CALGARY, ALBERTA -- (Marketwired) -- 02/23/17 -- BlackPearl Resources Inc. ("we", "our", "us", "BlackPearl" or the "Company") (TSX: PXX)(OMX: PXXS) is pleased to announce its financial and operating results for the three and twelve months ended December 31, 2016, the results of its 2016 year-end oil and gas reserves and resource evaluations and the commencement of construction of the Phase 2 thermal expansion at Onion Lake.
Highlights and accomplishments included:
-- Onion Lake is the cornerstone of the Company's current oil production.
The first phase of thermal development reached and exceeded its design
capacity of 6,000 barrels of oil per day (bbl/d) during the year with
operating costs under $10/bbl. During Q4 2016, production from the
project averaged 6,119 bbl/d. Our Board has sanctioned development of
the 6,000 bbl/d Phase 2 expansion of the project and we have commenced
construction. In addition, we have entered into a fixed price agreement
to fabricate the central processing facilities and pad facilities for
Phase 2. Total estimated capital costs for the project are between $180
and $185 million and the project is expected to be completed in mid-
2018.
-- During 2016, oil and gas production averaged 10,077 boe/day; a 21%
increase compared to 2015 and higher than full year guidance for the
year. The increase reflects the ramp-up of production from the Onion
Lake thermal project during the year. Q4 2016 oil and gas production
averaged 10,479 boe/day.
-- During the year debt was reduced from $88 million to nil; the Company
used its cash flow and proceeds from the sale of a royalty interest on
our Onion Lake property to eliminate debt by year-end.
-- At Blackrod, in 2016, we received regulatory approval for an 80,000
bbl/d SAGD development and the results from our successful pilot
continue to support the commerciality of this large resource. In 2016,
the pilot produced an average of 556 bbl/d, and cumulatively, has
produced in excess of 460,000 barrels of oil.
-- At Mooney, we were relatively quiet in 2016 as we shut-in a majority of
the ASP flood due to low oil prices. However, as a result of the recent
improvement in oil prices we re-initiated phase1 of the ASP flood. It
will likely take six to twelve months before we see the full impact on
production volumes from the re-start.
-- During the fourth quarter of 2016, the Company sold a gross overriding
royalty interest on its Onion Lake property for cash proceeds of $55
million whereby the Company will pay approximately 1.75% royalty on
production from substantially all of its Onion Lake lands.
-- Operating costs, on a per barrel of oil basis, dropped 38% in 2016 from
2015, which reflects the success of the Onion Lake thermal project as
well as cost cutting measures implemented in our other producing areas.
-- Q4 2016 revenue was $35 million and funds flow from operations (a non-
GAAP measure) was $16 million, up from Q4 2015 as a result of higher oil
prices. For the year, oil and gas revenue was $109 million and funds
flow from operations was $45 million.
-- Capital expenditures were $11 million in 2016 compared to $69 million in
2015. Reduced capital spending reflects lower oil prices and our desire
to maintain a strong balance sheet.
-- Proven plus probable reserves increased 6% in 2016 to 312 million
barrels. The increase represents a 377% replacement of 2016 production.
The increase is predominantly due to technical revisions and extensions
in our Onion Lake area assets.
-- Risked contingent resources (best estimate) for our three core
properties totaled 499 million barrels of oil equivalent, comparable to
2015 resource estimates.
John Festival, President of BlackPearl, commented that "The past two years have been very difficult due to low oil prices; however, we did more than just shut in production, cut costs and survive. We have managed the construction and start-up of a best in class thermal project at Onion Lake which has paved the way for additional phases. We have also been able to enter 2017 with no debt and the financial capacity to fund phase 2 of our Onion Lake thermal project. Building a successful thermal project was the result of learning from our pilots, careful project management and teaming up with experienced vendors. Surviving difficult financial circumstances was the result of discipline both in our hedging program and in our capital allocation. We intend to employ both these characteristics as prices improve as we continue to grow and build in our core areas. In 2017, we will allocate capital to drilling primary wells and bringing on shut in production, but most importantly, our focus will be on our 6,000 barrel per day phase 2 expansion at Onion Lake. We have signed a contract to build the facilities for phase 2 and expect to announce the remaining debt instruments shortly that are necessary to fully fund our capital program. We anticipate funding the remainder of the project with no additional equity dilution to shareholders. Long life, low decline production will be the bedrock of our company as we look to the future, which will include the funding and construction of our Blackrod oil sands project. In addition, 2016 was a significant milestone for Blackrod as we received regulatory and environmental approval for an 80,000 bbl/d commercial development."
