Pine Cliff Energy Ltd. announces fourth quarter and annual results



    CALGARY, April 20 /CNW/ - Pine Cliff Energy Ltd.
(www.pinecliffenergy.com) (TSX VENTURE:PNE) is pleased to announce its
financial and operational results for the three months and fiscal year ended
December 31, 2006. Much of the year's efforts were directed towards activities
in South America. Staffing and becoming familiar with regulations and business
philosophies in both Argentina and Chile were necessary prior to proceeding
with the acquisition of properties.
    These efforts are now being rewarded. In Q1, 2007, Pine Cliff's 93
percent owned subsidiary, CanAmericas Energy Ltd. ("CanAmericas"), was
successful in negotiating two major farm-in arrangements in Argentina. One has
been completed and the other is subject to completion of CanAmericas due
diligence. The farm-ins will result in earning interests in a total of 912,810
gross acres (542,410 net acres) of exploration and exploitation lands. For
more details kindly refer to "Property Discussions" of this report.
Negotiations are ongoing with regard to the acquisition of additional
exploration, exploitation and producing properties.
    The Company is pleased with the progress that CanAmericas is making in
South America. The geological potential and size of these concessions is
extraordinary. A land position of this magnitude is extremely difficult to
obtain and provides the potential for a large number of drill locations.
    In 2007 Pine Cliff will also increase its activities in Canada. The focus
will be to acquire production and to participate in more drilling.

    
    HIGHLIGHTS
                                                       2006         2005(1)

    -------------------------------------------------------------------------
    Financial
    Revenue - Oil and Gas                          $   661,100   $   633,873
    Funds flow from Operations(2)                     (424,248)      368,259
      Per Share Basic                                    (0.01)         0.01
      Per Share Fully Diluted                            (0.01)         0.01
    Net Loss                                        (1,014,605)     (329,062)
      Per Share Basic                                    (0.03)        (0.01)
      Per Share Fully Diluted                            (0.03)        (0.01)
    Capital Expenditures and Acquisitions              271,926     2,097,930
    Shareholders' Equity                             4,239,638     5,110,407
    Shares Outstanding (December 31)                36,523,041    36,420,041
    -------------------------------------------------------------------------
    Operations
    Oil and Liquids (barrels per day)                        5             7
      Average Price ($ per barrel)                       63.88         62.42
    Natural Gas (MCF per day)                              195           175
      Average Price ($ per MCF)                           7.58         10.78
    Total Barrels per Day (BOE per day)(3)                  38            36
    -------------------------------------------------------------------------
    Reserves(4)
    Oil and Liquids (barrels)
      Proved Developed Producing (Gross)                10,200        13,300
      Proved plus Probable (Gross)                      13,700        21,400
    Natural Gas (MCF)
      Proved Developed Producing (Gross)               326,000       352,000
      Proved plus Probable (Gross)                     440,000       568,000
    Share Trading Statistics
    Share Prices (based on daily closing price)
      High                                         $      0.76   $      0.61
      Low                                          $      0.40   $      0.42
      Close                                        $      0.65   $      0.55
    Daily Average Trading Volume                         3,754         7,535
    -------------------------------------------------------------------------
    (1) Operations commenced April 8, 2005
    (2) Funds flow from operations is not a recognized measure under GAAP.
        Management believes that in addition to net earnings, funds flow from
        operations is a useful supplemental measure as it demonstrates the
        Company's ability to generate the cash necessary to fund future
        growth through capital investment. Investors are cautioned, however,
        that this measure should not be construed as an indication of the
        Company's performance. The Company's method of calculating this
        measure may differ from other issuers and accordingly, it may not be
        comparable to that used by other issuers. For these purposes, the
        Company defines funds flow from operations as funds provided by
        operations before changes in non-cash operating working capital items
        excluding foreign exchange loss and asset retirement expenditures.
    (3) BOE's are calculated using a conversion ratio of 6 MCF to 1 barrel of
        oil. The conversion is based on an energy equivalency conversion
        method primarily applicable at the burner tip and does not represent
        a value equivalency at the wellhead and as such may be misleading if
        used in isolation.
    (4) Gross reserves relate to the Company's ownership of reserves before
        royalty interests.


    REVIEW OF OPERATIONS

    Reserves

    The Company engaged the services of Sproule Associates Limited to prepare
a reserve evaluation with an effective date of December 31, 2006. The reserves
are located in the Province of Alberta. The majority of the Company's
production is comprised of natural gas. The Company's main gas producing area
is located in the Sundance area of West Central Alberta. The gross reserve
figure in the following charts represents the Company's ownership interest
before royalties and the net figure is after deductions for royalties.

                       SUMMARY OF OIL AND GAS RESERVES
                           AS OF DECEMBER 31, 2006
                          FORECAST PRICES AND COSTS

                                                  RESERVES
                                      Natural                Natural Gas
                                        Gas                    Liquids
                                Gross          Net        Gross          Net
    RESERVE CATEGORY            (MMcf)       (MMcf)       (Mbbl)       (Mbbl)
    -------------------------------------------------------------------------
    PROVED
      Developed Producing         326          249           10            7
    -------------------------------------------------------------------------
    TOTAL PROVED                  326          249           10            7
    PROBABLE                      114           87            4            2
    -------------------------------------------------------------------------
    TOTAL PROVED PLUS PROBABLE    440          336           14            9
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


                  RECONCILIATION OF COMPANY GROSS RESERVES
                          BY PRINCIPAL PRODUCT TYPE
                          FORECAST PRICES AND COSTS

                                                  Natural
                                                    Gas
                               Gross Proved    Gross Probable   Gross Proved
                                   (MMcf)          (MMcf)      Plus Probable
                                                                   (MMcf)
    -------------------------------------------------------------------------
    December 31, 2005                352             216             568
      Technical Revisions             45            (102)            (57)
      Production                     (71)              -             (71)
    -------------------------------------------------------------------------
    December 31, 2006                326             114             440
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


             SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE
                           AS OF DECEMBER 31, 2006
                          FORECAST PRICES AND COSTS

