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Marketwired
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BlackPearl Announces Fourth Quarter and Full Year 2016 Financial and Operating Results and Year-End Reserves and Resources, Work Commences on Phase 2 Thermal Expansion at Onion Lake

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

----------------------------------------------------------------------------
                                  Three months ended   Twelve months ended
                                     December 31,          December 31,
                                      2016       2015       2016       2015
----------------------------------------------------------------------------

Daily sales volumes
  Oil (bbls/d)                       9,853      8,785      9,391      7,434
  Bitumen (bbls/d) (1)                 523        562        556        541
                                --------------------------------------------
  Combined (bbls/d)                 10,376      9,347      9,947      7,975
  Natural gas (mcf/d)                  620      1,047        781      2,130
                                --------------------------------------------
  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
                                --------------------------------------------
  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
                                --------------------------------------------
Net Debt (5)                         4,995     76,937      4,995     76,937
                                --------------------------------------------

Shares outstanding, end of
 period (000s)                     335,949    335,638    335,949    335,638
----------------------------------------------------------------------------
(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.

----------------------------------------------------------------------------
                                     Three months ended  Twelve months ended
                                        December 31,        December 31,
----------------------------------------------------------------------------
Production by Area (boe/d)                2016      2015      2016      2015
----------------------------------------------------------------------------
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
----------------------------------------------------------------------------
Total production                        10,479     9,521    10,077     8,330
----------------------------------------------------------------------------

Operating Netback

----------------------------------------------------------------------------
                                     Three months ended  Twelve months ended
                                        December 31,        December 31,
----------------------------------------------------------------------------
($/boe)                                   2016      2015      2016      2015
----------------------------------------------------------------------------
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
----------------------------------------------------------------------------
                                         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
----------------------------------------------------------------------------
Operating netback(1)                     19.51     16.61     15.76     20.53
----------------------------------------------------------------------------
(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:

----------------------------------------------------------------------------
Subject  Volume        Term          Reference     Strike Price    Option
 of                                                                Traded
 Contract
----------------------------------------------------------------------------
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
----------------------------------------------------------------------------
(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
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                                  (Mbbl)   (Mbbl)   (MMcf)   (MBoe)   (MBoe)
----------------------------------------------------------------------------

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
----------------------------------------------------------------------------
Total proved                      75,260    1,057      456   76,393   63,956
Probable                          56,374  178,742      421  235,186  230,010
----------------------------------------------------------------------------
Total proved plus probable       131,634  179,799      877  311,579  293,966
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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
----------------------------------------------------------------------------
                                       (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)
----------------------------------------------------------------------------
Balance, Dec 31, 2016                  75,260     1,057       456    76,393
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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
----------------------------------------------------------------------------
Balance, Dec 31, 2016                  56,374   178,742       421   235,187
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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)
----------------------------------------------------------------------------
Balance, Dec 31, 2016                 131,634   179,799       877   311,579
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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
----------------------------------------------------------------------------
----------------------------------------------------------------------------
        (US$/bbl)  (CDN$/bbl)   (CDN$/bbl) (CDN$/MMBtu)    (%/yr) (US$/Cdn$)
----------------------------------------------------------------------------
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)

----------------------------------------------------------------------------
                                                   Risked Volumes(4)
                                          ----------------------------------

                                           Heavy Crude Oil      Bitumen
----------------------------------------------------------------------------
             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
----------------------------------------------------------------------------

----------------------------------------------------------------------------
                                                   Unrisked Volumes
                                          ----------------------------------

                                           Heavy Crude Oil      Bitumen
----------------------------------------------------------------------------
             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
----------------------------------------------------------------------------

NPV of Best Estimate (P50) Contingent Resource Volumes - By Property

----------------------------------------------------------------------------
                      Net Present Values of Future Net Revenue Before Income
                                              Taxes
                     -------------------------------------------------------
                                      Discounted at (%/year)
                     -------------------------------------------------------
                              0%         5%        10%        15%        20%
                     -------------------------------------------------------
Project                                        ($M)
----------------------------------------------------------------------------

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
----------------------------------------------------------------------------

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
----------------------------------------------------------------------------

----------------------------------------------------------------------------
                      Net Present Values of Future Net Revenue After Income
                                            Taxes (10)
                     -------------------------------------------------------
                                      Discounted at (%/year)
                     -------------------------------------------------------
                              0%         5%        10%        15%        20%
                     -------------------------------------------------------
Project                                        ($M)
----------------------------------------------------------------------------

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
----------------------------------------------------------------------------

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
----------------------------------------------------------------------------

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

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