Financial and Operating Highlights
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Three months ended Twelve months ended
December 31, December 31,
2016 2015 2016 2015
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Daily sales volumes
Oil (bbls/d) 9,853 8,785 9,391 7,434
Bitumen (bbls/d) (1) 523 562 556 541
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Combined (bbls/d) 10,376 9,347 9,947 7,975
Natural gas (mcf/d) 620 1,047 781 2,130
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Combined (boe/d) (2) 10,479 9,521 10,077 8,330
Product pricing ($)
Crude oil - per bbl 38,.83 27.65 31.57 35.00
Natural gas - per mcf 2.90 2.91 1.95 2.72
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Combined - per boe (2) 38.61 27.45 31.30 34.14
Realized gains on risk
management contracts - per
boe 0.63 12.54 3.10 13.20
($000s, except where noted)
Oil and natural gas revenue -
gross 35,360 22,630 109,066 96,271
Net income (loss) for the period (2,217) (31,172) (19,928) (46,793)
Per share, basic ($) (0.01) (0.09) (0.06) (0.14)
Per share, diluted ($) (0.01) (0.09) (0.06) (0.14)
Cash flow from operating
activities (3) 15,079 12,179 42,491 62,344
Funds flow from operations (4) 15,798 10,898 44,775 48,962
Capital expenditures 6,150 1,665 10,925 68,508
Working capital deficiency
(surplus), end of period 4,995 (11,063) 4,995 (11,063)
Long term debt - 88,000 - 88,000
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Net Debt (5) 4,995 76,937 4,995 76,937
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Shares outstanding, end of
period (000s) 335,949 335,638 335,949 335,638
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(1) Includes production from the Blackrod SAGD pilot. All sales and
expenses from the Blackrod SAGD pilot are being recorded as an
adjustment to the capitalized costs of the project until the technical
feasibility and commercial viability of the project is established.
(2) Boe is based on a conversion ratio of 6 mcf of natural gas to 1 bbl of
oil. Boe may be misleading, particularly if used in isolation. A boe
conversion ratio of 6 mcf: 1 bbl is based on an energy equivalency
conversion method primarily applicable at the burner tip and is not
intended to represent a value equivalency at the wellhead.
(3) Cash flow from operating activities is a GAAP measure and has a
standardized meaning prescribed by Canadian GAAP.
(4) Funds flow from operations is a non-GAAP measure (as defined herein)
that represents cash flow from operating activities before
decommissioning costs incurred and changes in non-cash working capital
related to operations. Funds flow from operations does not have
standardized meanings prescribed by Canadian generally accepted
accounting principles ("GAAP") and therefore may not be comparable to
similar measures used by other companies. Management utilizes funds
flow from operations as a key measure to assess operating performance
and the ability of the Company to finance operating activities, capital
expenditures and debt repayments. Funds flow from operations is not
intended to represent cash flow from operating activities or other
measures of financial performance in accordance with GAAP.
(5) Net debt is a non-GAAP measure. Net debt does not have a standardized
meaning prescribed by GAAP and, therefore, may not be comparable to
similar measures used by other companies in the oil and gas industry.
FOURTH QUARTER 2016 ACTIVITIES
Oil and natural gas sales increased 56% in the fourth quarter of 2016 to $35.4 million from $22.6 million in the same period in 2015. The increase in oil and gas sales is attributable to a 41% increase in average sales price received in the fourth quarter of 2016 and a 10% increase in production volumes (on a boe basis). WTI oil prices averaged US$49.29 per barrel in Q4 2016 compared to US$42.18 per barrel in Q4 2015. Higher WTI oil prices combined with comparable heavy oil differentials and a weaker Canadian dollar relative to the US dollar resulted in our wellhead price averaging $38.83 per barrel in the fourth quarter of 2016 compared with $27.65 per barrel in the fourth quarter of 2015.
BlackPearl sold an average of 10,479 boe/day during the fourth quarter of 2016 compared with 9,521 boe/day during the fourth quarter of 2015. Higher production in the fourth quarter of 2016 primarily reflects an increase in production from our Onion Lake thermal project. During the fourth quarter the thermal project produced 6,119 barrels of oil per day.
Production costs were $11.1 million or $12.11 per boe in the fourth quarter of 2016 compared to $14.7 million or $17.77 per boe in the fourth quarter of 2015. The decrease in per unit operating costs is mainly attributable to lower costs related to our Onion Lake thermal project. General and administrative expenses were $1.6 million in the fourth quarter of 2016 compared to $1.8 million in the fourth quarter of 2015.
During the fourth quarter, the Company sold a gross overriding royalty interest on its Onion Lake property for cash proceeds of $55 million whereby the Company will pay an approximate 1.75% royalty on production from substantially all of its Onion Lake lands.