                                     NET PRESENT VALUE OF FUTURE NET REVENUE
                                                After Income Taxes
                                              Discounted at (%/year)
                                      0        5       10       15       20
    (M$)
    RESERVE CATEGORY
    -------------------------------------------------------------------------
    PROVED
      Developed Producing          1,722    1,519    1,362    1,237    1,135
    -------------------------------------------------------------------------
    TOTAL PROVED                   1,722    1,519    1,362    1,237    1,135
    PROBABLE                         483      346      258      200      161
    -------------------------------------------------------------------------
    TOTAL PROVED PLUS PROBABLE     2,205    1,865    1,620    1,437    1,296
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Year     Edmonton Par  Alberta Gas    Propane      Butane      Pentane
                Price       Reference
                              Price
                            Plantgate
                (Cdn $        (Cdn $      (Cdn $       (Cdn $       (Cdn $
              per barrel)    per MCF)   per barrel)  per barrel)  per barrel)
    -------------------------------------------------------------------------
    2007         74.10         7.51        43.94        55.23        75.88
    2008         77.62         8.38        46.03        57.85        79.49
    2009         70.25         7.55        41.66        52.36        71.94
    2010         65.56         7.37        38.88        48.87        67.14
    2011         61.90         7.54        36.71        46.14        63.40
    2012         63.15         7.68        37.45        46.07        64.67
    2013         64.42         7.79        38.21        48.02        65.98
    2014         65.72         7.93        38.97        48.98        67.30
    2015         67.04         8.07        39.76        49.97        68.66
    2016         68.39         8.21        40.56        50.97        70.04
    2017         69.76         8.35        41.38        52.00        71.45

    Natural gas and liquid prices escalate at various rates thereafter.

    The following cautionary statements are specifically required by NI
51-101.

    -  It should not be assumed that the estimates of future net revenue
       presented in the above tables represent the fair market value of the
       reserves. There is no assurance that the forecast prices and costs
       assumptions will be attained and variances could be material.
    -  Disclosure provided herein in respect of BOE's may be misleading,
       particularly if used in isolation. In accordance with NI 51-101, a BOE
       conversion ratio of 6mcf:1bbl has been used in all cases in this
       disclosure. This BOE conversion ratio is based on an energy
       equivalency conversion method primarily applicable at the burner tip
       and does not represent a value equivalency at the wellhead.
    -  Estimates of reserves and future net revenues for individual
       properties may not reflect the same confidence level as estimates of
       reserves and future net revenues for all properties due to the effects
       of aggregation.

    Land Holdings

    The Company's holdings of natural gas leases and rights as of December 31,
2006 are as follows:

                                      2006                      2005
                            Gross Acres   Net Acres   Gross Acres   Net Acres
    -------------------------------------------------------------------------
    Alberta                     7,360        2,802        7,680        2,844
    -------------------------------------------------------------------------

    Petroleum and Natural Gas Capital Expenditures

    The following table summarizes petroleum and natural gas capital
expenditures incurred by the Company on acquisitions, land, seismic,
exploration and development drilling and production facilities for the years
ended December 31:

                                                       2006          2005
    -------------------------------------------------------------------------
    Exploration and development costs              $   226,193   $ 1,089,632
    Acquisitions                                             -       999,701
    Land costs                                               -         5,490
    Seismic                                                  -         2,433
    -------------------------------------------------------------------------
    Net petroleum and natural gas capital
     expenditures                                  $   226,193   $ 2,097,256
    -------------------------------------------------------------------------

    Drilling History

    The following table summarizes the Company's gross and net drilling
activity and success:

                                              2006
                       Development         Exploratory            Total
                     Gross       Net     Gross       Net     Gross       Net
    -------------------------------------------------------------------------

    Natural Gas          1       0.1         -         -         1       0.1
    -------------------------------------------------------------------------
    Success rate      100%      100%         -         -      100%      100%
    -------------------------------------------------------------------------


                                              2005
                       Development         Exploratory            Total
                     Gross       Net     Gross       Net     Gross       Net
    -------------------------------------------------------------------------

    Natural Gas          2       0.2         -         -         2       0.2
    Dry                  -         -         1       1.0         1       1.0
    -------------------------------------------------------------------------
    Total                2       0.2         1       1.0         3       1.2
    -------------------------------------------------------------------------
    Success rate      100%      100%         -         -       67%     16.7%
    -------------------------------------------------------------------------
    

    PROPERTY DISCUSSIONS

    Pine Cliff's only producing property is located in the Sundance area of
West Central Alberta. The Company has a 13.7% average working interest in
5,280 acres (723 net) of Crown land in the area. There are currently 5 (0.53
net) wells producing. The wells produce from multiple zones from the Cadomin
to the Belly River. Current production from the five wells is approximately
2,660 mcf/day gross, 305 mcf/day net to Pine Cliff. NGL's are produced in
association with the natural gas.
    There is still significant industry activity in the Sundance area. With
the success of last year's drilling program the interests in non producing
properties are being analyzed to determine whether there are additional
prospective drilling locations. The increased activity in the area has caused
bottlenecks in non-interest gathering systems and gas plants causing some of
our wells to be shut-in from time to time over the last year. Increases in
facility capacity and re-routing of a portion of our production have
alleviated these problems at this time.
    In 2006 Pine Cliff had decided to pursue oil and gas opportunities in
South America. In 2007, the Company has been successful in negotiating two
separate farm-in agreements to acquire an interest in 40 gross townships
(912,810 acres) (net 24 townships (542,410 acres)) of land.

    Canadon Ramirez Farm-In

    The Company through its 93 percent owned subsidiary, CanAmericas Energy
Ltd. ("CanAmericas") has earned a 49% interest in 47,940 gross acres (23,490
net acres) of an exploitation concession situated in the western part of the
San Jorge Basin by committing to fund 100% of exploration costs totaling
$US 5,500,000 over the next two years. The commitment includes conducting a 3D
seismic program and drilling three wells in the first year at an estimated
cost of $US 4,630,000. In the second year of the commitment CanAmericas is
committed to spend the remainder of the $US 5,500,000 on drilling.
    The acreage is bordered by several producing oil fields. Over 40 separate
prospective reservoirs belonging to the Upper-Mid Cretaceous-aged Bajo Barreal
and Castillo Formations, are known to exist within the farm in area at depths
between 1950 - 5000 feet. Additionally, Neocomian aged source rocks within the
farm in area have been proven to be oil generating and over pressured.
    CanAmericas is currently conducting a 75 square mile 3D seismic survey
which is to be completed by the end of May. It is the first such program to be
recorded over the producing and earned areas that will permit detailed
stratigraphic and structural mapping of multiple leads that were initially
developed from existing 2D coverage. An agreement was made with an adjacent
operator to trade seismic data providing us with data over a total of 93
square miles. This will allow CanAmericas to tie in its seismic data to
seismic conducted over an existing producing oil field. A drilling rig has
been contracted and drilling of three prospects is scheduled to begin by
August, 2007.

