Painted Pony Reports Increased Credit Facilities and First Quarter 2017 Financial and Operating Results
Wednesday, May 10, 2017 6:35:00 PM ET
Painted Pony Petroleum Ltd. ("Painted Pony" or the "Corporation") (TSX: PPY) is pleased to announce increased credit facilities and first quarter 2017 financial and operating results. The first quarter was notable for the announcement of the proposed strategic acquisition of UGR Blair Creek Ltd. ("UGR") through a share purchase agreement whereby Painted Pony agreed to acquire all of the issued and outstanding shares of UGR ("UGR Acquisition"), subject to shareholder approval on May 11, 2017 at the annual general and special meeting of Painted Pony shareholders.
FIRST QUARTER 2017 HIGHLIGHTS:
-- Entered into an agreement to increase credit facilities to $500
million conditional upon closing of the UGR acquisition,
including available credit facilities of $400 million and a
development line of $100 million, which becomes available in
stages of $50 million by October 31, 2017 and $50 million by
April 30, 2018, subject to borrowing base review at those
-- Announced the planned expansion of Painted Ponys Montney
assets through the proposed UGR Acquisition, which will add
average daily production of 51 MMcfe/d (8,500 boe/d) based on
field estimates, Proved plus Probable reserves of 2.0 Tcfe
(325.1 MMboe), 108 net sections of land, and 105 MMcf/d of
owned natural gas processing capacity;
-- Generated net income for the first quarter of 2017 of $56.9
million compared to a net loss of $2.2 million in the first
quarter of 2016, and income before taxes of $8.6 million,
excluding the unrealized gain on commodity risk management
contracts, compared to a $1.3 million loss before taxes during
the first quarter of 2016;
-- Increased production by 116% to 215.3 MMcfe/d (35,878 boe/d),
in-line with previously released guidance, compared to 99.6
MMcfe/d (16,601 boe/d) during the first quarter of 2016;
-- Increased liquids production by 270% to 3,149 bbls/d or 9% of
total production volumes, compared to 852 bbls/d or 5% of total
production volumes in the first quarter of 2016;
-- Received an average natural gas price of $2.87/Mcf, which
represented a 7% premium to the AECO daily spot price, compared
to a 12% discount during the first quarter of 2016;
-- Increased funds flow from operations by 226% to $24.8 million
compared to $7.6 million during the first quarter of 2016;
-- Reduced operating costs by 30% to $0.62/Mcfe compared to
$0.88/Mcfe during the first quarter of 2016, and;
-- Decreased general and administrative ("G&A") expenses by 37% to
$0.17/Mcfe compared to $0.27/Mcfe during the first quarter of
-- On April 5, 2017 Painted Pony closed an equity financing
whereby the Corporation issued a total of 19,820,000 common
shares (the "Offering") in the capital of the Company ("Common
Shares") at a price of $5.60 per Common Share for net proceeds
of $106 million.
INCREASED CREDIT FACILITIESIn conjunction with the semi-annual borrowing base review, the Corporation has entered into an agreement to increase its credit facilities to $500 million, consisting of available credit facilities of $400 million and a development line of $100 million, conditional upon closing of the UGR Acquisition, expected to occur on or about May 16, 2017. Total credit facilities upon closing of the UGR Acquisition will consist of available credit facilities of $400 million and a development line of $100 million, which becomes available in stages of $50 million by October 31, 2017 and $50 million by April 30, 2018, subject to borrowing base review at those dates. In the event that the UGR Acquisition does not close, total credit facilities will be $350 million, with no development line.
UGR ACQUISITIONUpon closing, the UGR Acquisition will be a strategic expansion of Painted Pony's world-class Montney project in NEBC. The Corporation's Montney land position will increase by 52% to 314 net sections (201,009 net acres at an average 94% working interest) in one of the most productive areas of the Montney in British Columbia. Several of Painted Pony's most prolific Montney wells were drilled on the Daiber area lands that are either contiguous with UGR acreage or on lands held jointly with UGR. The UGR Acquisition includes 197 net Proved plus Probable drilling locations which will complement the Painted Pony inventory and are expected to drive near-term growth in the Corporation's proved developed producing reserves.