During the year debt was reduced from $88 million to nil at the end of 2016. The Company used a significant portion of its cash flow and the proceeds from the royalty sale to reduce its debt in 2016.
Funds flow from operations in the fourth quarter of 2016 was $15.8 million compared to $10.9 million in the fourth quarter of 2015. The increase reflects higher revenues in Q4 2016, partially offset by lower realized gains on risk management contracts. Net loss in the fourth quarter of 2016 was $2.2 million compared to a net loss of $31.2 million in the fourth quarter of 2015. The decrease in net loss in Q4 2016 is primarily a result of no impairment losses recognized during 2016 compared to an impairment charge of $33 million recorded in 2015.
Capital spending was $6.2 million during the quarter compared with $1.7 million in Q4 2015.
Production
BlackPearl's Q4 2016 oil and gas sales volumes were 10,479 boe per day, a 10% increase over production during the same period in 2015. The increase in fourth quarter production is attributable to the Onion Lake thermal project.
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Three months ended Twelve months ended
December 31, December 31,
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Production by Area (boe/d) 2016 2015 2016 2015
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Onion Lake - thermal 6,119 3,010 5,520 951
Onion Lake - conventional 2,011 2,914 2,135 3,312
Mooney 785 1,902 801 2,367
John Lake 837 955 863 989
Blackrod SAGD Pilot 523 562 556 541
Other 204 178 202 170
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Total production 10,479 9,521 10,077 8,330
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Operating Netback
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Three months ended Twelve months ended
December 31, December 31,
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($/boe) 2016 2015 2016 2015
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Oil and natural gas revenue 38.61 27.45 31.30 34.14
Realized gains on risk management
contracts 0.63 12.54 3.10 13.20
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39.24 39.99 34.40 47.34
Royalties 4.93 4.38 3.96 5.74
Transportation costs 2.69 1.23 2.24 1.13
Production costs 12.11 17.77 12.44 19.94
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Operating netback(1) 19.51 16.61 15.76 20.53
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(1) Operating netback is a non-GAAP measure. Operating netback does not
have a standardized meaning prescribed by GAAP and, therefore, may not
be comparable to similar measures used by other companies in the oil
and gas industry.
Hedging Position
Periodically we will enter into risk management contracts in order to ensure a certain level of cash flow to fund planned capital projects. The table below summarizes the Company's current risk management contracts:
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Subject Volume Term Reference Strike Price Option
of Traded
Contract
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2017
Oil 500 bbls/d January 1 to CDN$ WCS (1) CDN$ 52.75/bbl Swap
December 31
Oil 500 bbls/d February 1 CDN$ WCS (1) CDN$ 54.30/bbl Swap
to December
31
Oil 500 bbls/d February 1 US$ WCS (1) US$ 40.15/bbl Swap
to December
31
Oil 1,000 bbls/d January 1 to CDN$ WCS (1) CDN$ 50.00/bbl Swap
December 31
Oil 1,000 bbls/d January 1 to CDN$ WCS (1) CDN$ 49.50/bbl Swap
December 31
Oil 500 bbls/d January 1 to CDN$ WCS (1) CDN$ 40.00/bbl Collar
June 30 to 52.50/bbl
Oil 500 bbls/d January 1 to CDN$ WCS (1) CDN$ 40.00/bbl Collar
June 30 to 47.00/bbl
Oil 1,000 bbls/d January 1 to US$ WTI (2) US$ 60.00/bbl Sold Call
December 31
2018
Oil 500 bbls/d January 1 to US$ WTI (2) US$ 70.00/bbl Sold Call
December 31
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(1) WCS refers to Western Canadian Select, a heavy oil reference price in
Alberta
(2) WTI refers to West Texas Intermediate, a light oil reference price in
Cushing Oklahoma
2017 Outlook - Initial Guidance
Capital spending in 2017 will be approximately $200 million, with expansion of the Onion Lake thermal project our main focus. We have begun preliminary spending on planning and long lead items for the project with a target completion date of mid-2018. In addition to the expansion of the Onion Lake thermal project, we also plan to resume drilling on some of our conventional heavy oil projects at John Lake, Onion Lake and other minor project areas, as well as continuing to operate the Blackrod SAGD pilot.
We are planning to fund a significant portion of the capital costs of the Onion Lake expansion with our funds flow from operations, which we are budgeting to be between $65 and $70 million in 2017, and our undrawn credit facilities. We are looking to supplement these sources with $75 to $100 million of additional term debt financing to provide us with financial flexibility during the construction phase. In the event that we are unable to obtain additional financing we will reduce capital spending on our conventional heavy oil projects. Year-end debt is expected to be between $135 and $140 million.
