TSX Venture Exchange: PRY
CALGARY,
Nov. 27, 2013 /CNW/ - Pinecrest
Energy Inc. ("Pinecrest" or the "Company") announces that it has
filed on SEDAR its unaudited financial statements and related
Management's Discussion and Analysis ("MD&A") for the three and
nine months ended September 30,
2013. The statements will be available for review at
www.sedar.com or www.pinecrestenergy.com.
THIRD QUARTER 2013 HIGHLIGHTS
The following update highlights operational
matters undertaken by Pinecrest during the three months ended
September 30, 2013:
- Completed field operations and injection well conversions on
its third (Evi Project #3) and fourth (Red Earth Project #1)
operated waterflood schemes, and commenced injection on both these
schemes in late July. Subsequent to September 30, the Company initiated injection on
three additional waterflood schemes in the Otter area, bringing the
active waterflood count to eight, comprising more than one third of
total corporate production;
- Drilled 3 gross (3.0 net) wells achieving a 100% success
rate:
- Average production of 2,804 boe per day (97% light oil &
NGLs). The Company's production for the quarter was adversely
affected by a major facility turnaround (required 17 days of
downtime; 307 boe per day lost production over the quarter) and by
the conversion of seven producing oil wells to water injection
(approximately 260 boe per day lost production over the
quarter);
- Top quartile field netback of $60.54 per boe;
- Observed a production response at its Evi Project #3 (November
oil production is up approximately 60% over June's production based
upon field estimates); and
- Average cost to drill, complete, and equip a well of
$3.4 million. Pinecrest has
been continuously refining its well design and has most recently
achieved a cost savings of approximately $2.3 million per well as compared to the first
half of 2012.
FINANCIAL AND OPERATIONAL HIGHLIGHTS
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September 30 |
Three months ended |
Nine months ended |
|
2013 |
2012 |
2013 |
2012 |
FINANCIAL |
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|
Petroleum and natural gas sales |
25,921 |
21,006 |
89,323 |
71,623 |
Funds flow from
operations, before realized derivative
financial instrument gains or losses (1) |
13,574 |
14,068 |
53,069 |
50,307 |
Funds flow from operations
(1) |
9,582 |
14,975 |
47,336 |
51,116 |
|
Per share - basic |
$0.04 |
$0.07 |
$0.22 |
$0.24 |
|
Per share - diluted |
$0.04 |
$0.06 |
$0.21 |
$0.21 |
Net income (loss) |
(843) |
4,578 |
7,069 |
19,602 |
|
Per share - basic |
$0.00 |
$0.02 |
$0.03 |
$0.09 |
|
Per share - diluted |
$0.00 |
$0.02 |
$0.03 |
$0.08 |
Capital expenditures |
23,886 |
56,979 |
79,761 |
132,480 |
Net debt and working capital deficit
(2) |
(128,617) |
(51,489) |
(128,617) |
(51,489) |
Common Shares Outstanding |
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|
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Weighted average - basic |
217,375 |
214,289 |
215,730 |
209,197 |
|
Weighted average -
diluted |
217,375 |
239,594 |
228,203 |
237,984 |
OPERATING |
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Number of days |
92 |
92 |
273 |
274 |
Production |
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Crude oil (bbls/d) |
2,674 |
2,730 |
3,457 |
3,002 |
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Natural gas (mcf/d) |
463 |
65 |
433 |
51 |
|
NGL (bbls/d) |
53 |
7 |
43 |
7 |
|
Barrels of oil
equivalent (boe/d-6:1) |
2,804 |
2,748 |
3,572 |
3,018 |
Average realized price
(3) |
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Crude oil ($/bbl) |
103.90 |
83.50 |
93.66 |
86.91 |
|
Natural gas ($/mcf) |
2.52 |
1.98 |
2.97 |
1.86 |
|
NGL ($/bbl) |
51.54 |
35.09 |
48.91 |
52.10 |
Netback per boe
($)(1) |
|
|
|
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Petroleum and natural gas
sales |
100.46 |
83.09 |
91.59 |
86.61 |
|
Royalties |
(10.86) |
(6.67) |
(7.78) |
(6.67) |
|
Production and
transportation expenses |
(29.06) |
(15.68) |
(22.74) |
(14.80) |
|
Field netback |
60.54 |
60.74 |
61.07 |
65.14 |
|
Realized gain
(loss) on derivative financial instruments |
(15.46) |
3.59 |
(5.88) |
0.98 |
|
Operating netback |
45.08 |
64.33 |
55.19 |
66.12 |
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Wells drilled |
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Gross |
3.0 |
13.0 |
15.0 |
23.0 |
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Net |
3.0 |
12.8 |
14.3 |
22.5 |
|
Success rate (%) |
100 |
100 |
100 |
100 |
(1) |
Non-GAAP measure |
(2) |
Net debt and working capital if defined as
current assets minus current liabilities, plus outstanding debt,
excluding derivative financial instruments |
(3) |
Before the effects of derivative financial
instruments |
WATERFLOOD UPDATE
During 2013, the Company has continued to focus
its efforts on establishing a sustainable and predictable low
decline light oil production base through the implementation of
seven operated waterflood projects. During the quarter, seven
wells producing approximately 260 barrels per day of oil were shut
in and converted to water injectors for the Otter Projects #1, #2
and #3. These three projects are more than double the size of
the initial four schemes and are forecast to provide a meaningful
impact to the Company's production profile. Production response on
these new projects is anticipated in Q1 2014. Pinecrest currently
has over one third of its production being pressure maintained by
waterflooding and as reservoir pressures rise and volumes increase
as projected, this production base is expected to grow to
approximately fifty percent of corporate production by early Q2
2014.
