN$/GJ)	4.00	4.00	4.00	4.00	4.00

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 the Corporation 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 risks associated with oil and gas exploration, production, transportation and marketing such as uncertainty of geological and technical data, imprecision of reserves and resource estimates, operational risks, environmental risks, loss of market demand, general economic conditions affecting ability to access sufficient capital, commodity price fluctuations, changes in governmental regulation of the oil and gas industry and competition from others for scarce resources.

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.

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 the Corporation'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. The Corporation 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 the Corporation's plans or expectations, except as otherwise required by applicable securities laws.

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.

Contact Information:

Birchcliff Energy Ltd.
Jeff Tonken
President and Chief Executive Officer
(403) 261-6401
(403) 261-6424 (FAX)

Birchcliff Energy Ltd.
Bruno Geremia
Vice-President and Chief Financial Officer
(403) 261-6401
(403) 261-6424 (FAX)

Birchcliff Energy Ltd.
Jim Surbey
Vice-President, Corporate Development
(403) 261-6401
(403) 261-6424 (FAX)

Birchcliff Energy Ltd.
Suite 500, 630 - 4th Avenue S.W.
Calgary, AB T2P 0J9

Birchcliff Energy Ltd. Provides Operational Update and Announces Audited 2014 Financial Statements