    San Jorge Basin Farm-In

    The Company through its 93 percent owned subsidiary, CanAmericas, has
negotiated exclusive rights to progressively earn a 60% interest in 864,870
gross acres (518,920 net acres) of an exploration permit situated in the 
north-central San Jorge basin. CanAmericas has the right to become operator of
the Permit and will likely decide to do so after it has completed its due
diligence.
    Subject to completion of the due diligence, the exclusive rights commit
CanAmericas to fund 100% of the costs to conduct an aero-magnetic and
aero-gravity survey over the entire permit area, acquire 39 square miles of 3D
seismic, and drill two exploration wells to earn a 30% participating interest
in the entire permit. The surveys are to be completed within one year of the
effective date of the agreement and the wells are to be drilled within two
years of the effective date.
    CanAmericas will earn an additional 30% in the entire permit by drilling
two additional wells within three years of the effective date of the
agreement. CanAmericas will receive 100 percent of cash flow from this
property until it has recovered 100 percent of its costs for the two work
programs. The estimated cost for both work programs is $US 4,620,000. After
completion of the two work programs costs will be shared on a 60 percent
CanAmericas and 40 percent farmor basis.
    Principal reservoir objectives are multiple sands of the Upper-Mid
Cretaceous Bajo Barreal and Castillo Formations which are known to exist
throughout the permit at depths ranging between 1000 - 5000 feet. A producing
oil field lies adjacent to the southern border of this permit and existing
seismic data and well control suggests the productive trend may extend into
the southern portion of this permit. Additionally, numerous oil and gas shows
encountered by older wells drilled throughout the permit during the 1960's -
1980's prove that the permit contains an active hydrocarbon system.
    CanAmericas will initially acquire the regional aero-gravity and
aero-magnetic surveys over the entire permit and with this information, and
existing well and 2D seismic coverage, will determine where to best conduct
the required 3D seismic survey. The 3D coverage is expected to assist in
better understanding strategraphic environments that were previously
identified from existing 2D seismic coverage.

    FINANCIAL AND OPERATIONAL

    The Company was incorporated in the Province of Alberta on November 10,
2004 and commenced operations on April 8, 2005.

    
    Quarterly Financial and Operational Highlights
    ----------------------------------------------

                                                 2006
                          ---------------------------------------------------
                               4th          3rd          2nd          1st
    Revenue - Oil
     and Gas              $   170,231  $    90,386  $   108,413  $   292,070
    Funds Flow from
     Operations(1)            (51,833)    (113,095)    (337,020)      77,700
      Per Share Basic           (0.00)       (0.00)       (0.01)        0.00
      Per Share Diluted         (0.00)       (0.00)       (0.01)        0.00
    Net Loss                 (209,575)    (211,784)    (526,107)     (67,139)
      Per Share Basic           (0.01)       (0.01)       (0.01)       (0.00)
      Per Share Diluted         (0.01)       (0.01)       (0.01)       (0.00)
    Capital Expenditures
     and Acquisitions          19,227       (3,463)     124,236      131,926
    Total Assets            4,494,010    4,700,305    4,892,079    5,373,147
    Working Capital         2,963,513    3,030,822    3,175,577    3,625,133
    Shareholder's Equity    4,239,638    4,411,915    4,589,015    5,093,951
    -------------------------------------------------------------------------
    Operations
    Oil and Liquids
     (barrels per day)              3            5            4            9
    Natural Gas (MCF
     per day)                     226          131          139          284
    -------------------------------------------------------------------------

    (1) Funds flow from operations is not a recognized measure under GAAP.
        Management believes that in addition to net earnings, funds flow from
        operations is a useful supplemental measure as it demonstrates the
        Company's ability to generate the cash necessary to fund future
        growth through capital investment. Investors are cautioned, however,
        that this measure should not be construed as an indication of the
        Company's performance. The Company's method of calculating this
        measure may differ from other issuers and accordingly, it may not be
        comparable to that used by other issuers. For these purposes, the
        Company defines funds flow from operations as funds provided by
        operations before changes in non-cash operating working capital items
        excluding foreign exchange loss and asset retirement expenditures.
    

    Production
    ----------
    On April 8, 2005, with an effective date of January 1, 2005, the Company
acquired interests in two natural gas properties for a cash payment of
$999,701. The Sundance land, located in West Central Alberta was the major
property acquired. Pine Cliff acquired a 13.2 percent working interest
(subject to Crown royalty) in 4,320 acres in this area. There are two wells
(0.308 net) on these lands that have been producing for approximately two
years. Two additional multi-zone wells were drilled in 2005 (net 0.2) and a
further well (0.038 net) was drilled in 2006. In 2006 production averaged 195
MCF (2005 - 175 MCF) of natural gas and five barrels (2005 - 7 barrels) of
natural gas liquids per day.
    During the second quarter of 2006, the operator of the gas plant, where
approximately 80 percent of the Company's production is processed, performed
an annual turnaround resulting in the significant reduction in production for
that period. Subsequent to the completion of the turnaround, capacity
restrictions resulted in the continued shut-in of the Company's production. In
September the capacity restrictions were resolved and the Company's production
resumed.
    Pine Cliff also acquired a 100 percent interest in a 256 hectare Crown
lease in the Auburndale area of East Central Alberta. The Company drilled a
Devonian well for sweet natural gas during 2005. The Company tested the well
and concluded that the projected production volume is not sufficient to
construct a five kilometer pipeline to tie it in. The drilling and land costs
were written off in 2005.

    Revenue
    -------
    Revenue from petroleum and natural gas sales for 2006 was $661,100
compared to $633,873 in 2005. The increase of $27,227 was due to higher
production volumes offset by lower commodity prices. Average price received in
2006 for its natural gas was $7.58 (2005 - $10.78) per MCF and $63.88 (2005 -
$62.42) per barrel for natural gas liquids. The Company did not have hedging
agreements in either 2006 or 2005 and presently does not have any future
hedging agreements.
    Fourth quarter petroleum and natural gas sales increased to $170,231 from
$90,386 in the third quarter. The increase is due to full production from the
Sundance property as well as higher natural gas prices.

    Royalties
    ---------
    Royalties consist of Crown royalties paid to the Province of Alberta and
gross overriding royalties. In 2006 the Company recorded a net recoverable
amount of $1,054 in Crown royalties compared to a Crown royalty expense of
$17,464 in 2005. The operator of the Sundance property applied for and
received a Crown royalty holiday in respect of the wells drilled in 2005. As
customary in the industry, Crown royalties were paid on this well until the
royalty holiday was granted. As a result of the Crown royalty holiday, the
Company recovered in 2006 the full amount of the $17,464 paid in 2005. The
royalty holiday has expired in 2006 and the Company is now paying royalties on
this production.
    Gross overriding royalties of $26,723 (2005 - $21,366) were recorded in
2006. There has been no significant change to the rates over the two years or
quarter over quarter.