All Painted Pony shareholders are encouraged to refer to the management information circular of Painted Pony dated March 30, 2017 (the "Circular") for details regarding the UGR Acquisition, which was mailed to shareholders of record at the close of business on April 11, 2017. The Circular is also available under Painted Pony's profile on SEDAR (www.sedar.com) and on Painted Pony's website using the following link:
The Share Issuance Resolution will be considered at the upcoming annual general and special meeting of shareholders of Painted Pony to be held at 3:00 p.m. (MT, Calgary time) on Thursday, May 11, 2017 at the Ranchmen's Club, in the Bennett Room, at 710 - 13th Avenue S.W., Calgary, Alberta.
FIRST QUARTER 2017 FINANCIAL & OPERATING RESULTS
ProductionProduction volumes for the first quarter of 2017 of 215.3 MMcfe/d (35,878 boe/d) were in-line with previously released guidance and represented an increase of 116% compared to the first quarter of 2016 of 99.6 MMcfe/d (16,601 boe/d). Liquids production increased 270% to 3,149 bbls/d or 9% of total production volumes during the first quarter compared to 852 bbls/d or 5% of total production volumes during the first quarter of 2016. Liquids production during the first quarter of 2017 consisted of 45% condensate, 30% butane and 25% propane. Average daily production volumes during the first quarter of 2017 were reduced by approximately 7.2 MMcfe/d (1,200 boe/d) due to temporary shut-ins of producing wells off-setting completion operations. The increase in first quarter 2017 production volumes was driven by production additions from successful new drills in the Blair Creek, Townsend and Daiber areas, and the commissioning of the AltaGas Townsend natural gas processing plant ("Townsend Facility") in July 2016.
Capital Expenditures During the first quarter of 2017 Painted Pony invested $96.7 million in capital expenditures, compared to $67.1 million during the first quarter of 2016. A total of 7 wells were tied-in and brought on production during the first quarter of 2017. Capital expenditures for the first quarter of 2017 included $78.5 million to drill 18 (18.0 net) wells and complete 11 (11.0 net) wells as part of Painted Pony's capital program to fulfill current commitments at the Townsend Facility and pre-drills in anticipation of commissioning Townsend Phase 2, expected in late 2017. Facilities spending of $12.7 million included equipping costs, pipeline construction costs and spending on processing facilities. At the end of the first quarter 2017, Painted Pony had an inventory of 16 drilled uncompleted wells ("DUCs") and three completed wells awaiting flow back. Painted Pony believes both those wells awaiting flow back as well as the DUCs have a combined productive capacity of approximately 100 MMcfe/d (16,500 boe/d). This inventory of non-producing wells establishes a foundation from which Painted Pony expects significant production growth during the second half of 2017.
Painted Pony's pro forma 2017 capital program is expected to be $348 million. In 2017, pro forma, the Corporation intends to drill 71 net wells and complete 64 net Montney horizontal natural gas wells on its 100% working interest lands in the Townsend and Blair Creek areas.
PricingDuring the first quarter of 2017 Painted Pony realized a natural gas price of $2.87/Mcf which represented a 7% premium to the AECO daily spot price, compared to a 12% discount in the first quarter of 2016.
As part of Painted Pony's long-term sales point diversification strategy, effective October 1, 2016, Painted Pony began selling 45 MMcf/d of its production volumes directly into the AECO market, and effective November 1, 2016, began selling 18 MMcf/d of its production volumes into the SUMAS/Huntingdon market. For the remainder of 2017, Painted Pony entered into fixed price contracts for physical delivery of 58.0 to 68.0 MMcf/d priced at AECO less fixed differentials totaling $0.08 per Mcfe, when adjusted for AECO transportation charges.