Oil and gas production is expected to average between 10,000 and 11,000 boe/d in 2017. This will include bringing back some of our shut-in production at Onion Lake as well as reactivating phase one of the ASP flood at Mooney.
The initial guidance is based on a WTI oil price of US$54.50/bbl, a heavy oil differential of US$14.75/bbl and a Cdn/US dollar exchange rate of 0.75.
Oil and Gas Reserves
The following tables summarize certain information contained in the independent reserves report prepared by Sproule Unconventional Limited ("Sproule") as of December 31, 2016. The report was prepared in accordance with definitions, 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 reserve information as required under NI 51-101 has been included in the Company's Annual Information Form which has been filed on SEDAR. It should not be assumed that the net present value of reserves estimated by Sproule represents the fair market value of these reserves.
Summary of Oil and Gas Reserves
(Company interest, before Heavy Natural 2016 2015
royalties) Crude Oil Bitumen Gas Total Total
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(Mbbl) (Mbbl) (MMcf) (MBoe) (MBoe)
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Proved developed producing 18,461 628 216 19,125 19,907
Proved developed non-
producing 3,400 0 169 3,428 2,673
Proved undeveloped 53,399 429 71 53,840 41,376
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Total proved 75,260 1,057 456 76,393 63,956
Probable 56,374 178,742 421 235,186 230,010
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Total proved plus probable 131,634 179,799 877 311,579 293,966
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Notes:
(1) BOEs may be misleading, particularly if used in isolation. In accordance with NI 51-101, a BOE conversion ratio of 6 Mcf: 1 barrel is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
(2) Columns may not add due to rounding.
Net Present Value of Reserves
($000s) 0% 5% 10% 15% 20% ---------------------------------------------------------------------------- Before Tax Proved Developed producing 459,650 409,646 364,468 326,303 294,658 Developed non- producing 57,041 44,809 35,721 28,902 23,723 Undeveloped 1,436,295 660,090 335,306 184,234 106,443 ---------------------------------------------------------------------------- Total proved 1,952,986 1,114,545 735,495 539,439 424,824 Probable 6,101,866 2,705,896 1,319,121 681,908 358,751 ---------------------------------------------------------------------------- Total proved plus probable 8,054,852 3,820,441 2,054,616 1,221,347 783,575 ---------------------------------------------------------------------------- ---------------------------------------------------------------------------- After Tax Proved Developed producing 459,650 409,646 364,468 326,303 294,658 Developed non- producing 57,041 44,809 35,721 28,902 23,723 Undeveloped 1,064,317 492,031 250,036 136,658 77,834 ---------------------------------------------------------------------------- Total proved 1,581,008 946,486 650,225 491,863 396,215 Probable 4,418,620 1,928,767 910,614 445,040 210,965 ---------------------------------------------------------------------------- Total proved plus probable 5,999,628 2,875,253 1,560,839 936,903 607,180 ---------------------------------------------------------------------------- ----------------------------------------------------------------------------
Notes:
(1) Based on Sproule's December 31, 2016 forecast prices.
(2) Columns may not add due to rounding.
Estimated Future Development Capital
The following table summarizes the future development capital ("FDC") Sproule estimates is required to bring total proved and total proved plus probable reserves on production.
($ Millions) Total Proved Total Proved + Probable ---------------------------------------------------------------------------- 2017 47.6 183.9 2018 25.4 91.1 2019 26.3 50.4 2020 11.5 86.6 2021 55.8 357.2 Remainder 465.5 1,927.0 ---------------------------------------------------------------------------- Total FDC undiscounted 632.1 2,696.2 Total FDC discounted at 10% 246.0 1,160.1 ---------------------------------------------------------------------------- ----------------------------------------------------------------------------
Reconciliation of Changes in Reserves
The following table summarizes the changes in Sproule's evaluation of the Company's share of oil and natural gas reserves (before royalties) from December 31, 2015 to December 31, 2016.
Heavy Natural
Crude Oil Bitumen Gas BOE
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(Mbbl) (Mbbl) (MMcf) (MBOE)
Proved
Balance, Dec 31, 2015 63,446 429 487 63,956
Extensions and improved recovery 9,388 0 0 9,388
Technical revisions 6,144 930 322 7,128
Economic factors (281) (98) (67) (390)
Production (3,437) (204) (286) (3,689)
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Balance, Dec 31, 2016 75,260 1,057 456 76,393
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Probable
Balance, Dec 31, 2015 50,612 179,338 363 230,010
Extensions and improved recovery 6,901 0 0 6,901
Technical revisions (1,177) (299) 35 (1,470)
Economic factors 38 (297) 23 (255)
Production 0 0 0 0
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Balance, Dec 31, 2016 56,374 178,742 421 235,187
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Proved plus Probable
Balance, Dec 31, 2015 114,058 179,767 850 293,966
Extensions and improved recovery 16,289 0 0 16,289
Technical revisions 4,967 631 357 5,658
Economic factors (243) (395) (44) (645)
Production (3,437) (204) (286) (3,689)
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Balance, Dec 31, 2016 131,634 179,799 877 311,579
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Note:
(1) Columns may not add due to rounding
The pricing assumptions used in the Sproule evaluation are summarized below.
