VIRGINIA HILLS OIL CORP VFGGF

Pinecrest Energy Inc. announces its December 31, 2

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Pinecrest Energy Inc. announces its December 31, 2012 Year End Results and 2012 Year End Reserves

8 hours ago - ACQUIREMEDIA

TSX Venture Exchange:  PRY

CALGARY, March 18, 2013 /CNW/ - Pinecrest Energy Inc. ("Pinecrest" or the "Company") is pleased to announce that it has filed on SEDAR its audited annual financial statements, related Management's Discussion and Analysis ("MD&A") and Annual Information Form for the year ended December 31, 2012.  The statements will be available for review atwww.sedar.com or www.pinecrestenergy.com.

2012 HIGHLIGHTS

• Increased proved plus probable reserves by 107% to 16.2 mmboe (99% oil) and proved reserves by 100% to 9.5 mmboe (99% oil).  Proved reserves represent 58% of proved plus probable reserves as at December 31, 2012;
   
• Increased proved plus probable reserves per fully diluted share by 70% to 68 boe per 1,000 shares from 40 boe per 1,000 shares;
   
• Pinecrest's 2012 capital program added proved plus probable reserves at a cost of $23.64 per boe excluding future development capital ("FDC") and $33.37 per boe including FDC;
   
• Emphasizing the quality of the Company's production base and the efficiency of its operations, Pinecrest continued to generate a top ranking operating netback of $66.01 per boe for the year ended December 31, 2012, despite a realized price decrease of 10%, compared to$69.46 per boe for the year ended December 2011.  Operating netback for Q4 2012 was$65.71 per boe compared to $76.39 per boe for Q4 2011 and increased by 2% compared to$64.33 per boe in Q3 2012;
   
• Pinecrest achieved a finding, development and acquisition ("FD&A") recycle ratio of 2.8 excluding FDC and 2.0 including FDC based on our 2012 operating netback of $66.01 per boe;
   
• Replaced 2012 production by greater than 4 times on a proved basis and 8 times on a proved plus probable basis;
   
• Maintained an attractive reserves life index of 12.7 years based on our Q4 2012 average production rate of 3,510 boe per day;
   
• Increased average production 133% to 3,142 boe per day (99% light oil) for the year endedDecember 31, 2012, from 1,348 boe per day for the year ended 2011.  Average production increased by 58% for Q4 2012 to 3,510 boe per day (99% light oil) compared to Q4 2011 (2,225 boe per day), and increased by 28% over Q3 2012 (2,748 boe per day);
   
• Increased average production per share by 104%;
   
• Increased funds from operations by 130% to $71.8 million ($0.34 per basic and $0.30 per diluted shares outstanding) compared to $31.2 million ($0.17 per basic and $0.15 per diluted shares outstanding) for the year ended December 2011.  Fourth quarter funds from operations increased by 41% to $20.7 million ($0.10 per basic and $0.09 per diluted shares outstanding) for Q4 2012 compared to $14.6 million ($0.07 per basic and diluted shares outstanding) during Q4 2011, and increased 38% in Q4 2012 compared to $15.0 million from Q3 2012;
   
• Pinecrest increased 2012 net income by 284% to a corporate record of $32.1 million ($0.15per basic and $0.13 per diluted shares outstanding) compared to $8.4 million ($0.05 per basic and $0.04 per diluted shares outstanding) in 2011 and increased Q4 net income 115% to$12.5 million ($0.06 per basic and $0.05 per diluted shares outstanding) compared to $5.8 million in Q4 2011;
   
• Increased drilling inventory to over 400 net locations as at January 1, 2013 of which 50 gross (40.7 net) are currently booked (un-booked portion of drilling inventory is supported by the Independent Third Party Assessment of the Contingent and Prospective Oil Resources report, dated January 31, 2012);
   
• The Company achieved 100% drilling success with a total of 39 (37.7 net) horizontal oil wells drilled during the year ended December 31, 2012 compared to 29 (24.7 net) oil wells drilled during the year ended 2011.  Pinecrest drilled 10 additional wells more than originally planned in 2012 to accelerate the Company's waterflood schemes.  A total of 16 (15.3 net) horizontal oil wells were drilled in the fourth quarter of 2012, compared to 14 (13.3 net) wells in Q4 2011;
   
• Commenced water injection in late December 2012 at the Company's first 100% operated waterflood scheme which has already demonstrated a positive response (an increase in pressure and production rates) from offsetting producing wells.  Pinecrest received ERCB approval to implement six additional 100% operated waterflood projects, and expects to commence injection at the Loon-Project #1 in the first quarter 2013;
   