    Interest Income
    ---------------
    The Company maintains an investment account with its principal banker
that pays interest at prime less 2.25 percent as long as the Company maintains
a minimum balance of $1,500,000. The Company in March 2007 drew down on the
outstanding cash balance to finance its seismic expenditure commitment in
Argentina. Please refer to Business Prospects Section.

    Production Costs
    ----------------
    Production costs for the year ended December 31, 2006, were $132,346
(2005 - $53,449) or $9.62 (2005 - $5.41) per BOE (Q4 - $10.90 per BOE, Q3 -
$9.37 per BOE). BOE's are calculated using a conversion ratio of 6 MCF to 1
barrel of oil. The conversion is based on an energy equivalency conversion
method primarily applicable at the burner tip and does not represent a value
equivalency at the wellhead and as such may be misleading if used in
isolation. Due to capacity constraints at the gas plant, the Company is
incurring increased processing fees in relation to its Sundance gas
production.

    General and Administrative
    --------------------------
    General and administrative expenses for 2006 were $1,043,866 (Q4 -
$254,226) compared to $239,417 for 2005 and $220,442 for the third quarter of
2006. The primary reason for the increase in 2006 expenses was due to the
Company incurring $621,621 in administration costs related to its activities
in South America. The majority of the South American costs related to
engineering and consulting fees of $408,651, travel and accommodation costs of
$92,121, and legal costs of $96,559.
    Pine Cliff does not have any employees at the present time but has
engaged Comstate Resources Ltd. ("Comstate") a related party (see Related
Party section), to provide management services and engages the services of
consultants on a contract or temporary basis. Pine Cliff's subsidiary
CanAmericas Energy Ltd. ("CanAmericas") has also engaged the services of two
individual professionals as senior management and officers of CanAmericas.
    In addition to the above South American costs, increases in geological
consulting fees of $18,490 (Canadian operations); audit, accounting and
engineering costs of $65,874 for year end audit and financial reporting and
$84,000 in management fees (see Related Party section) were incurred in 2006.

    Stock Based Compensation
    ------------------------
    Stock based compensation for the year ended December 31, 2006, was
$128,385 (2005 - $87,041). The Company has a stock-based compensation plan for
Pine Cliff. The Company records a compensation expense over the vesting period
based on the fair value of options granted to employees, directors and
consultants. The Company issued 895,000 stock options in Pine Cliff during
2006. The Company estimated the stock options fair value at $191,458 ($0.21
per option) using the Black-Scholes option pricing model, assuming a weighted
average risk free interest rate of 4.13 percent, weighted average expected
volatility of 63.1 percent, weighted average expected life of 2.5 years and no
annual dividend rate.

    Dry Hole Exploration Costs
    --------------------------
    As previously discussed, the Company drilled a Devonian gas well in the
second quarter of 2005. The well, although capable of production, did not
contain sufficient reserves to warrant a five kilometer pipeline. Given the
lack of current economics for this well, no proved or probable reserves were
assigned to the well in the preparation of the third party engineering report.
With the Company following the successful efforts method of accounting (see
below), capital costs associated with each field that are in excess of that
field's economic value are to be written off. As such the Company wrote off
$6,222 (2005 - $588,256) in respect of the cost of the land and development
costs incurred in drilling the Devonian well.

    Depletion, Depreciation and Amortization
    ----------------------------------------
    The Company follows the successful efforts method of accounting for
petroleum and natural gas properties and related equipment. Costs of acquiring
unproved properties are capitalized. When petroleum and natural gas properties
are found to contain proved reserves as determined by Company engineers, the
related net book value is depleted on the unit-of-production basis, calculated
by field. The costs of dry holes and abandoned properties are charged to
operations. Geological costs, lease rentals and carrying costs are charged to
income as incurred. Costs of drilling exploratory and development wells that
result in additions to proved reserves are capitalized and depleted on the
unit-of-production basis. Tangible equipment is depreciated on a straight-line
basis over ten years.
    Provisions are made for asset retirement obligations through the
recognition of the fair value of obligations associated with the retirement of
tangible long-life assets being recorded in the period the asset is put into
use, with a corresponding increase to the carrying amount of the related
asset. The obligations recognized are statutory, contractual or legal
obligations. The liability is adjusted over time for changes in the value of
the liability through accretion charges which are included in depletion,
depreciation and accretion expense. The costs capitalized to the related
assets are amortized to earnings in a manner consistent with the depletion and
depreciation of the underlying asset.
    At December 31, 2006, the estimated total undiscounted amount required to
settle the asset retirement obligations was $71,031 (2005 - $42,796). These
obligations will be settled based on the useful lives of the underlying
assets, which extend up to 13 years into the future. This amount has been
discounted using a credit-adjusted risk-free interest rate of five percent.
The discount rate is reviewed annually and adjusted if considered necessary. A
change in the rate would not have a significant impact on the amount recorded
for asset retirement obligations.
    The calculation of the above requires an estimation of the amount of the
Company's petroleum reserves by field. This figure is calculated annually by
an independent engineering firm and used to calculate depletion. This
calculation is to a large extent subjective. Reserve adjustments are affected
by economic assumptions as well as estimates of petroleum products in place
and methods of recovering those reserves. To the extent reserves are increased
or decreased, depletion costs will vary.

    Income Taxes
    ------------
    The Company follows the liability method of accounting for income taxes
under which the income tax provision is based on the temporary differences in
the accounts calculated using income tax rates expected to apply in the year
in which the temporary differences will reverse. The Company has sufficient
tax pools so it is not liable for current income tax in 2006. Due to the
decline in natural gas prices as well as the moderate decrease in estimated
reserves, the ability to claim the tax benefits of the following tax pools is
no longer more likely than not and as such the Company has recorded a full
valuation allowance to eliminate the future tax asset.

    Non-Controlling Interest
    ------------------------
    As described above, Foreign Corp. owns seven percent of CanAmericas. The
$38,701 of loss applicable to non-controlling interest relates to their share
of revenues and costs associated with CanAmericas' South American activities.

    Loss
    ----
    The loss for the 2006 fiscal year is $1,014,605 ($209,575 in the fourth
quarter) compared to $329,062 in 2005 and $211,784 in the third quarter of
2006. The 2006 loss was predominantly due to general and administrative costs
incurred in respect of the Company's South American operations as well as a
future tax adjustment. Please see Business Prospects Section for discussions
regarding future activities.