For the first quarter of 2017 approximately 45% of Painted Pony's NGL volumes were condensate, which received an average price representing an 8% premium to the Edmonton light oil reference price.
Funds Flow From Operations and Net IncomePainted Pony's funds flow from operations for the first quarter of 2017 was $24.8 million or $0.25/share and represents an increase of 226% compared to the first quarter of 2016. Increased funds flow was the result of a 116% increase in production volumes and an 83% improvement in realized commodity prices compared to the first quarter of 2016. Painted Pony also realized an 8% decrease in combined per unit royalties, operating expenses and transportation costs for the first quarter of 2017 compared to the first quarter of 2016. Painted Pony's operating netback, after hedging, for the first quarter of 2017 increased 72% to $2.08 per Mcfe compared to first quarter of 2016, which equals 62% of total revenue of $3.35 per Mcfe.
Net income for the first quarter of 2017 was $56.9 million compared to a net loss of $2.2 million in the first quarter of 2016. Painted Pony generated income before taxes of $8.6 million, excluding the unrealized gain on commodity risk management contracts, compared to a $1.3 million loss before taxes during the first quarter of 2016.
Operating Expenses Painted Pony reduced operating expenses by 30% to $0.62/Mcfe ($3.72/boe) during the first quarter of 2017 compared to the first quarter of 2016 where operating expenses were $0.88/Mcfe ($5.28/boe). Per unit operating expenses for the first quarter of 2017 have improved as a result of higher production volumes driving down fixed costs per Mcfe. For the remainder of 2017, Painted Pony expects pro forma average per unit operating expenses of between $0.50 and $0.60/Mcfe, assuming normal seasonal weather conditions.
General and Administrative ExpensesG&A expenses for the first quarter of 2017 decreased by 37% to $0.17/Mcfe compared to the first quarter of 2016 G&A expenses of $0.27/Mcfe due to higher volumes quarter over quarter. For the second quarter of 2017, with anticipated transaction expenses related to the UGR acquisition, Painted Pony expects that pro forma per unit G&A expenses will average between $0.30 and $0.35/Mcfe. For the remainder of 2017, with significant pro forma production volumes expected to come on-stream, Painted Pony expects pro forma per unit G&A expenses will average approximately $0.10 to $0.15 per Mcfe.
Subsequent Event Painted Pony intends to use the total net proceeds of $106 million from the Offering (including the net proceeds realized from the exercise of the over-allotment option) to: (i) fund a portion of its 2017 and 2018 capital program in respect of the previously announced UGR Acquisition and for general corporate purposes; and (ii) if the Acquisition does not close, for the development of its assets and for general corporate purposes. In the interim, and to most efficiently use the net proceeds of the Offering, the Corporation intends to initially apply the total net proceeds of the Offering to reduce indebtedness under its credit facilities that has been incurred, principally, for the development of its assets and for general corporate purposes. An equivalent amount will then be redrawn under the Corporation's credit facilities, as and when required, to implement its capital program over 2017 and 2018 (including the development of the assets acquired pursuant to the Acquisition) or in the event the Acquisition is not completed, to develop the current portfolio of its gas and natural gas liquids assets.
OutlookPainted Pony expects pro forma production volumes during the second quarter of 2017 to average approximately 234 MMcfe/d (39,000 boe/d) to 246 MMcfe/d (41,000 boe/d), including the partial impact of UGR volumes.
Average pro forma production volumes for 2017 are expected to be approximately 290.0 MMcfe/d (48,400 boe/d), representing a 108% increase over full-year 2016 production volumes. The pro forma forecasted production increase is driven by the expected commissioning of Phase 2 of the Townsend Facility ("Townsend Phase 2") in late 2017, and increased production resulting from the acquisition of UGR. Subsequent to the commissioning of Townsend Phase 2, pro forma exit volumes for 2017 are expected to be between 438 MMcfe/d (73,000 boe/d) to 450 MMcfe/d (75,000 boe/d).
