Pinecrest Energy Inc. Announces its 2011 Year End and Fourth Quarter Results, December 31, 2011 Year End Reserves, a Greater Red Earth Oil Resource Assessment and Filing of its Annual Information Form

TSX Venture Exchange:  PRY

CALGARY, March 22, 2012 /CNW/ - Pinecrest Energy Inc. ("Pinecrest" or the "Company") is pleased to announce that it has filed on SEDAR its audited financial statements and related Management's Discussion and Analysis ("MD&A") for the three and twelve month periods ending December 31, 2011.  The statements will be available for review at www.sedar.com or www.pinecrestenergy.com.

ACCOMPLISHMENTS

The following are the highlights of Pinecrest's operations for the quarter ended December 31, 2011:

• Achieved record exit production rate of 3,500 boe/day;
  
  
• Increased Q4 2011 average daily production (99% light oil) to 2,225 boe/d from 1,563 boe/d in Q3 2011, representing a 42% increase;
  
  
• Generated a top decile operating netback of $76.39/boe;
  
  
• Increased Q4 2011 funds from operations by 74% to $14.6 million from $8.4 million in Q3 2011;
  
  
• Increased the Company's net acreage by 14% to approximately 117,000 net acres with an average working interest of 92%;
  
  
• Reduced Q4 2011 operating and transportation costs per boe by approximately 14% to $14.79 from $17.13 in Q3 2011; and
  
  
• Achieved a 100% drilling success rate during Q4 2011 with 14 (13.3 net) wells.
  
  

Highlights for the year ended December 31, 2011 include:

• Achieved a 100% drilling success rate with 29 (24.7 net) wells all in the Red Earth area of Alberta;
  
  
• Increased proved plus probable ("2P") reserves by approximately 364% to 8.4 million barrels of oil equivalent ("mmboe") (98% light oil) at December 31, 2011;
  
  
• Increased the Company's low risk development drilling inventory by approximately 30% to 235 (4 wells/section) or 470 (8 wells/section) in the Slave Point formation;
  
  
• Increased the Company's net acreage to approximately 117,000 net acres (92% working interest), a 154% increase over the five months ended December 31, 2010;
  
  
• Increased funds from operations to $31.2 million, a 14,651% increase over the five months ended December 31, 2010;
  
  
• Reduced per barrel operating and transportation expenses by approximately 7% compared to the five months ended December 31, 2010;
  
  
• Increased operating netback to $69.46/boe compared to $46.89/boe for the five months ended December 31, 2010;
  
  
• Completed construction of a major pipeline and regional gathering system;
  
  
• Assumed operatorship and expanded the Evi central oil battery;
  
  
• Closed a $60 million bought-deal financing in March 2012;
  
  
• Amended the $30 million credit facility with a Canadian chartered bank to provide supplemental funding for the Company's general operations and capital program during 2011, and increased the credit facility in early 2012 to $75 million; and
  
  
• Current production is approximately 3,450 boe/day (based on field estimates) with approximately 5% currently shut in for operational purposes.  The Company currently has 6 gross (5.75 net) additional wells to be brought on production prior to the end of April.

FINANCIAL AND OPERATIONAL HIGHLIGHTS

The following is a review of Pinecrest's financial and operating performance for the three months ended and year ended December 31, 2011:

		Three months ended					Year ended		Five months ended
		Dec 31	Dec 31				Dec 31		Dec 31
		2011	2010		% Change		2011		2010		% Change
FINANCIAL ($ except per share amounts)
Petroleum and natural gas sales		19,897,663	1,386,045		1,336		46,846,135		1,906,353		2,357
Funds flow from (used in) operations^(1)		14,616,142	(237,130)		6,264		31,166,499		(214,187)		14,651
	Per share - basic	$0.07	($0.00)		100		$0.17		($0.00)		100
	Per share - diluted	$0.07	($0.00)		100		$0.15		($0.00)		100
Net income (loss)		5,828,965	(1,516,254)		484		8,361,584		(1,649,863)		607
	Per share - basic	$0.03	($0.01)		400		$0.05		$(0.01)		600
	Per share - diluted	$0.03	($0.01)		400		$0.04		$(0.01)		500
Capital expenditures		66,133,638	78,232,898		(15)		164,940,917		87,177,854		89
Working capital		(26,974,659)	49,610,031		(154)		(26,974,659)		49,610,031		(154)
Common Shares Outstanding
	Weighted average - basic	195,626,364	141,490,383		38		179,211,395		121,544,951		47
	Weighted average - diluted	224,068,212	141,490,383		58		208,103,830		121,544,951		71
OPERATING
Number of days		92	92				365		153
Production
	Crude oil (bbls/d)	2,204	183		1,104		1,334		155		761
	Natural gas (mcf/d)	51	32		59		34		29		17
	Natural gas liquids (bbls/d)	12	2		500		8		3		167
	Barrels of oil equivalent (boe/d-6:1)	2,225	190		1,071		1,348		162		732
Average realized price
	Crude oil ($/bbl)	97.77	80.88		21		95.80		78.90		21
	Natural gas ($/mcf)	3.43	4.19		(18)		3.68		4.05		(9)
	Natural gas liquids ($/bbl)	53.72	46.21		16		58.69		48.63		21
	Barrels of oil equivalent (6:1)	97.24	78.54		24		95.27		76.50		24
Netback per boe ($)^(1)
	Petroleum and natural gas sales	97.24	78.54		24		95.27		76.50		25
	Royalties	(6.06)	(13.64)		(56)		(8.82)		(11.37)		(22)
	Operating & transportation expenses	(14.79)	(16.32)		(9)		(16.99)		(18.24)		(7)
	Operating netback	76.39	48.58		57		69.46		46.89		48
Wells drilled
	Gross	14	8		75		30		11		173
	Net	13.3	3.6		269		25.2		5.1		403
	Success rate (%)	100	100		-		100		100		-

⁽¹⁾     NON-IFRS measure

GREATER RED EARTH AREA, ALBERTA

2011 proved to be a very exciting, eventful and sometimes challenging time for Pinecrest with all of its activities focused on the Red Earth core area.  After a successful winter drilling program, Pinecrest's capital program and production were both severely interrupted by wildfires, flooding and a third party pipeline disruption.  Despite these challenges, Pinecrest was able to materially grow both its 2P reserves and production per share by 305% and 1,427% respectively.  In addition, Pinecrest commissioned the expansion of the Evi battery and a regional gathering system that resulted in significant operating and transportation cost reductions quarter over quarter.

During the year, Pinecrest continued to develop its Slave Point resource play at Red Earth by drilling 29 gross (24.7 net) successful horizontal wells and placing 25 gross (20.75 net) of these wells on production prior to year end.  Overall, Pinecrest brought a total of 35 gross (25.5 net) on production during 2011.  The majority of these wells were horizontally drilled within the Slave Point reservoir with single laterals approximately 1,400 meters in length and completed with approximately 20 fracture stimulations per well.  Overall reservoir quality has been in line with the Company's expectations with each long lateral horizontal well receiving, on average, 210 mbbls of gross technical 2P reserves (see reserves disclosure below).  These wells are part of the Company's continuous Slave Point drilling program, which commenced in December 2010.

Pinecrest remains focused on capturing the potential upside expected with waterflooding its Slave Point reservoirs, as analogous waterfloods in the immediate area have been assigned incremental recovery factors ranging between 50 and 100 percent over primary recovery.    At this time, Pinecrest has identified and is in the process of applying for two additional operated waterflood schemes and it is anticipated that initial water injection should commence in the third quarter of 2012.

Consistent with other operators, Pinecrest has started to drill infill wells at eight wells per section spacing.  In conjunction with waterflooding, the Company anticipates that eight wells per section spacing will be the eventual well density throughout the Company's Slave Point opportunity base.  The combination of waterflooding and infill drilling/downspacing is consistent with Pinecrest's corporate strategy of focusing capital on large, low risk oil accumulations and applying its in-house technical expertise to improve recoveries and capital efficiencies.

Additionally, the Company has made strategic investments in the acquisition of undeveloped land, increasing its position in the Slave Point light oil resource play through Crown land sales.  Pinecrest has successfully grown its land holdings in its Red Earth core area to a current total of approximately 154,000 net acres with an average working interest of over 93%.  Pinecrest currently has a risked development drilling inventory of 235 (4 wells/section) or 470 (8 wells/section) net Slave Point drilling locations.  This is expected to provide the Company with six to ten years of drilling inventory at a density of four wells/section.  In addition, Pinecrest operates its own production facilities and infrastructure which can allow for quick, cost effective tie-in of wells.