Pricing Assumptions
Canadian Western
WTI Light Sweet Canadian
Cushing Crude Select Alberta
40 degrees 40 degrees 20.5 degrees AECO-C Inflation Exchange
Year API API API Spot rate rate
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(US$/bbl) (CDN$/bbl) (CDN$/bbl) (CDN$/MMBtu) (%/yr) (US$/Cdn$)
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2017 55.00 65.58 53.12 3.44 0.0 0.78
2018 65.00 74.51 61.85 3.27 2.0 0.82
2019 70.00 78.24 64.94 3.22 2.0 0.85
2020 71.40 80.64 66.93 3.91 2.0 0.85
2021 72.83 82.25 68.27 4.00 2.0 0.85
2022 74.28 83.90 69.64 4.10 2.0 0.85
2023 75.77 85.58 71.03 4.19 2.0 0.85
2024 77.29 87.29 72.45 4.29 2.0 0.85
2025 78.83 89.03 73.90 4.40 2.0 0.85
2026 80.41 90.81 75.38 4.50 2.0 0.85
2027 82.02 92.63 76.88 4.61 2.0 0.85
Escalation rate of 2.0% thereafter
Notes:
(1) The pricing assumptions were provided by Sproule.
(2) None of the Company's future production is subject to a fixed or contractually committed price.
Definitions:
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 probable reserves.
c. "Developed" reserves are those reserves that are expected to be
recovered from existing wells and installed facilities or, if facilities
have not been installed, that would involve a low expenditure (e.g. when
compared to the cost of drilling a well) to put the reserves on
production.
d. "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 reasonable certainty.
e. "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 unknown.
f. "Undeveloped" reserves are those reserves expected to be recovered from
known accumulations where a significant expenditure (for 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
reserves classification (proved, probable, possible) to which they are
assigned.
g. The Net Present Value (NPV) is based on Sproule forecast pricing and
costs. The estimated NPV does not necessarily represent the fair market
value of our reserves. There is no assurance that forecast prices and
costs assumed in the Sproule evaluations will be attained, and variances
could be material.
Contingent Resources
The following tables summarize certain information contained in the contingent resource evaluations prepared by Sproule as of December 31, 2016. The reports were independently prepared in accordance with definitions, standards and procedures contained in the COGE Handbook.
It should not be assumed that the estimates of recovery, production, and net revenue presented in the tables below represent the fair market value of the Company's contingent resources. There are certain contingencies which currently prevent the classification of these contingent resources as reserves. Information on these contingencies is provided in the footnotes to the tables below. There is no certainty that it will be commercially viable to produce any portion of the contingent resources. Please refer to our Annual Information Form for a more detailed discussion of our contingent resources.
An estimate of risked net present value of contingent resources is preliminary in nature and is provided to assist the reader in reaching an opinion on the merit and likelihood of the Company proceeding with the required investment. It includes contingent resources that are considered too uncertain with respect to the chance of development to be classified as reserves. There is uncertainty that the risked net present value of future net revenue will be realized.