    Funds Flow from Operations
    --------------------------
    Funds flow from operations decreased to negative $424,248 in 2006 from a
positive $368,259 in 2005. The decrease from the 2005 amount was mainly due to
the Company's activities in South America. Quarter over quarter saw a
reduction in the funds flow loss due to increased funds flow from the
Company's oil and natural gas operations.
    The following reconciliation compares funds flow for the fiscal years
ended December 31, 2006 and 2005 to the Company's cash flow from operating
activities as calculated according to Canadian generally accepted accounting
principles:

    
                                                       2006          2005
    -------------------------------------------------------------------------
    Cash flow from operating activities           ($   168,809)  $    25,764
    Items not affecting funds flow
      Due from related party                           (16,006)       16,006
      Accounts receivable                             (154,329)      339,329
      Prepaid expenses                                    (806)        3,460
      Accounts payable and accrued liabilities        (117,138)      (16,135)
      Due to related party                                 165          (165)
      Asset retirement obligations settled              35,123             -
      Foreign exchange loss                             (2,448)            -
    -------------------------------------------------------------------------
    Funds flow for the period                     ($   424,248)  $   368,259
    -------------------------------------------------------------------------
    

    Liquidity and Capital Resources
    -------------------------------
    As of December 31, 2006, Pine Cliff had positive working capital of
$2,963,513 (December 31, 2005 - $3,565,689). These funds will be used to fund
financial commitments as discussed under Property Discussion. The Company
plans on financing the balance of its commitments through the issue of
additional common shares and company cash flow.

    Forward-Looking Information
    ---------------------------
    Certain information set forth in this document, including management's
assessment of Pine Cliff Energy Ltd. ("Pine Cliff" or "the Company") future
plans and operations, contains forward-looking statements. By their nature,
forward-looking statements are subject to numerous risks and uncertainties,
some of which are beyond Pine Cliff's control, including the impact of general
economic conditions, industry conditions, volatility of commodity prices,
currency fluctuations, imprecision of reserve estimates, environmental risks,
competition from other industry participants, the lack of availability of
qualified personnel or management, stock market volatility and ability to
access sufficient capital from internal and external sources. Readers are
cautioned that the assumptions used in the preparation of such information,
although considered reasonable at the time of preparation, may prove to be
imprecise and, as such, undue reliance should not be placed on forward-looking
statements. Pine Cliff's actual results, performance or achievement could
differ materially from those expressed in, or implied by these forward-looking
statements, and, accordingly, no assurance can be given that any of the events
anticipated by the forward-looking statements will transpire or occur, or if
any of them do so, what benefits that Pine Cliff will derive therefrom. Pine
Cliff disclaims any intention or obligation to update or revise any
forward-looking statements, whether as a result of new information, future
events or otherwise. Readers are cautioned that net present value of reserves
does not represent fair market value of reserves.

    The TSX Venture Exchange does not accept responsibility for the adequacy
    or accuracy of this release.



    
    Pine Cliff Energy Ltd.
    Consolidated Balance Sheets

    As at December 31

                                                          2006          2005
    Assets
    Current
      Cash                                         $ 2,915,020   $ 3,334,961
      Due from related party (Note 2)                        -        16,006
      Accounts receivable                              185,001       339,330
      Prepaid expenditures                               2,654         3,460
    -------------------------------------------------------------------------
                                                     3,102,675     3,693,757
    Future Income Tax Asset (Note 4)                         -       216,254
    -------------------------------------------------------------------------
    Property and Equipment (Note 5)
      Property and equipment                         1,848,887     1,538,809
      Accumulated depletion and depreciation          (457,552)     (180,832)
    -------------------------------------------------------------------------
                                                     1,391,335     1,357,977
    -------------------------------------------------------------------------
                                                   $ 4,494,010   $ 5,267,988
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Liabilities
    Current
      Accounts payable and accrued liabilities     $   139,162   $   127,903
      Due to related party (Note 2)                          -           165
    -------------------------------------------------------------------------
                                                       139,162       128,068
    Asset Retirement Obligations (Note 6)               40,240        29,513
    Non-controlling Interests (Note 3)                  74,970             -
    -------------------------------------------------------------------------
                                                       254,372       157,581
    -------------------------------------------------------------------------
    Commitments (Notes 8 and 11)
    Shareholders' Equity
      Share capital (Note 7)                         5,377,343     5,352,428
      Contributed surplus                              205,962        87,041
      Deficit                                       (1,343,667)     (329,062)
    -------------------------------------------------------------------------
                                                     4,239,638     5,110,407
    -------------------------------------------------------------------------
                                                   $ 4,494,010   $ 5,267,988
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------



    Pine Cliff Energy Ltd.
    Consolidated Statements of Loss and Deficit

    For the years ended December 31

                                                          2006          2005

    Revenue
      Oil and gas sales                            $   661,100   $   633,873
      Royalties                                        (25,669)      (38,830)
      Alberta royalty tax credits                            -         4,366
      Interest income                                  118,981        61,715
    -------------------------------------------------------------------------
                                                       754,412       661,124
    -------------------------------------------------------------------------
    Expenses
      Production costs                                 132,346        53,449
      General and administrative                     1,043,866       239,417
      Foreign exchange loss                              2,448             -
      Stock based compensation                         128,385        87,041
      Dry hole exploration costs (Note 5)                6,222       588,256
      Depletion, depreciation and accretion            278,197       181,208
    -------------------------------------------------------------------------
                                                     1,591,464     1,149,371
    -------------------------------------------------------------------------
    Loss Before Income Taxes and
     Non-controlling Interests                        (837,052)     (488,247)
    -------------------------------------------------------------------------
    Income Taxes Provision (Recovery) (Note 4)
      Current                                                -             -
      Future                                           216,254      (159,185)
    -------------------------------------------------------------------------
                                                       216,254      (159,185)
    -------------------------------------------------------------------------
    Loss before Non-Controlling Interests           (1,053,306)     (329,062)
    Loss applicable to non-controlling interests
     (Note 3)                                           38,701             -
    -------------------------------------------------------------------------
    Loss for the Year                               (1,014,605)     (329,062)
    Deficit, beginning of year                        (329,062)            -
    -------------------------------------------------------------------------
    Deficit, end of year                           $(1,343,667)  $  (329,062)
    -------------------------------------------------------------------------
    Loss Per Share - Basic and Diluted (Note 7)    $     (0.03)  $     (0.01)