The Corporate focus of Pinecrest since inception has been on significant resource capture and the productive/commercial validation of the Slave Point light oil play.  Pinecrest has now assembled a high quality asset at Red Earth with scope and scale, as validated by the Resource Assessment performed by Sproule (see below).  With this milestone behind us, the Company's goals going forward are to focus on achieving greater capital and cost efficiencies throughout its capital and operating budgets along with the implementation of waterflood schemes.

RESERVE HIGHLIGHTS

Sproule Associates Ltd. ("Sproule") was engaged as an independent qualified reserve evaluator to evaluate Pinecrest's year end reserves (the "Sproule Reserves Report") in accordance with National Instrument 51-101 ("NI 51-101") and the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook").  Reserves are stated on a working interest basis unless otherwise indicated.  Pinecrest's Annual Information Form for the year ended December 31, 2011 (the "AIF") contains Pinecrest's reserves data and other oil and gas information for the period ended December 31, 2011 as mandated by NI 51-101.  A copy of the AIF can be obtained under Pinecrest's profile at www.sedar.com or at www.pinecrestenergy.com.

Below is a brief summary of the Company's 2011 year end reserve report.

• Increased 2P reserves to 8.4 MMboe representing an increase of 364 percent (98% light sweet oil);
• Increased 2P reserves per share by 305%;
• Achieved a 2P reserve life index ("RLI") of approximately 10.3 years based on the Company's 2011 fourth quarter average production rate of 2,225 boe/d;
• Achieved a reserves replacement ratio of 14.4 based on the Company's 2011 average production of 1,348 boe/d; and
• The Company's reserves include 16 gross (13.3 net) Slave Point horizontal locations in the 2P undeveloped category.  Of these locations, 10 gross (9.75 net) have been drilled in 2012.

Summary of Reserves

	Oil and NGLs (mbbls)	Gas (mmcf)	Combined (mboe)	Future Development Capital (FDC) ($MM)
				Discounted @ 10%	Undiscounted
Proved Developed Producing	3,781.1	83	3,795.0	-	-
Proved Developed Non-Producing	205.0	7	206.1	428	430
Proved Undeveloped	1,250.1	414	1,319.1	34,374	35,460
Total Proved	5,236.2	504	5,320.2	34,802	35,891
Probable Additional	3,019.9	279	3,066.5	22,870	23,161
Total Proved plus Probable	8,256.0	784	8,386.7	57,671	59,052

The following table is a before tax net present value (at a discount rate of ten percent) summary as at December 31, 2011.

Before Tax Net Present Value Summary ^(1)(2)
	NPV10 BT ($000s)	NPV5 BT ($000s)
Proved Developed Producing	151,373	178,038
Proved Developed Non-Producing	8,773	10,124
Proved Undeveloped	18,469	28,074
Total Proved	178,616	216,236
Probable Additional	61,153	92,486
Total Proved plus Probable	239,769	308,702

^(1)	Pinecrest's crude oil, natural gas and natural gas liquid reserves were evaluated using Sproule's product price forecast effective December 31, 2011 prior to the provision for income taxes, interests, debt services charges and general and administrative expenses. It should not be assumed that the discounted future revenue estimated by Sproule represents the fair market value of the reserves.
^(2)	Assumes that development of each property will occur, without regard to the likely availability to the Company of funding required for that development.

The following table outlines Pinecrest's F&D and FD&A Costs:

Finding Development & Acquisition (FD&A) Costs ^(1)
	Proved	Proved plus Probable
FD&A costs excluding crown land purchases ($000s)	145,869	145,869
Crown land purchases ($000s)	19,072	19,072
Change in Future Development Costs ("FDC") required to develop reserves ($000s)	32,714	52,767
Total FD&A costs ($000s)	197,655	217,708
Reserve additions, net (mBOE)	4,705	7,072
FD&A costs - excluding crown lands acquired; excluding change in FDC ($/BOE)	31.00	20.63
FD&A costs - including crown lands acquired; excluding change in FDC ($/BOE)	35.06	23.32
FD&A costs - excluding crown lands acquired; including change in FDC ($/BOE)	37.95	28.09
Total FD&A costs - including crown lands acquired; including change in FDC ($/BOE)	42.01	30.78
Q4 2011 operating netback ($/BOE)	76.39	76.39
Recycle ratio - excluding crown land acquired; including change in FDC ($/BOE)	2.01	2.72

(1)

Under NI 51-101, the methodology to be used to calculate FD&A costs includes incorporating changes in future development capital ("FDC") required to bring the proved undeveloped and probable reserves to production. For continuity, Pinecrest has presented herein FD&A costs calculated both excluding and including FDC.