Summary of Best Estimate (P50) Contingent Resource Volumes - By Property (1)(2)
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Risked Volumes(4)
----------------------------------
Heavy Crude Oil Bitumen
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Maturity Chance of
Project Subclass(3) Development(4) Gross(5) Net Gross(5) Net
----------------------------------------------------------------------------
(Mbbl) (Mbbl)
Blackrod (6) Development/ 80% 0 0 452,908 370,479
pending
Onion Lake Development/ 90% 35,101 27,807 0 0
(7) pending
Mooney (8) Development/ 71% 11,154 9,731 0 0
on hold
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Unrisked Volumes
----------------------------------
Heavy Crude Oil Bitumen
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Maturity Chance of
Project Subclass(3) Development(4) Gross(5) Net Gross(5) Net
----------------------------------------------------------------------------
(Mbbl) (Mbbl)
Blackrod (6) Development/ 80% 0 0 566,135 463,099
pending
Onion Lake Development/ 90% 39,001 30,897 0 0
(7) pending
Mooney (8) Development/ 71% 15,709 13,705 0 0
on hold
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NPV of Best Estimate (P50) Contingent Resource Volumes - By Property
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Net Present Values of Future Net Revenue Before Income
Taxes
-------------------------------------------------------
Discounted at (%/year)
-------------------------------------------------------
0% 5% 10% 15% 20%
-------------------------------------------------------
Project ($M)
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Risked Volumes (4)
Blackrod 9,494,445 2,825,717 851,304 212,292 -4,585
Onion Lake 1,118,061 411,066 171,668 79,826 40,034
Mooney 335,947 160,233 79,854 40,897 21,121
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Unrisked Volumes
Blackrod 11,868,057 3,532,146 1,064,131 265,366 -5,731
Onion Lake 1,242,290 456,740 190,742 88,695 44,482
Mooney 473,165 225,681 112,471 57,602 29,749
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Net Present Values of Future Net Revenue After Income
Taxes (10)
-------------------------------------------------------
Discounted at (%/year)
-------------------------------------------------------
0% 5% 10% 15% 20%
-------------------------------------------------------
Project ($M)
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Risked Volumes (4)
Blackrod 6,817,151 1,943,718 514,839 67,498 -73,076
Onion Lake 806,412 291,145 117,894 52,154 24,118
Mooney 244,534 114,986 55,964 27,593 13,372
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Unrisked Volumes
Blackrod 8,521,438 2,429,647 643,549 84,373 -91,345
Onion Lake 896,013 323,495 130,993 57,949 26,798
Mooney 344,414 161,953 78,823 38,863 18,834
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Notes:
(1) Contingent Resources are defined in the COGE Handbook as 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 are not currently
considered to be commercially recoverable due to one or more
contingencies. Contingencies may include factors such 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.
(2) There are three classifications of contingent resources: Low Estimate,
Best Estimate and High Estimate. Best estimate (P50) is a
classification of estimated resources described in the COGE Handbook
as being considered to be the best estimate of the quantity that will
be actually 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%
probability that the quantities actually recovered will equal or
exceed the best estimate.
(3) Contingent resources are further classified based on project maturity.
The project maturity subclasses include development pending,
development on hold, development unclarified and development not
viable. All of the Company's contingent resources are classified as
either development pending or development on hold:
(a) Development pending is where resolution of the final conditions of
development are being actively pursued, indicating there is a high
chance of development.
(b) Development on hold is where there is a reasonable chance of
development, but there are major non-technical contingencies to be
resolved that are usually beyond the control of the operator.
(4) Chance of Development is defined as the probability of a project being
commercially viable. Sproule's estimate of unrisked contingent
resources have been adjusted for risk based on the chance of
development (risked amounts represent unrisked values multiplied by
the Chance of Development).
(5) "Gross" means the Company's working interest share in the contingent
resources of bitumen and heavy oil before deducting royalties. The
Company has a 100% working interest at Blackrod and Mooney, and a 50
to 100% working interest at Onion Lake.
(6) The established recovery technology to be used in phases 3 and 4 of
the Blackrod project is the SAGD process, the same process that is
being used in the successful pilot that is currently being conducted
within the Blackrod reservoir. The contingencies in the Sproule Report
associated with the Company's Blackrod contingent resources are due to
the following: (a) the requirement for more evaluation drilling, as
required by the regulatory process, to define the reservoir
characteristics to assist in the implementation and operation of the
SAGD process; (b) the absence of submission of an application to
expand the commercial SAGD development beyond the phase 2 project
area; (c) the absence of corporate commitment related to the final
investment decision and endorsement from the Board of Directors of the
Company to move forward with commercial development of Phases 3 and 4
of the Blackrod project; and (d) the uncertainty of timing of
production and development of Phases 3 and 4 of the Blackrod project.
For the Blackrod project contingent resources, the estimated timing of
first commercial production is 2025 and the estimated capital to reach
first commercial production is $0.97 billion (unrisked and unescalated
for inflation).
(7) The recovery of the Company's Onion Lake contingent resources will use
a combination of production processes: the established modified SAGD
process for phase 3 of the Onion Lake thermal project, the same
process that is already utilized commercially in phase 1 of the Onion
Lake thermal project; and the established cold heavy oil production
with sand (CHOPS) process to extend the primary development area, the
same CHOPS process that has already been extensively deployed
throughout the field.
- For phase 3 of the Onion Lake thermal project, the contingencies
in the Sproule Report associated with the Company's Onion Lake
contingent resources are due to the following: (a) the requirement
for more evaluation drilling to define the reservoir
characteristics to assist in the implementation and operation of
the modified SAGD recovery process; and (b) the absence of an
agreement between the Company and OLCN/OLE for thermal EOR
development in the lands currently leased by the Company but
outside the thermal EOR development area, the thermal EOR volumes
assigned to these lands were classified as contingent resources.