FINANCIAL AND OPERATING HIGHLIGHTS
Three months ended March
2017 2016 Change
---- ---- ------
Financial ($ millions, except per share and shares outstanding)
revenue(1) 64.9 16.6 291%
operations(2) 24.8 7.6 226%
Per share - basic(3) and
diluted(4) 0.25 0.08 213%
(loss) 56.9 (2.2) N/A
Per share - basic(3) 0.57 (0.02) N/A
Per share - diluted(4) 0.56 (0.02) N/A
expenditures 96.7 67.1 44%
(5) 74.2 26.0 185%
Bank debt 232.6 87.6 166%
Net debt (6) 299.8 137.2 119%
Total assets 1,406.2 857.9 64%
(millions) 100.2 100.0 -
(millions) 100.2 100.0 -
(millions) 101.0 100.0 1%
Daily production volumes
Natural gas (MMcf/d) 196.4 94.5 108%
Natural gas liquids (bbls/d) 3,149 852 270%
Total (MMcfe/d) 215.3 99.6 116%
Total (boe/d) 35,878 16,601 116%
Realized commodity prices
Natural gas ($/Mcf) 2.87 1.60 79%
Natural gas liquids ($/bbl) 50.30 36.26 39%
Total ($/Mcfe) 3.35 1.83 83%
($/Mcfe) (7) 2.08 1.21 72%
------------- ---- ---- ---
1. Before royalties.
2. Funds flow from operations and funds flow
from operations per share (basic and
diluted) are non-GAAP measures used to
represent cash flow from operating
activities before the effects of changes in
non-cash working capital, deferred share
unit expense and decommissioning
expenditures. Funds flow from operations
per share is calculated by dividing funds
flow from operations by the weighted average
number of basic or diluted shares
outstanding in the period. See "Non-GAAP
3. Basic per share information is calculated on
the basis of the weighted average number of
shares outstanding in the period.
4. Diluted per share information reflects the
potential dilutive effect of stock options.
5. Working capital deficiency is a non-GAAP
measure calculated as current assets less
current liabilities. See "Non-GAAP
6. Net debt is a non-GAAP measure calculated
as bank debt and working capital
deficiency, adjusted for the current
portion of fair value of risk management
contracts. See "Non-GAAP Measures". Net
debt does not include gross proceeds of
$111 million from the public offering that
closed on April 5, 2017.
7. Operating netbacks is a non-GAAP measure
calculated on a per unit basis as natural
gas and natural gas liquids revenues,
adjusted for realized gains or losses on
commodity risk management, less royalties,
operating expenses and transportation
costs. See "Non-GAAP Measures" and
Currency: All amounts referred to in this press release are stated in Canadian dollars unless otherwise specified.
Forward-Looking Information: This press release contains certain forward-looking information within the meaning of Canadian securities laws. Forward-looking information relates to future events or future performance and is based upon the Corporation's current internal expectations, estimates, projections, assumptions and beliefs. All information other than historical fact is forward-looking information. Words such as "plan", "expect", "intend", "believe", "anticipate", "estimate", "may", "will", "potential", "proposed" and other similar words that indicate events or conditions may occur are intended to identify forward-looking information. In particular, this press release contains forward looking information relating to the expected increase to the Corporation's credit facilities; the anticipated completion of the UGR Acquisition; an expectation of capital spending in 2017; an expectation of operating and G&A expenses for the remainder of 2017; an expectation of 2017 second quarter and exit production, including the partial impact of the UGR Acquisition; an expectation that the expansion to AltaGas Townsend Facility will be operational in the time frame anticipated.