• Operational efficiencies reduced transportation and production costs to $14.92 per boe for the year ended December 31, 2012 compared to $16.99 per boe for the year ended December 31, 2011.  Transportation and production costs were $15.22 per boe for Q4 2012 compared to $14.79 per boe in Q4 2011, and decreased from $15.68 per boe from the third quarter 2012;
   
• Pinecrest exited the year with a strong balance sheet with net debt and working capital deficit of $100.2 million on a bank line of $125 million (at December 31, 2012, $59.8 million was drawn on the credit line).  Subsequent to the year ended December 31, 2012, Pinecrest's bank indicated an increase in total credit available to $155.0 million.
   
• Pinecrest's Net Asset Value (NAV) is estimated at $1.67 per basic share based on net present value discounted at 10% (before tax) Proved plus Probable (2P) reserves at December 31, 2012 and an independent land evaluation as at December 31, 2012; and
   
• Based on Pinecrest's third party contingent resource and reserve reports, the internally calculated NAV per basic share is estimated at $4.43 including all un-booked drilling locations.  This estimate is based on primary recovery only, not including the considerable upside potential via waterflooding.
   

Â		Â	Â	Â	Â	Â	Â
December 31		Three months ended			Year ended
Â		2012	2011	%  Change	2012	2011	%  Change
FINANCIAL		   Â	Â	Â	Â	Â	Â
Petroleum and natural gas sales		   26,581	19,897	34	98,204	46,846	110
Funds flow from operations (1)(2)		20,663	14,616	41	71,779	31,166	130
  Â	Per share - basic	   $0.10	$0.07	43	$0.34	$0.17	100
 Â	Per share - diluted	   $0.09	$0.07	29	$0.30	$0.15	100
Net income		   12,527	5,828	115	32,129	8,362	284
  Â	Per share - basic	   $0.06	$0.03	100	$0.15	$0.05	200
  Â	Per share - diluted	   $0.05	$0.03	67	$0.13	$0.04	225
Capital expenditures		   80,320	66,134	21	212,800	164,940	29
Working capital deficit, including debt		(100,175)	(26,974)	271	(100,175)	(26,974)	271
Common Shares Outstanding (000's)		   Â	Â	Â	Â	Â	Â
  Â	Weighted average - basic	   214,311	195,626	10	210,482	179,211	17
  Â	Weighted average -  diluted	   238,543	224,068	6	238,373	208,104	15
OPERATING		   Â	Â	Â	Â	Â	Â
Number of days		   92	92	Â	366	365	Â
Production		   Â	Â	Â	Â	Â	Â
 Â	Crude oil (bbls/d)	   3,484	2,204	58	3,124	1,334	134
 Â	Natural gas (mcf/d)	   93	51	82	62	34	82
 Â	NGL (bbls/d)	   10	12	(17)	8	8	-
 Â	Barrels of oil equivalent (boe/d-6:1)	   3,510	2,225	58	3,142	1,348	133
Average realized price		   Â	Â	Â	Â	Â	Â
 Â	Crude oil ($/bbl)	   82.72	97.77	(15)	85.73	95.80	(11)
 Â	Natural gas ($/mcf)	   3.18	3.43	(7)	2.36	3.68	(36)
 Â	NGL ($/bbl)	   40.59	53.72	(24)	48.33	58.69	(18)
 Â	Barrels of oil equivalent ($/boe- 6:1)	   82.31	97.24	(15)	85.41	95.27	(10)
Netback per boe ($)(1)		   Â	Â	Â	Â	Â	Â
 Â	Petroleum and natural gas sales	   82.31	97.24	(15)	85.41	95.27	(10)
 Â	Realized gain (loss)  on derivative contracts	   4.64	-	100	2.01	-	100
 Â	Royalties	   (6.02)	(6.06)	(1)	(6.49)	(8.82)	(26)
 Â	Transportation and production  expenses	   (15.22)	(14.79)	3	(14.92)	(16.99)	(12)
 Â	Operating netback	   65.71	76.39	(14)	66.01	69.46	(5)
Wells drilled		   Â	Â	Â	Â	Â	Â
 Â	Gross	   16	14	14	39	29	34
 Â	Net	   15.3	13.3	15	37.7	24.7	5
 Â	Success rate (%)	   100	100	-	100	100	-

(1)     Non-GAAP measure
(2)     Excludes $11.8 million relating to termination fee income, net of costs

The following tables summarize certain information contained in the independent reserves report prepared by Sproule Associates Ltd. ("Sproule") as at December 31, 2012.  The report was prepared in accordance with definition, standards and procedures contained in theCanadian Oil and Gas Evaluation Handbook ("COGE Handbook") and National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101").  Additional reserves information as required under NI 51-101 will be included in the Company's Annual Information Form - a copy of which can be obtained under Pinecrest's profile atwww.sedar.com or at www.pinecrestenergy.com.