    Pine Cliff Energy Ltd.
    Consolidated Statements of Cash Flow

    For the years ended December 31

                                                          2006          2005
    Operating Activities
      Loss for the year                            $(1,014,605)  $  (329,062)
      Items not affecting cash
        Stock based compensation                       128,385        87,041
        Dry hole exploration costs                       6,222       588,256
        Depletion, depreciation and accretion          278,197       181,208
        Foreign exchange loss                            2,448             -
        Future income taxes (recovery)                 216,254      (159,185)
        Loss applicable to non-controlling
         interests                                     (38,701)            -
    -------------------------------------------------------------------------
                                                      (421,800)      368,258
    -------------------------------------------------------------------------
      Change in non-cash working capital
        Due from related party                          16,006       (16,006)
        Accounts receivable                            154,329      (339,328)
        Prepaid expenditures                               806        (3,460)
        Accounts payable and accrued liabilities       117,138        16,135
        Due to related party                              (165)          165
      Asset retirement obligations settled             (35,123)            -
    -------------------------------------------------------------------------
                                                       252,991      (342,494)
    -------------------------------------------------------------------------
    Cash Provided by (Used in) Operating Activities   (168,809)       25,764
    -------------------------------------------------------------------------
    Financing Activities
      Share option proceeds                             15,450             -
      Issue of shares by subsidiary to
       non-controlling interests                       113,670             -
      Proceeds received on initial
       public offering                                       -     5,463,005
      Issue costs                                            -       (88,802)
      Change in non-cash working capital
        Accounts payable and accrued liabilities             -       (25,000)
        Due to related party                                 -       (53,845)
    -------------------------------------------------------------------------
    Cash Provided by Financing Activities              129,120     5,295,358
    -------------------------------------------------------------------------
    Investing Activities
      Property and equipment expenditures             (271,926)   (2,097,930)
      Change in non-cash working capital
        Accounts payable and accrued liabilities      (105,878)      111,768
    -------------------------------------------------------------------------
    Cash Used In Investing Activities                 (377,804)   (1,986,162)
    -------------------------------------------------------------------------
    Foreign Exchange Loss on Cash Held in
     Foreign Currency                                   (2,448)            -
    -------------------------------------------------------------------------
    Net Cash Inflow (Outflow)                         (419,941)    3,334,960
    Cash, Beginning of Year                          3,334,961             1
    -------------------------------------------------------------------------
    Cash, End of Year                              $ 2,915,020   $ 3,334,961
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Cash Interest Paid                             $         -   $         -
    Cash Taxes Paid                                $         -   $         -



    Notes to the Financial Statements

    For the Years Ended December 31, 2006 and 2005

    1.  SIGNIFICANT ACCOUNTING POLICIES

        Basis of Presentation

        The consolidated financial statements have been prepared by
        management in accordance with Canadian generally accepted accounting
        principles as described below.

        Consolidation

        These financial statements include the accounts of the Company and
        its 93 percent owned subsidiary CanAmericas Energy Ltd.
        ("CanAmericas") (see note 3). Inter-company transactions and balances
        are eliminated upon consolidation.

        Measurement Uncertainty

        The preparation of the consolidated financial statements requires
        management to make estimates and assumptions that affect the reported
        amounts of assets and liabilities and disclosure of contingent assets
        and liabilities at the date of the consolidated financial statements
        and revenues and expenses during the reporting period. Actual results
        can differ from those estimates.

        In particular, amounts recorded for depreciation and depletion and
        amounts used in ceiling test calculations are based on estimates of
        petroleum and natural gas reserves and future costs required to
        develop those reserves. The Company's reserve estimates are evaluated
        annually by an independent engineering firm. By their nature, these
        estimates of reserves and the related future cash flows are subject
        to measurement uncertainty, and the impact on the consolidated
        financial statements of future periods could be material.

        The amounts recorded for asset retirement obligations were estimated
        based on the Company's net ownership interest in all wells and
        facilities, estimated costs to abandon and reclaim the wells and
        facilities and the estimated period during which these costs will be
        incurred in the future. Any changes to these estimates could change
        the amount recorded for asset retirement obligations and may
        materially impact the consolidated financial statements of future
        periods.

        Petroleum and Natural Gas Properties and Related Equipment

        The Company follows the successful efforts method of accounting for
        petroleum and natural gas properties and related equipment. Costs of
        exploratory wells are initially capitalized pending determination of
        proved reserves. Costs of wells which are assigned proved reserves
        remain capitalized, while costs of unsuccessful wells are charged to
        earnings. All other exploration costs including geological and
        geophysical costs are charged to earnings as incurred. Development
        costs, including the cost of all wells, are capitalized.

        Producing properties and significant unproved properties are assessed
        annually or as economic events dictate, for potential impairment.
        Impairment is assessed by comparing the estimated net undiscounted
        future cash flows to the carrying value of the asset. If required,
        the impairment recorded is the amount by which the carrying value of
        the asset exceeds its fair value.

        Depreciation and depletion of capitalized costs of oil and gas
        producing properties are calculated using the unit of production
        method. Development and exploration drilling and equipment costs are
        depleted over the remaining proved developed reserves. Depreciation
        of other plant and equipment is provided on the straight line method.
        Straight line depreciation is based on the estimated service lives of
        the related assets which is estimated to be ten years.

        Furniture, Equipment and Other

        These assets are recorded at cost and are depreciated on a straight
        line basis over five to ten years.

        Income Taxes

        The Company follows the liability method of accounting for income
        taxes under which the income tax provision is based on the temporary
        differences between the amounts reported by the Company and their
        respective tax bases calculated using income tax rates expected to
        apply in the year in which the temporary differences will reverse.

        Asset Retirement Obligations

        The Company recognizes the fair value of obligations associated with
        the retirement of long-life assets in the period the asset is put
        into use, with a corresponding increase to the carrying amount of the
        related asset. The obligations recognized are statutory, contractual
        or legal obligations. The liability is adjusted over time for changes
        in the value of the liability through accretion charges which are
        included in depletion, depreciation and accretion expense. The costs
        capitalized to the related assets are amortized to earnings in a
        manner consistent with the depletion and depreciation of the
        underlying asset.

        Stock-based Compensation

        The Company has a stock-based compensation plan which is described in
        Note 7. The Company records compensation expense over the vesting
        period based on the fair value of options granted to employees,
        directors and consultants. These amounts are recorded as contributed
        surplus. Any consideration paid by employees, directors or
        consultants on the exercise of these options is recorded as share
        capital together with the related contributed surplus associated with
        the exercised options.

        Revenue Recognition

        Petroleum and natural gas sales are recognized when the commodities
        are delivered and title transfers to the purchasers.

        Foreign Currency Translation

        The Company translates foreign currency denominated monetary assets
        and liabilities of its integrated foreign subsidiary at the exchange
        rate in effect at the balance sheet date and non-monetary assets and
        liabilities are translated at historical exchange rates. Revenues and
        expenses are translated at estimated transaction date exchange rates
        except depletion and depreciation expense, which is translated at the
        same historical exchange rates as the related assets. Exchange gains
        or losses are included in the determination of net income as foreign
        exchange gain or loss.