GREATER RED EARTH OIL RESOURCES ASSESSMENT

The Company commissioned Sproule to conduct an assessment of the Company's Contingent Slave Point Oil Resources (the "Sproule Resource Assessment") in the Greater Red Earth Area effective January 31, 2012.  The Assessment was prepared in accordance with definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook ("COGE") and NI 51-101.

Sproule's estimate of Discovered Oil Initially in Place (DOIIP) on the Company's Slave Point focused land base is over 580 MMbbl.  Sproule's estimate of Contingent Slave Point Oil Resources as of January 31, 2012 ranges from 36.2 MMbbls in the low estimate ("C1") to 110.4 MMbbls in the high estimate ("C3"), with a best estimate ("C2") of 67.5 MMbbls.  Contingent resources are in addition to the Company's currently booked reserves.  The Company's current booked reserves represent approximately 5% of the Company's existing Slave Point focused land base.  Additionally, the Contingent Resources represent approximately 40% of our existing Slave Point focused land base.

The Sproule Resources Assessment is based on a primary recovery development plan that consists of four 1,400 m long horizontal wells per section using multi-stage fracture stimulation completions.  It does not reflect any Contingent Resources or reserves attributable to secondary recovery schemes or downspaced drilling.

The table below sets out certain summary information from the Sproule Resources Assessment.

	Company Gross Contingent Oil Resource Estimates
Category	Discovered Oil Initially in place (DOIIP) ^(1)(2) (MMbbl)	Discovered Ultimate Recoverable Oil ^(3) (MMbbl)	Ultimate Reserves ^(4) (MMbbl)	Contingent Oil Resources ^(5) (MMbbl)
Low Estimate  (C1) ^(6)	584	42.5	6.3	36.2
Best Estimate (C2)^(6)	584	76.6	9.1	67.5
High Estimate (C3)^(6)	584	121.9	11.5	110.4

Notes:
(1)	"Discovered Oil Initially in place" means 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 petroleum initially in place includes production, reserves and contingent resources.  There is no certainty that it will be commercially viable to produce any portion of these resources.
(2)	All DOIIP other than cumulative production, reserves and contingent resources have been categorized as unrecoverable.
(3)	"Discovered Ultimate Recoverable Oil" equals Contingent Oil Resources plus Ultimate Reserves
(4)	"Ultimate Reserves" are technical volumes and are shown as produced oil volumes plus remaining oil reserves, as reported in the December 31, 2011 Sproule Reserves Report.  Note that 3P reserves were not included in the Sproule Reserves Report, but were estimated for the purposes of the Sproule Resources Assessment.
(5)	"Contingent Oil 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.  Contingencies may include factors such as distance from existing production, economic, legal, environmental, political, and regulatory matters or a lack of markets. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage.
(6)	"Uncertainty Ranges" as are described by the Canadian Oil and Gas Evaluation 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 percent 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 percent 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 percent probability (P10) that the quantities actually recovered will equal or exceed the high estimate.

BUDGET OUTLOOK/EXPANSION

Building on the success Pinecrest achieved in 2011, the focus of Pinecrest's capital program will remain on the Slave Point light oil play in the Greater Red Earth area.  Activities will include strategic land acquisitions to grow our considerable land/opportunity base and to grow reserves and production through continued drilling and strategic acquisitions.

The Company recently completed a bought deal financing of 18,500,000 shares at a price of $3.25 per share raising net proceeds of approximately $57.0 million.  This financing provides the Company with financial flexibility for future growth opportunities in 2012.

