TSX Venture Exchange: PRY
CALGARY, Nov. 14, 2012 /CNW/ - Pinecrest Energy Inc. ("Pinecrest" or the
"Company") is pleased to provide an update on the performance of the
Company's waterflood schemes as well as an operational update.
EVI - Project #1
The results to date from the Company's first joint waterflood in the Evi
area have been encouraging. Water injection commenced on a continuous
basis in May, 2012 with initial incremental oil response observed
within 2-3 months. Since first response, oil production rates from the
Company's joint offsetting wells have increased rapidly and
significantly. Three wells (one horizontal and two vertical wells)
offsetting the injector have increased by factors of between three and
six times their respective rates prior to the commencement of water
injection. This response is consistent with those observed in other
water injection scheme areas within the Company's Greater Red Earth
core area. In aggregate, production has increased from 16 bbls/d to 88
bbls/d. These results provide support for the low cost repeatable
upside associated with pressure maintenance by way of waterflooding.
After injecting approximately 70,000 bbls of water, the offsetting
producing wells have increased as follows:
Oil Rate Prior
Pinecrest plans the implementation of an additional seven waterflood
schemes prior to the end of 2013. Within these schemes, eight wells
will be converted to injectors supporting approximately 20 producing
wells. The 20 producing wells have current aggregate production of
approximately 850 barrels of oil per day. Management is projecting that
all of the proposed schemes will see similar production responses and
within the same time frames (two to three months) as the other five
existing waterflood schemes in the immediate area.
Pinecrest's first 100% operated waterflood scheme has received ERCB
approval; facility construction has commenced and water injection is
scheduled to begin in December 2012. Approval for the second
waterflood scheme is anticipated to be received prior to year end 2012
with injection commencing prior to the end of Q1 2013. The five
remaining projects are expected to be phased in throughout the second
and third quarters of 2013.
The location of the seven waterflood schemes are dispersed throughout
the Greater Red Earth area, encompassing the Evi, Otter, Loon and Red
Earth fields. All of the proposed waterflood schemes will utilize
existing wells and will enjoy similar or lower capital efficiencies as
the initial Evi - Project #1 waterflood. It is anticipated that an
equal number of waterflood schemes will be commissioned in 2014.
Impact of Waterflood Projects
Management estimates that the seven planned 2013 waterflood schemes will
provide the Company with waterflood specific capital efficiencies of
less than $10,000 per flowing barrel. Additionally, the introduction
of the pressure maintained production stream is anticipated to
materially change the Company's overall production decline profile.
The combination of the Company's large drilling inventory, industry
leading production netback, improving capital efficiencies and
attenuated corporate decline rate will drive the growth profile of the
Company for the foreseeable future.
The implementation of the waterflood schemes is an integral piece of the
Company's strategy of increasing the recovery factor of the large
contingent oil resource. Effective January 31, 2012, Sproule
Associates Ltd. ("Sproule") provided a best estimate that the Company
has over 580 million barrels of discovered oil originally-in-place,
with the best estimate of contingent resources being 67.5 million
barrels of oil. The best estimate of the contingent oil resources plus
proved plus probable reserves associated with the area incorporates a
13% recovery factor and is based solely on primary recovery. The
empirical data from the offsetting historical waterfloods suggests that
overall recoveries of 20% or greater are possible.
PRODUCTION AND DRILLING
Current field production is estimated to be in excess of 4,000 boe/day.
As well, between 9-13 additional wells will commence production before
year end. The Company is maintaining its exit production guidance of
5,000 - 5,200 boe/day.
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 2012 business
objectives, Pinecrest's 2012 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.
Many of the risks and uncertainties described above and additional risk
factors are described in the Company's Annual Information Form which is
available at www.sedar.com and www.pinecrestenergy.com. Readers are also referred to risk factors described in other
documents Pinecrest files with Canadian securities authorities.
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.
Reserves and Resource Estimates
The estimates of discovered oil initially-in-place and contingent
resources presented herein are based on an assessment by Sproule of the
Company's Contingent Slave Point Oil Resources (the "Sproule
Assessment") in the Greater Red Earth Area effective January 31, 2012.
All estimates of resources and reserves as well as the cumulative
production volumes presented herein represent Pinecrest's gross
interest resources, reserves or production before the deduction of any
royalties and without including any royalty interests of Pinecrest.
The Sproule Assessment was prepared in accordance with definitions,
standards and procedures contained in the Canadian Oil and Gas
Evaluation Handbook ("COGE") and National Instrument 51-101 Standards
of Disclosure for Oil and Gas Activities. Certain resource definitions
as set out in the COGE Handbook are set out below:
Discovered oil initially-in-place is that quantity of oil that is estimated, as of a given date, to be
contained in known accumulations prior to production. The recoverable
portion of discovered oil initially-in-place includes cumulative
production, reserves, and contingent resources; the remainder is
categorized as unrecoverable. The best estimate of discovered oil
initially-in-place presented herein includes 0.96 mmbbls of cumulative
production (as at December 31, 2011), 8.1376 mmbls of reserves (proved
plus probable as at December 31, 2011), 67.5 mmbbls contingent
resources (best estimate as at January 31, 2012) and 507.4 mmbbls of
unrecoverable discovered oil-initially-in-place resources.
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. Contingencies may include such factors as 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. With respect to the contingent resources
associated with the Company's interests in the Great Red Earth Area,
the primary contingency which prevents the classification of the
contingent resources as reserves is the current early stage of
development. Additional drilling, completion, and testing data will be
required before the contingent resources can be classified as reserves.
There is no certainty that it will be commercially viable to produce any
portion of the contingent resources or that any portion of the volumes
currently classified as contingent resources will be produced. The
recovery and resource estimates provided herein are estimates. Actual
contingent resources (and any volumes that may be classified as
reserves) and future production from such contingent resources may be
greater than or less than the estimates provided herein.
Unrecoverable discovered petroleum initially-in-place is that portion of discovered oil initially-in-place 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.
Best Estimate of a resource represents 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 quantities actually recovered will equal
or exceed the best estimate.
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
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
SOURCE: Pinecrest Energy Inc.
For further information:
Pinecrest Energy Inc.
Suite 500, 255 - 5th Avenue S.W.
Calgary, Alberta T2P 3G6
Wade Becker, President and CEO
Dan Toews, V.P. Finance& CFO
Tel: (403) 817-2550 or
Fax: (403) 817-2599