Forward-looking information is based on certain expectations and assumptions including but not limited to future commodity prices, currency exchange rates interest rates, royalty rates and tax rates; the state of the economy and the exploration and production business; the economic and political environment in which the Corporation operates; the regulatory framework; anticipate timing and results of capital expenditures; the sufficiency of budgeted capital expenditures to carry out planned operations; operating, transportation, marketing and general and administrative costs; drilling success, production rates, future capital expenditures and the availability of labor and services. With respect to future wells, a key assumption is the validity of geological and technical interpretations performed by the Corporation's technical staff, which indicate that commercially economic volumes can be recovered from the Corporation's lands. Estimates as to average annual and exit production assume that no material unexpected outages occur in the infrastructure the Corporation relies upon to produce its wells, that existing wells continue to meet production expectations and that future wells scheduled to come on production in 2017 meet timing and production rate expectations.
Undue reliance should not be placed on forward-looking information, as there can be no assurance that the plans, intentions or expectations on which they are based will occur. Although the Corporation's management believes that the expectations in the forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct. As a consequence, actual results may differ materially from those anticipated.
Forward-looking information necessarily involves both known and unknown risks associated with oil and gas exploration, production, transportation and marketing. There are risks associated with the uncertainty of geological and technical data, operational risks, risks associated with drilling and completions, environmental risks, risks of the change in government regulation of the oil and gas industry, risks associated with competition from others for scarce resources and risks associated with general economic conditions affecting the Corporation's ability to access sufficient capital. Additional information on these and other risk factors that could affect operational or financial results are included in the Corporation's most recent Annual Information Form and in other reports filed with Canadian securities regulatory authorities.
Forward-looking information is based on estimates and opinions of management at the time the information is presented. The Corporation is not under any duty to update the forward-looking information after the date of this press release to revise such information to actual results or to changes in the Corporation's plans or expectations, except as required by applicable securities laws.
Any "financial outlook" contained in this press release, as such term is defined by applicable securities laws, is provided for the purpose of providing information about management's current expectations and plans relating to the future. Readers are cautioned that reliance on such information may not be appropriate for other purposes
Non-GAAP Measures: This press release makes reference to the terms "funds flow from operations", "funds flow from operations per share", "working capital deficiency", "operating netbacks", "netbacks", "cash flow", "net debt" and "net debt to cash flow", which do not have standardized meanings prescribed by GAAP and therefore may not be comparable with the calculation of similar measures presented by other issuers.
Management uses "funds flow from operations" and "cash flow" to analyze operating performance and considers funds flow from operations and cash flow to be key measures as they demonstrate the Corporation's ability to generate the cash necessary to fund future capital investment and to repay debt. "Funds flow from operations" denotes cash flow from operating activities before the effects of changes in non-cash working capital, deferred share unit expense and decommissioning expenditures. "Cash flow" is determined as gross natural gas and natural gas liquids revenues including realized gains on commodity risk management contracts, less the following: royalties, operating costs, transportation costs, general and administrative costs and finance expenses. "Funds flow from operations per share" is calculated using the basic and diluted weighted average number of shares for the period. These terms should not be considered an alternative to, or more meaningful than, cash flows from operating activities as determined in accordance with GAAP as an indicator of the Corporation's performance.
Management uses "working capital deficiency", "net debt" and "net debt to cash flow" as useful supplemental measures of the liquidity of the Corporation. Working capital deficiency is calculated as current assets less current liabilities. "Net debt" is calculated as bank debt plus working capital deficiency, adjusted for the current portion of fair value of risk management contracts. "Net debt to cash flow" is calculated as net debt and letters of credit divided by quarterly annualized cash flow. These terms should not be considered alternatives to, or more meaningful than, current and long-term debt as determined in accordance with GAAP.
"Operating netbacks" or "netbacks" is used as a supplemental measure of the Corporation's profitability relative to commodity prices. Operating netbacks or netbacks are calculated on a per unit basis as natural gas and natural gas liquids revenues, adjusted for realized gains or losses on commodity risk management, less royalties, operating expenses and transportation costs. These terms should not be considered alternatives to, or more meaningful than net income (loss) and comprehensive income (loss) as determined in accordance with GAAP.
