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 at www.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 ended December 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 ($0.15 per 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.
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December 31 |
Three
months ended |
Year ended |
|
2012 |
2011 |
%
Change |
2012 |
2011 |
%
Change |
FINANCIAL |
|
|
|
|
|
|
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 |
|
Per share - basic |
$0.10 |
$0.07 |
43 |
$0.34 |
$0.17 |
100 |
|
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 |
|
Per share - basic |
$0.06 |
$0.03 |
100 |
$0.15 |
$0.05 |
200 |
|
Per share - diluted |
$0.05 |
$0.03 |
67 |
$0.13 |
$0.04 |
225 |
Capital expenditures |
80,320 |
66,134 |
21 |
212,800 |
164,940 |
29 |
Working capital deficit, including
debt |
(100,175) |
(26,974) |
271 |
(100,175) |
(26,974) |
271 |
Common Shares Outstanding (000's) |
|
|
|
|
|
|
|
Weighted average - basic |
214,311 |
195,626 |
10 |
210,482 |
179,211 |
17 |
|
Weighted average - diluted |
238,543 |
224,068 |
6 |
238,373 |
208,104 |
15 |
OPERATING |
|
|
|
|
|
|
Number of days |
92 |
92 |
|
366 |
365 |
|
Production |
|
|
|
|
|
|
|
Crude oil (bbls/d) |
3,484 |
2,204 |
58 |
3,124 |
1,334 |
134 |
|
Natural gas (mcf/d) |
93 |
51 |
82 |
62 |
34 |
82 |
|
NGL (bbls/d) |
10 |
12 |
(17) |
8 |
8 |
- |
|
Barrels of oil equivalent (boe/d-6:1) |
3,510 |
2,225 |
58 |
3,142 |
1,348 |
133 |
Average realized price |
|
|
|
|
|
|
|
Crude oil ($/bbl) |
82.72 |
97.77 |
(15) |
85.73 |
95.80 |
(11) |
|
Natural gas ($/mcf) |
3.18 |
3.43 |
(7) |
2.36 |
3.68 |
(36) |
|
NGL ($/bbl) |
40.59 |
53.72 |
(24) |
48.33 |
58.69 |
(18) |
|
Barrels of oil equivalent ($/boe- 6:1) |
82.31 |
97.24 |
(15) |
85.41 |
95.27 |
(10) |
Netback per boe ($)(1) |
|
|
|
|
|
|
|
Petroleum and natural gas sales |
82.31 |
97.24 |
(15) |
85.41 |
95.27 |
(10) |
|
Realized gain (loss) on
derivative contracts |
4.64 |
- |
100 |
2.01 |
- |
100 |
|
Royalties |
(6.02) |
(6.06) |
(1) |
(6.49) |
(8.82) |
(26) |
|
Transportation and production expenses |
(15.22) |
(14.79) |
3 |
(14.92) |
(16.99) |
(12) |
|
Operating netback |
65.71 |
76.39 |
(14) |
66.01 |
69.46 |
(5) |
Wells drilled |
|
|
|
|
|
|
|
Gross |
16 |
14 |
14 |
39 |
29 |
34 |
|
Net |
15.3 |
13.3 |
15 |
37.7 |
24.7 |
5 |
|
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 the Canadian
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 at www.sedar.com or at
www.pinecrestenergy.com.
SUMMARY OF RESERVES
|
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 |
2012 FD&A COSTS
|
|
|
Finding Development &
Acquisition (FD&A) Costs (1)(2) |
|
Total Proved
($000) |
Proved plus
Probable
($000) |
2012 Capital Expenditures
($000s) |
|
|
Land |
8,643 |
8,643 |
Development |
193,163 |
193,163 |
Net Acquisitions |
10,994 |
10,994 |
Change in FDC |
54,488 |
87,573 |
Total Capital |
267,288 |
300,373 |
|
|
|
2012 Reserve Additions
Mboe |
|
|
Acquisitions |
322 |
433 |
Additions/Revisions |
4,979 |
8,567 |
Total |
5,301 |
9,000 |
|
|
|
2012 FD&A
($/boe)(1) |
|
|
|
Including FDC |
50.42 |
33.37 |
|
Before FDC |
40.14 |
23.64 |
(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. |
(2) |
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.
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
2013 business objectives, Pinecrest's 2013 budget, oil recovery
rates, drilling plans for 2013, expected production, expected oil
to gas ratios, the effects of waterfloods on recovery factors,
anticipated receipt of ERCB approvals, decline rates and type
curves for wells, success in anticipated drilling in Q1 2013,
production rates, exit rates for production and bank debt,
downspacing opportunities, the quantity of reserves, and
projections of market prices, anticipated increase to the Company's
credit facility, 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. Forward-looking statements are made as of the
date herein 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.
Net asset value per share as presented herein
is based on the [PVBT10] of proven plus probable reserves as at
December 31, 2012 of $353 million, 2012 year end net debt of
$100 million, a December 31, 2012 independent third party
valuation estimate of Pinecrest's undeveloped land of $106 million, for total net asset value of
$376 million and with 214.3 million
basic shares outstanding is a net asset value of $1.67/share.
Net asset value per share including all
un-booked drilling locations as presented herein is calculated
based on Pinecrest's January 31, 2012
third party contingent resource report along with internal
engineering estimates of $694 million
and [PVBT10] of proven plus probable reserves as at December 31, 2012 of $353
million, 2012 year end net debt of $100 million less an independent third party
valuation estimate of Pinecrest's undeveloped land as at
December 31, 2012 of $106 million for total net asset value of
$589 million and with 214.3 million
basic shares outstanding is a net asset value of $4.43/share.
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.
SOURCE Pinecrest Energy Inc.