        Joint Interest Operations

        Significant portions of the Company's oil and gas operations are
        conducted with other parties and accordingly the financial statements
        reflect only the Company's proportionate interest in such activities.

        Earnings Per Share

        Basic earnings per share is computed by dividing the earnings by the
        weighted average number of shares outstanding during the year.
        Diluted per share amounts reflect the potential dilution that could
        occur if options to purchase common shares were exercised. The
        treasury stock method is used to determine the dilutive effect of
        common share options, whereby proceeds from the exercise of common
        share options or other dilutive instruments are assumed to be used to
        purchase common shares at the average market price during the year.

    2.  RELATED PARTY TRANSACTIONS

        Bonterra Energy Income Trust ("Bonterra"), an organization with
        common directors and management and the former parent of the Company,
        through its wholly owned subsidiaries Comstate Resources Ltd.
        ("Comstate"), Bonterra Energy Corp. ("Bonterra Corp.") and Novitas
        Energy Ltd. ("Novitas") has provided working capital, management
        services and has sold natural gas properties to the Company. Fees
        paid for management services totalled $216,000 (2005 - $132,000) for
        the year. The management services agreement may be cancelled by the
        Company with 90 days notice.

        As of December 31, 2006, the Company owed Nil (2005 - $165) to
        Bonterra and its wholly owned subsidiaries for these items. The
        Company has an account receivable from Novitas of Nil (December 31,
        2005 - $16,006) relating to post closing adjustments in relation to
        the natural gas properties acquired.

    3.  NON-CONTROLLING INTERESTS

        The Company incorporated a subsidiary company, CanAmericas, to
        explore and develop oil and gas properties primarily in South
        America. CanAmericas is owned 93.3 percent by the Company and
        6.7 percent by a foreign private corporation ("Foreign Corp.").
        CanAmericas was initially financed by investments of $1,400,000 U.S.
        for 5,600,000 common shares from the Company and $100,000 U.S. for
        400,000 common shares from Foreign Corp.

        Foreign Corp. has been granted an option to acquire an additional
        1,000,000 common shares of CanAmericas at $0.25 U.S. per common
        share. The options vest 50 percent on each of January 13, 2007 and
        January 13, 2008 and expire on January 13, 2011.

    4.  INCOME TAXES

        The Company recorded a future income tax asset in 2005 as at that
        time management considered its recoverability to be more likely than
        not. As of December 31, 2006, it was determined that this criteria
        was not met and as such the entire amount of the future income tax
        asset was fully offset by a valuation allowance.

                                                         2006          2005
                                                        Amount        Amount
        ---------------------------------------------------------------------
        Future income tax assets:
        Capital assets                             $   125,932   $   158,295
        Asset retirement obligation                     11,670        10,454
        Share issue costs                               29,171        47,505
        Loss carry-forward (expires 2016)              215,798             -
        Valuation allowance                           (382,571)            -
        ---------------------------------------------------------------------
                                                   $         -   $   216,254
        ---------------------------------------------------------------------

        Income tax expense differs from the amounts that would be computed by
        applying Canadian federal and provincial income tax rates as follows:

                                                          2006          2005
        ---------------------------------------------------------------------
        Loss before income taxes and
         non-controlling interests                 $  (837,052)  $  (488,247)
        Combined federal and provincial income
         tax rates                                       34.5%         37.6%
        ---------------------------------------------------------------------
        Income tax provision calculated using
         statutory tax rates                          (288,783)     (183,679)
        Increase (decrease) in income taxes
         resulting from:
          Stock based compensation                      44,293        32,745
          Non-deductible crown royalties                   329         4,667
          Resource allowance                            (4,854)      (19,059)
          Change in valuation allowance                382,571             -
          Change in tax rates                           84,195             -
          Other                                         (1,497)        6,141
        ---------------------------------------------------------------------
        Income tax provision (recovery)            $   216,254   $  (159,185)
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        The Company has the following tax pools, which may be used to reduce
        taxable income in future years, limited to the applicable rates of
        utilization:

                                                      Rate of
                                                    Utilization
                                                         %            Amount
        ---------------------------------------------------------------------
        Undepreciated capital costs                      25      $   305,936
        Canadian oil and gas property expenditures       10          728,371
        Canadian development expenditures                30          398,588
        Canadian exploration expenditures               100          392,110
        Share issue costs                                20          100,588
        Non-capital loss carryforward (expire 2016)     100          757,797
        ---------------------------------------------------------------------
                                                                 $ 2,683,390
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    5.  PROPERTY AND EQUIPMENT

                                 2006                        2005
                                     Accumulated                 Accumulated
                                    Depletion and               Depletion and
                           Cost      Depreciation      Cost      Depreciation
    -------------------------------------------------------------------------
    Undeveloped land   $     5,538   $         -   $     5,490   $         -
    Petroleum and
     natural gas
     properties and
     related equipment   1,797,586       450,365     1,533,319       180,832
    Furniture,
     equipment and
     other                  45,763         7,187             -             -
    -------------------------------------------------------------------------
                       $ 1,848,887   $   457,552   $ 1,538,809   $   180,832
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

        On April 8, 2005, the Company purchased its original properties from
        Bonterra (see Note 2) for approximately $1,000,000 in cash, with an
        effective date of January 1, 2005. The properties included one
        producing property and some exploration lands. The transaction was
        concluded between the related parties at fair value.

        In 2006, the Company wrote off $6,222 (2005 - $588,256) in respect of
        the cost of the land and exploration costs incurred in drilling an
        exploratory well. The well, although capable of production, does not
        contain sufficient reserves to warrant tie-in. Given the lack of
        current economics for this well, no proved or probable reserves were
        assigned to the well in the preparation of the third party
        engineering report.

    6.  ASSET RETIREMENT OBLIGATIONS

        At December 31, 2006, the estimated total undiscounted amount
        required to settle the asset retirement obligations was $71,031
        (December 31, 2005 - $42,796). Costs for asset retirement have been
        calculated assuming a 5 percent inflation rate for 2007, 4 percent
        for 2008, 3 percent for 2009 and 2 percent thereafter. These
        obligations will be settled based on the useful lives of the
        underlying assets, which extend up to 13 years into the future. This
        amount has been discounted using a credit-adjusted risk-free interest
        rate of 5 percent.