Management of the Corporation believes these measures are useful supplemental measures of the net position of current assets and current liabilities of the Corporation and the profitability relative to commodity prices. Readers are cautioned, however, that these measures should not be construed as alternatives to other terms such as current and long-term debt or comprehensive income determined in accordance with GAAP as measures of performance. The Corporation's method of calculating these non- GAAP measures may differ from other companies, and accordingly, may not be comparable to similar measures used by other entities.
Certain Reserves Data Information: The securities regulatory authorities in Canada have adopted NI 51-101 (as defined herein), which imposes oil and gas disclosure standards for Canadian public issuers engaged in oil and gas activities. NI 51-101 permits oil and gas issuers, in their filings with Canadian securities regulatory authorities, to disclose proved, probable and possible reserves, and to disclose reserves and production on a gross basis before deducting royalties. Probable and possible reserves are progressively less certain estimates than proved reserves.
All reserves information in this press release are presented on a gross basis. Gross reserves are the total working interest reserves before the deduction of any royalties and including any royalty interests receivable. Reserves estimates set forth herein with respect to the Corporation are based on the independent engineering evaluation of Painted Pony's oil, natural gas liquids and natural gas reserves (the "GLJ Report") prepared by GLJ Petroleum Consultants Ltd. ("GLJ") effective December 31, 2016 and dated February 27, 2017, and reserves estimates set forth herein with respect to the Target are based on an independent engineering evaluation of the Target's oil, natural gas liquids and natural gas reserves (the "McDaniel Report") prepared by McDaniel & Associates Consultants Ltd. ("McDaniel") effective December 31, 2016 and dated February 6, 2017. Before tax net present values set forth herein are based on a 10 percent discount rate and GLJ's January 1, 2017 forecast prices or McDaniel's January 1, 2017 forecast prices, as applicable.
All estimates of future revenue in this press release and in the documents incorporated herein by reference are, unless otherwise noted, after the deduction of royalties, development costs, production costs and well abandonment costs but before deduction of future income tax expenses and before consideration of indirect costs such as administrative, overhead and other miscellaneous expenses. The estimated future net revenues contained in this press release and in the documents incorporated herein by reference do not represent the fair market value of the applicable reserves.
In this press release and the documents incorporated by reference herein:
(a) the discounted and undiscounted net
present value of future net
revenues attributable to reserves
do not represent the fair market
value of reserves;
(b) there is no assurance that the
forecast prices and costs
assumptions will be attained and
variances could be material. The
recovery and reserve estimates of
natural gas and liquids reserves
provided in this press release are
estimates only and there is no
guarantee that the estimated
reserves will be recovered. Actual
natural gas and liquids reserves
may be greater than or less than
the estimates provided in this
(c) the estimates of reserves and future
net revenue for individual
properties may not reflect the same
confidence level as estimates of
reserves and future net revenue for
all properties, due to the effects
(d) boe amounts may be misleading,
particularly if used in isolation.
Boe amounts have been calculated
using the conversion ratio of six
thousand cubic feet (6 Mcf) to one
barrel of oil (1 bbl). A
conversion ratio of 6 Mcf to 1 bbl
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; and
(e) Mcfe amounts may be misleading,
particularly if used in isolation.
Mcfe amounts have been calculated
by using the conversion ratio of 1
bbl to 6 Mcf. A conversion ratio
of 1 bbl to 6 Mcfs 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 1:6, utilizing a
conversion on a 1:6 basis may be
misleading as an indication of
Reserves are the estimated remaining quantities of conventional natural gas, shale gas and natural gas liquids anticipated to be recoverable from known accumulations, from a given date forward, based on: (i) analysis of drilling, geological, geophysical and engineering data; (ii) the use of established technology; and (iii) specified economic conditions which are generally accepted as reasonable.