In addition, an application to expand the commercial modified SAGD
development beyond the existing OLCN/OLE approved thermal EOR
development area and facility capacities has not been submitted by
the Company. It is expected that as the Company nears a final
development decision for developing additional acreage, OLCN/OLE
agreements will be affirmed and further expansion applications
will be submitted, at which point this contingency would be
lifted. For the Onion Lake thermal project contingent resources,
the estimated timing of first commercial production is 2022, while
the estimated capital to reach first commercial production is
$48.4 million (unrisked and unescalated for inflation).
- For the extension of the primary development area, the
contingencies in the Sproule Report associated with the Company's
Onion Lake contingent resources are due to the following: (a) the
requirement for more evaluation drilling to confirm the geological
continuity of the reservoir and reduce the distance from proven
productivity; and (b) the potential for the current agreements
with the Onion Lake Cree Nation (OLCN), which are subject to
policies and approvals by Indian Oil and Gas Canada (IOGC),
required to be renegotiated due to changes imposed by IOGC. First
commercial production for the primary development area has already
been achieved and, as a result, estimated capital to reach first
commercial production is nil.
(8) The established recovery technology to be used for phases 3 and 4 of
the Mooney project is the established ASP flood process, the same
process that is already deployed commercially in phase 1 of the Mooney
field. The contingencies in the Sproule Report associated with the
Company's Mooney contingent resources are due to the following: (a)
the requirement for more evaluation wells to confirm the reservoir
characteristics needed for the ASP process; (b) the absence of
regulatory approvals to expand the ASP development area beyond the
phase 1 and phase 2 project areas; (c) the absence of a final
investment decision from the Board of Directors of the Company to move
forward with the ASP flood expansion to phases 3 and 4 of the Mooney
project and (d) the uncertainty of timing of production and
development of phases 3 and 4 of the Mooney project. First commercial
production for the Mooney ASP flood has already been achieved and, as
a result, estimated capital to reach first commercial production at
the Mooney ASP flood is nil.
(9) The amounts included in these tables do not include the volume or net
present value of the Company's proved plus probable reserves
previously assigned by Sproule to these properties.
(10) The after-tax net present value of the Company's contingent resources
reflects the tax burden on the properties on a stand-alone basis. It
does not consider the business-entity-level tax situation, or tax
planning. It does not provide an estimate of the value at the level of
the business entity, which may be significantly different. The
financial statements and the management's discussion & analysis of the
Company should be consulted for information at the level of the
business entity.
Other
The Company's financial statements, notes to the financial statements, management's discussion and analysis and Annual Information Form have been filed on SEDAR (www.sedar.com) and are available on the Company's website (www.blackpearlresources.ca). The Annual Information Form includes the Company's reserves and resource data for the period ended December 31, 2016 as evaluated by Sproule and other oil and natural gas information prepared in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities. BlackPearl's annual meeting of shareholders will be held on May 4, 2017 in Calgary, Alberta.
Forward-Looking Statements
This release contains certain forward-looking statements and forward-looking information (collectively referred to as "forward-looking statements") within the meaning of applicable Canadian securities laws. All statements other than statements of historic fact are forward-looking statements. Forward-looking statements are typically identified by such words as "seek", "anticipate", "plan", "continue", "estimate", "expect", "may", "will", "project", "potential", "targeting", "intend", "could", "might", "should", "believe" or similar words suggesting future events or future performance.
In particular, this release contains forward-looking statements pertaining to the estimated capital costs of between $180 to $185 million to construct phase 2 of the Onion Lake thermal project and the estimated mid-2018 completion date, estimated timing to see the full impact on production of the re-initiation of the ASP flood at Mooney, anticipated debt funding for the Phase 2 thermal expansion at Onion Lake with no additional equity dilution to fund the expansion, estimated volumes and net present values of BlackPearl's proved and probable reserves and contingent resources and all the information under 2017 Outlook - Initial Guidance.
The forward-looking information is based on, among other things, expectations and assumptions by management regarding its future growth, future production levels, future oil and natural gas prices, continuation of existing tax, royalty and regulatory regimes, foreign exchange rates, estimates of future operating costs, timing and amount of capital expenditures, performance of existing and future wells, recoverability of the Company's reserves and contingent resources, the ability to obtain financing on acceptable terms, availability of skilled labour and drilling and related equipment on a timely and cost efficient basis, general economic and financial market conditions, environment matters and the ability to market oil and natural gas successfully to current and new customers. Although management considers these assumptions to be reasonable based on information currently available to it, they may prove to be incorrect.