The Company continues to see encouraging results
from the four previously announced operated waterflood schemes, Evi
Project #2 (December 2012), Loon
Project #1 (March 2013), Evi Project
#3 (July 2013) and Red Earth Project
#1 (July 2013). Response times
and production increases for these schemes are within Company
expectations. Wells in areas downspaced to eight wells per section
have been the first to experience the effect of re-pressurization,
resulting in quicker production increases than those spaced at four
wells per section. The Company anticipates further gains in
production rates from these and future Pinecrest operated schemes
in the Greater Red Earth area. Pinecrest's active waterflood
count is now comprised of eight projects and the Company has
applied for an additional four schemes for implementation in
2014.
All schemes have been on continuous injection
since start-up with voidage replacement ratios (VRR) monitored and
adjusted continuously as fluid production from the schemes steadily
increases. Excluding the August battery turnaround,
offsetting producing wells in all schemes have been on continuous
production with the exception of Evi Project #2, in which a routine
bottomhole pump failure occurred during breakup causing the
offsetting producing well to be down for 27 days which also
necessitated an injection rate reduction.
The following chart shows the shallowing impact
of pressure maintenance on the Company's waterflood production
profile for the period September 2012
to October 2013. Additionally,
the Company anticipates this production to increase as the balance
of the 2013 waterfloods respond.
OPERATIONS UPDATE
Wet weather delayed the implementation of the
Company's third quarter capital program and caused an increase in
unscheduled downtime due to difficult field conditions.
During the third quarter, the Company drilled three wells and
completed two of these wells. The average cost to drill, complete
and equip the wells drilled in the quarter was $3.4 million per well, a $2.3 million per well savings as compared to the
first half of 2012.
Operating costs were also negatively impacted by
the operating conditions (lease repair and road maintenance).
Additionally, the initial start-up phase of the waterflood schemes
caused an increase in operating costs. Initially, water and
power for the injection facilities is supplied via temporary
means. Water is trucked to each site and power is supplied
using rental generators and diesel fuel. Pinecrest has
completed the field electrification at the Red Earth and Loon
fields which will reduce costs. Injection water is now being
delivered by pipeline to all but one of the Company's injection
schemes, eliminating significant trucking costs. In addition,
costs associated with emulsion trucking have been reduced as the
majority of the wells have now been tied into central production
facilities.
The Company expects that these initiatives and
others currently being implemented will have a positive impact on
lowering the Company's overall operating costs.
For the balance of 2013, Pinecrest is targeting
total operating expenses (production and transportation costs) of
approximately $23.00 per boe.
The implementation of all of Pinecrest's operating cost initiatives
will not be fully realized until Q1 2014.
Current production is approximately 2,650 boed,
with approximately 350 boed shut in due to field conditions.
For the balance of the year the company expects to invest minimal
capital as it awaits the response of its waterfloods.
OUTLOOK - GREATER RED EARTH AREA, ALBERTA
Pinecrest commenced operations in early 2011
with a minimal production base and has organically grown the
Company, almost exclusively, through the drill bit by way of an
aggressive capital program focused on the large oil in place Slave
Point formation in the Greater Red Earth area. As a result,
the corporate decline rate has, at times, mimicked that of a
horizontal Slave Point oil well. On average, a Slave Point
horizontal oil well will experience a first year natural decline of
approximately 65% to 70%, which is typical for all tight oil
reservoirs. With the licensing and implementation of the
seven operated waterfloods, the Company has now transitioned from a
high decline production base dominated by newly drilled horizontal
wells to a more stable, lower decline asset base. Pinecrest
entered 2013 with an estimated annualized monthly decline rate of
approximately 55% compared to an estimated current decline rate of
32%. It is expected that this overall decline rate will continue to
abate as the full effect and benefit of the Company's waterflood
initiatives occurs over the coming months.
This reduction in corporate decline rates
combined with improving capital efficiencies and a focus on
operating cost reductions, is projected to grow production while
spending significantly less capital in the upcoming years.
With the anticipated response of the remaining four operated 2013
waterfloods, the Company expects to generate cash flow in excess of
capital requirements in 2014.
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, the effects of waterfloods on recovery factors, the
potential success of waterfloods in the Slave Point area, decline
rates and type curves for wells, production rates, effect of
operations initiatives, timing for implementation of operating cost
initiatives, 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; regulatory approvals and permits;
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.
SOURCE Pinecrest Energy Inc.
Image with caption: "Pinecrest Energy Inc. Total Waterflood
Performance (CNW Group/Pinecrest Energy Inc.)". Image available at:
http://photos.newswire.ca/images/download/20131127_C5698_PHOTO_EN_33983.jpg