Reserves are classified according to the degree of certainty associated with the estimates.
(a) Proved reserves are those reserves
that can be estimated with a high
degree of certainty to be
recoverable. It is likely that
the actual remaining quantities
recovered will exceed the
estimated proved reserves.
(b) Probable reserves are those
additional reserves that are less
certain to be recovered than
proved reserves. It is equally
likely that the actual remaining
quantities recovered will be
greater or less than the sum of
the estimated proved plus
Other criteria that must also be met for the categorization of reserves are provided in the Canadian Oil and Gas Evaluation ("COGE") Handbook.
Each of the reserves categories (proved and probable) may be divided into developed and undeveloped categories.
(a) Developed reserves are
those reserves that
are expected to be
existing wells and
or, if facilities have
not been installed,
that would involve a
low expenditure (for
example, when compared
to the cost of
drilling a well) to
put the reserves on
developed category may
be subdivided into
producing and non-
(i) Developed producing reserves
are those reserves that are
expected to be recovered from
completion intervals open at
the time of the estimate.
These reserves may be
currently producing or, if
shut-in, they must have
previously been on production,
and the date of resumption of
production must be known with
(ii) Developed non-producing
reserves are those reserves
that either have not been on
production, or have previously
been on production, but are
shut-in, and the date of
resumption of production is
(b) Undeveloped reserves
are those reserves
expected to be
recovered from known
accumulations where a
example, when compared
to the cost of
drilling a well) is
required to render
them capable of
production. They must
fully meet the
requirements of the
(proved, probable) to
which they are
In multi-well pools it may be appropriate to allocate total pool reserves between the developed and undeveloped categories or to subdivide the developed reserves for the pool between developed producing and developed non-producing. This allocation should be based on the estimator's assessment as to the reserves that will be recovered from specific wells, facilities and completion intervals in the pool and their respective development and production status.
Levels of Certainty for Reported Reserves: The qualitative certainty levels referred to in the definitions above are applicable to individual reserves entities (which refers to the lowest level at which reserves calculations are performed) and to reported reserves (which refers to the highest level sum of individual entity estimates for which reserve estimates are prepared). Reported reserves should target the following levels of certainty under a specific set of economic conditions:
(a) at least a 90 percent
probability that the
quantities actually recovered
will equal or exceed the
estimated proved reserves;
(b) at least a 50 percent
probability that the
quantities actually recovered
will equal or exceed the sum
of the estimated proved plus
A quantitative measure of the certainty levels pertaining to estimates prepared for the various reserves categories is desirable to provide a clearer understanding of the associated risks and uncertainties. However, the majority of reserves estimates will be prepared using deterministic methods that do not provide a mathematically derived quantitative measure of probability. In principle, there should be no difference between estimates prepared using probabilistic or deterministic methods.
Additional clarification of certainty levels associated with reserves estimates and the effect of aggregation is provided in the COGE Handbook.
For additional information regarding the presentation of Painted Pony's reserves and other oil and gas information, see Painted Pony's Form 51-101F1 (as defined herein), which is incorporated by reference in this press release.
ABOUT PAINTED PONY
Painted Pony is a publicly-traded natural gas corporation based in Western Canada. The Corporation is primarily focused on the development of natural gas and natural gas liquids from the Montney formation in northeast British Columbia. Painted Pony's common shares trade on the Toronto Stock Exchange under the symbol "PPY".
SOURCE Painted Pony Petroleum Ltd.
View original content: http://www.newswire.ca/en/releases/archive/May2017/10/c6450.html
SOURCE: Painted Pony Petroleum Ltd.
Patrick R. Ward, President and CEO, (403) 475-0440; John H. Van de Pol, Senior Vice
President and CFO, (403) 475-0440; Jason Fleury, Director, Investor Relations, (403)
776-3261, firstname.lastname@example.org, www.paintedpony.ca