By their nature, forward-looking statements involve numerous known and unknown risks and uncertainties that contribute to the possibility that actual results will differ from those anticipated in the forward looking statements. These risks include, but are not limited to, risks associated with fluctuations in market prices for crude oil, natural gas and diluent, general economic, market and business conditions, volatility of commodity inputs, substantial capital requirements, conditions including receipt of necessary regulatory and stock exchange approvals with respect to the issuance of common shares, uncertainties inherent in estimating quantities of reserves and resources, extent of, and cost of compliance with, government laws and regulations and the effect of changes in such laws and regulations from time to time, the need to obtain regulatory approvals on projects before development commences, environmental risks and hazards and the cost of compliance with environmental regulations, aboriginal claims, inherent risks and hazards with operations such as fire, explosion, blowouts, mechanical or pipe failure, cratering, oil spills, vandalism and other dangerous conditions, financial loss associated with derivative risk management contracts, potential cost overruns, variations in foreign exchange rates, variations in interest rates, diluent and water supply shortages, competition for capital, equipment, new leases, pipeline capacity and skilled personnel, uncertainties inherent in the SAGD bitumen and ASP recovery process, credit risks associated with counterparties, the failure of the Company or the holder of licences, leases and permits to meet requirements of such licences, leases and permits, reliance on third parties for pipelines and other infrastructure, changes in royalty regimes, failure to accurately estimate abandonment and reclamation costs, inaccurate estimates and assumptions by management, effectiveness of internal controls, the potential lack of available drilling equipment and other restrictions, failure to obtain or keep key personnel, title deficiencies with the Company's assets, geo-political risks, risks that the Company does not have adequate insurance coverage, risk of litigation and risks arising from future acquisition activities. Readers are also cautioned that the foregoing list of factors is not exhaustive. Further information regarding these risk factors may be found under "Risk Factors" in the Annual Information Form.
Undue reliance should not be placed on these forward-looking statements. There can be no assurance that the plans, intentions or expectations upon which forward-looking statements are based will be realized. Actual results will differ, and the differences may be material and adverse to the Company and its shareholders. Furthermore, the forward-looking statements contained in this release are made as of the date hereof, and the Company does not undertake any obligation, except as required by applicable securities legislation, to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained herein are expressly qualified by this cautionary statement.
Non-GAAP Measures
Throughout this release, the Company uses terms "funds flow from operations", "operating netback" and "net debt". These terms do not have any standardized meaning as prescribed by GAAP and, therefore, may not be comparable with the calculation of similar measures presented by other issuers.
Funds flow from operations is calculated based on cash flow from operating activities before decommissioning costs incurred and changes in non-cash working capital related to operations. Management utilizes funds flow from operations as a key measure to assess operating performance and the ability of the Company to finance operating activities, capital expenditures and debt repayments. Funds flow from operations is not intended to represent cash flow from operating activities or other measures of financial performance in accordance with GAAP. The following table reconciles non-GAAP measure funds flow from operations to cash flow from operating activities, the nearest GAAP measure.
Three months ended Twelve months ended
December 31, December 31,
------------------------------------------
($000s) 2016 2015 2016 2015
------------------------------------------
Cash flow from operating
activities 15,079 12,179 42,491 62,344
Add (deduct):
Decommissioning costs incurred 26 152 580 531
Changes in non-cash working
capital related to operations 693 (1,433) 1,704 (13,913)
------------------------------------------
Funds flow from operations 15,798 10,898 44,775 48,962
------------------------------------------
Operating netback is calculated as oil and gas revenues less royalties, production costs and transportation costs on a dollar basis and divided by total production for the period on a boe basis. Oil and gas revenues exclude the impact of realized gains on risk management contracts. Operating netback is a non-GAAP measure commonly used in the oil and gas industry to assist in measuring operating performance against prior periods on a comparable basis. Our operating netback calculation is consistent with the definition found in the Canadian Oil and Gas Evaluation (COGE) Handbook.
Net debt is calculated as long-term debt plus working capital for the period ended. Working capital consists of cash and cash equivalents, trade and other receivables, inventory, prepaid expenses and deposits, fair value of risk management assets less accounts payable and accrued liabilities, current portion of decommissioning liabilities, deferred consideration and fair value of risk management liabilities. Management utilizes net debt as a key measure to assess the liquidity of the Company.
The information in this release is subject to the disclosure requirements of the Company under the EU Market Abuse Regulation and the Swedish Securities Markets Act. The information was publicly communicated on February 23, 2017 at 3:00 p.m. Mountain Time.
Contacts:
BlackPearl Resources Inc.
John Festival
President and Chief Executive Officer
(403) 215-8313
BlackPearl Resources Inc.
Don Cook
Chief Financial Officer
(403) 215-8313
www.blackpearlresources.ca
Robert Eriksson
Investor Relations Sweden
+46 8 545 015 50