The Company's previously announced capital budget of $166 million for 2012 is under review in light of the recent financing and the net effect of realized commodity prices year to date.  Any changes to the published 2012 capital program and guidance will be made after the Company's drilling operations break-up period.

ANNUAL GENERAL AND SPECIAL MEETING

Pinecrest's Annual General and Special Meeting is scheduled for 10:00 am on June 5, 2012 at the Bow Valley Conference Center, Angus/Northcote Room, located at 300, 205 - 5th Avenue S.W., Calgary. Alberta, T2P 2V7.

Advisory 

The information in this press release contains certain forward-looking statements. These statements relate to future events or our future performance. All statements other than statements of historical fact may be forward-looking statements. Forward-looking statements are often, but not always, identified by the use of words such as "seek", "anticipate", "plan", "continue", "estimate", "expect", "may", "will", "project", "predict", "potential", "targeting", "intend", "could", "might", "should", "believe", "would" and similar expressions. In particular, forward looking statements in this press release includes, but is not limited to: Pinecrest's capital program and 2011 business objectives, Pinecrest's 2011 budget, oil recovery rates, the effects of waterfloods on recovery factors, decline rates and type curves for wells, production rates, exit rates for production and bank debt, downspacing opportunities, the quantity of reserves, and projections of market prices and costs. These statements involve substantial known and unknown risks and uncertainties, certain of which are beyond Pinecrest's control, including: the impact of general economic conditions; industry conditions; changes in laws and regulations including the adoption of new environmental laws and regulations and changes in how they are interpreted and enforced; fluctuations in commodity prices and foreign exchange and interest rates; stock market volatility and market valuations; volatility in market prices for oil and natural gas; liabilities inherent in oil and natural gas operations; uncertainties associated with estimating oil and natural gas reserves; competition for, among other things, capital, acquisitions, of reserves, undeveloped lands and skilled personnel; incorrect assessments of the value of acquisitions; changes in income tax laws or changes in tax laws and incentive programs relating to the oil and gas industry; geological, technical, drilling and processing problems and other difficulties in producing petroleum reserves. Pinecrest's actual results, performance or achievement could differ materially from those expressed in, or implied by, such forward-looking statements and, accordingly, no assurances can be given that any of the events anticipated by the forward-looking statements will transpire or occur or, if any of them do, what benefits that Pinecrest will derive from them. Except as required by law, Pinecrest undertakes no obligation to publicly update or revise any forward-looking statements.

Statements relating to "reserves" or "resources" are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the resources or reserves described can be profitably produced in the future.

The Corporation uses the following terms for measurement within this press release that do not have a standardized prescribed meaning under GAAP and these measurements may differ from other companies and accordingly may not be comparable to measures used by other companies. The terms "funds from operations" and "operating netback" are not recognized measures under the applicable GAAP. Management of the Corporation believes that these terms are useful, in addition to profit and loss and cash flow from operating activities as defined by GAAP, for evaluating the Corporation's operating performance and leverage. Funds from operations is expressed as cash flow from operating activities before changes in non-cash working capital and asset retirement expenditures. Operating netback is a measure of operating margin used in capital allocation decisions. Pinecrest defines operating netback as average realized price per BOE, less royalties per BOE, less operating and transportation expenses per BOE, plus any realized gain or loss per BOE on financial instruments.

Certain information provided in this press release in relation to the results of waterflooding Slave Point reservoirs on lands in close proximity to the land in which the Company has an interest, is considered analogous information under National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities.  Such information is based on publicly available information from governmental agencies and other industry producers and has been provided to give an indication of possible incremental recovery factors in the specified area.  Other than comparing such information to the Company's own limited results in the specified area, the Company has not independently confirmed the accuracy of this information.  There is no certainty that such incremental recovery factors will be obtained of even if so obtained, whether such factors can be achieved on an economic basis.

Barrels of Oil Equivalent ("boe") may be misleading, particularly if used in isolation. A boe conversion ratio of 6MCF:1bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1,utilizing a conversion on a 6:1 basis may be misleading as an indication of value.

Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this news release.

 

 

 

 

Pinecrest Energy Inc.
Suite 500, 255 - 5^th Avenue S.W.
Calgary, Alberta  T2P 3G6

Wade Becker, President and CEO
or
Dan Toews, V.P. Finance & CFO

Tel: [phone] or
Fax: [phone]