SUMMARY OF RESERVES

 

Â	Oil and NGLs  (mbbls)	Gas  (mmcf)	Combined  (mboe)	NPV 10% (1)  ($000)	Undiscounted  Future  Development Capital ($000)	Net  Undeveloped Locations  Booked
Proved Developed Producing	5,877.1	322	5,930.9	205,088	-	-
Proved Developed Non-Producing	645.9	13	648.1	23,805	2,203	-
Proved Undeveloped	2,886.5	62	2,896.9	24,137	88,176	23.4
Total Proved	9,409.5	398	9,475.8	253,030	90,379	23.4
Probable Additional	6,724.1	248	6,765.4	99,523	56,297	17.3
Total Proved plus Probable	16,133.6	645	16,241.2	352,553	146,675	40.7

(1)     Before Tax

 

2012 FD&A COSTS

 

Â		Â	Â
Finding Development & Acquisition (FD&A) Costs (1)(2)
Â		Total Proved  ($000)	Proved plus  Probable  ($000)
2012 Capital Expenditures ($000s)		Â	Â
Land		8,643	8,643
Development		193,163	193,163
Net Acquisitions		10,994	10,994
Change in FDC		54,488	87,573
Total Capital		267,288	300,373
Â		Â	Â
2012 Reserve Additions Mboe		Â	Â
Acquisitions		322	433
Additions/Revisions		4,979	8,567
Total		5,301	9,000
Â		Â	Â
2012 FD&A ($/boe)(1)		Â	Â
     Â	Including FDC	50.42	33.37
     Â	Before FDC	40.14	23.64

(1)  Â

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.

(2) Â

While NI 51-101 requires that the effects of acquisitions and dispositions be excluded from the calculation of FD&A, FD&A costs have been presented because acquisitions and dispositions can have a significant impact on the Company's ongoing reserve replacement costs and excluding these amounts could result in an inaccurate portrayal of the Company's cost structure.  The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in the estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.

 

OPERATIONAL UPDATE

Pinecrest is in the midst of a very active first quarter operating three drilling rigs in its Red Earth core area.   By the end of Q1 2013, the Company expects to have drilled 12 (11.25 net) wells and completed 14 (12.75 net) wells, with 100% success (including one net water source well to be utilized in a future pressure maintenance scheme).  Six (5.25 net) wells have been placed on production along with an additional 4 (3.5 net) wells that were drilled in 2012.  The remaining horizontal wells drilled in the first quarter are planned to be on production before the end of April.  Based on experience operating in the area, Pinecrest does not budget any drilling activity during the second quarter due to wet access and road bans, however the Company is confident in its ability to drill and bring on a total of 30-34 net horizontal wells as per our previously announced 2013 budget.

Pinecrest is very encouraged by the early results of its waterflooding activities, having previously reported increases in pressure and production rates on its initial Evi Projects #1 and #2.  These first two pressure maintenance schemes continue to perform in accordance with expectations.  We have received ERCB approval to proceed with an additional six waterflood schemes in the greater Red Earth area. The required field work has been completed and we expect the ERCB to grant final injection approval on our second operated scheme imminently.  Construction of the required field facilities for the third and fourth operated schemes has commenced and we anticipate having water injection into these two, as well as the three previously approved schemes by the end of the third quarter.

2013 production is tracking our budget and we are confident we will meet or exceed our year end exit estimate of 6,000 boe per day (99% oil).  With our 2012 top decile netback and strong recycle ratio, the Company is well situated to continue strong growth regardless of fluctuations in commodity pricing.

ANNUAL GENERAL AND SPECIAL MEETING

Pinecrest's Annual General and Special Meeting is scheduled for 10:00 am on June 5, 2013 at the Bow Valley Conference Centre, Angus/Northcote Room, located at 300, 205 - 5th Avenue S.W., Calgary. Alberta, T2P 2V7.