        Changes to asset retirement obligations were as follows:

                                                          2006          2005
        ---------------------------------------------------------------------
        Asset retirement obligations, December 31  $    29,513   $         -
        Obligations associated with acquisition
         and development programs                            -        29,138
        Adjustment to asset retirement obligation       44,375             -
        Liabilities settled during the year            (35,123)            -
        Accretion                                        1,475           375
        ---------------------------------------------------------------------
        Asset retirement obligations, December 31  $    40,240   $    29,513
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    7.  SHARE CAPITAL

        Authorized

        Unlimited number of Common Shares without nominal or par value.

        Unlimited number of Class B Preferred Shares without nominal or par
        value which may be issued in one or more series.

                                    2006                        2005
    Issued                  Number        Amount        Number        Amount
    -------------------------------------------------------------------------
    Common Shares
    Balance, beginning
     of year            36,420,041   $ 5,352,428            10   $         1
    Issued pursuant to
     public offering             -             -    36,420,031     5,463,005
    Share issue costs            -             -             -      (167,647)
    Issued on exercise
     of stock options      103,000        15,450             -             -
    Transfer of
     contributed
     surplus to share
     capital                     -         9,465             -             -
    Future tax benefit
     of share issue
     costs                       -             -             -        57,069
    -------------------------------------------------------------------------
    Balance,
     end of year        36,523,041   $ 5,377,343    36,420,041   $ 5,352,428
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

        The number of common shares used to calculate diluted loss per share
        for the year ended December 31, 2006 is 36,477,619 (December 31, 2005
        - 27,545,132). The exercise of outstanding stock options would have
        no dilutive effect on per share amounts.

        On April 7, 2005, the Company concluded its initial public offering
        of 36,420,031 Common Shares at $0.15 per share for gross proceeds of
        $5,463,005. The Company granted 930,000 stock options to its
        directors and officers, and an additional 802,000 stock options to
        other service providers at an exercise price of $0.15 per share. The
        Company commenced trading on the TSX Venture Exchange on April 11,
        2005.

        The Company may grant options for up to 3,605,583 (2005 - 3,605,583)
        common shares. The exercise price of each option granted equals the
        market price of the common share on the date of grant and the
        options' maximum term is five years.

        A summary of the status of the Company's stock option plan as of
        December 31, 2006 and December 31, 2005, and changes during the years
        ended on those dates are presented below:



                             December 31, 2006           December 31, 2005
    -------------------------------------------------------------------------
                                        Weighted-                   Weighted-
                                         Average                     Average
                                        Exercise                    Exercise
                           Options         Price       Options         Price
    -------------------------------------------------------------------------
    Outstanding at
     beginning of year   1,686,000   $      0.16             -   $      0.00
    Options granted        895,000          0.52     1,752,000          0.16
    Options exercised     (103,000)         0.15                           -
    Options cancelled      (58,000)         0.21       (66,000)         0.15
    -------------------------------------------------------------------------
    Outstanding at end
     of year             2,420,000   $      0.29     1,686,000   $      0.16
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Options exercisable
     at end of year        740,000   $      0.16             -   $      0.00
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


                    Options Outstanding            Options Exercisable
    -------------------------------------------------------------------------
                                 Weighted-
                                  Average   Weighted-               Weighted-
    Range of          Number    Remaining    Average       Number    Average
    Exercise     Outstanding  Contractual   Exercise  Exercisable   Exercise
    Prices       At 12/31/06         Life      Price  At 12/31/06      Price
    -------------------------------------------------------------------------
    $0.15          1,515,000    3.1 years      $0.15      730,000      $0.15
     0.50 - 0.60     825,000    3.1 years       0.50       10,000       0.59
     0.70 - 0.75      80,000    3.1 years       0.72            -          -
    -------------------------------------------------------------------------
    $0.15 - 0.75   2,420,000    3.1 years      $0.29      740,000      $0.16
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

        The Company records compensation expense over the vesting period
        based on the fair value of options granted to employees, directors
        and consultants. Unvested options as of December 31, 2006 vest
        872,500 in 2007 and 807,500 in 2008.

        The Company issued 895,000 stock options with an estimated fair value
        of $191,458 ($0.21 per option) using the Black-Scholes option pricing
        model with the following key assumptions in 2006:


        Weighted-average risk free interest rate (%)       4.13
        Dividend yield (%)                                 0.00
        Expected life (years)                               2.5
        Weighted-average volatility (%)                    63.1

    8.  COMMITMENTS

        Commencing February 1, 2005, the Company entered into a management
        agreement with Comstate (see Note 2). The management agreement
        consists of a monthly fee of $18,000 (2005 - $12,000) per month plus
        out of pocket costs, a fee of three percent of net earnings before
        income taxes, $250 per month per operated producing well and $150 per
        month per water injector well.

        For commitments entered into subsequent to December 31, 2006 please
        see Note 11.

    9.  FINANCIAL INSTRUMENTS

        Fair Values

        The Company's financial instruments included in the balance sheet are
        comprised of due from related party, accounts receivable and current
        liabilities. The fair values of these financial instruments
        approximate their carrying value due to the short-term maturity of
        those instruments.

        Credit Risk

        Substantially all of the Company's accounts receivable are due from
        customers in the oil and gas industry and are subject to normal
        industry credit risks. The carrying value of accounts receivable
        reflects management's assessment of associated credit risks.

        Commodity Price Risk

        The Company's operations and financial results may be affected by
        fluctuations in commodity prices and exchange rates.

        Currency Risk

        The Company is exposed to fluctuations in foreign currency as a
        result of its South American operations. The Company has not entered
        into any foreign currency derivatives with respect to this exposure.

    10. SEGMENTED INFORMATION

        The Company, with the incorporation of CanAmericas in February, 2006,
        has operations in Canada and South America; all operating activities
        are related to exploration, development and production of petroleum
        and natural gas as follows:

                                                         South
        ($)                               Canada       America         Total
        Twelve Months Ended
         December 31, 2006(1)
        Revenue, gross                   729,332        50,749       780,081
        Loss before non-controlling
         interest                        472,797       580,509     1,053,306
        Property and equipment         1,352,759        38,576     1,391,335
        Capital expenditures             226,163        45,763       271,926
        Total assets                   3,254,440     1,239,570     4,494,010

        (1) Prior to the incorporation of CanAmericas all of the Company's
            operations were in Canada and as such no prior period
            information has been provided.

    11. SUBSEQUENT EVENT - COMMITMENT

        Subsequent to December 31, 2006, the Company entered into two farm-in
        agreements in South America which require future expenditure
        commitments as outlined below:

        Canadon Ramirez Concession

        Pine Cliff through its 93 percent owned subsidiary, CanAmericas, has
        committed to pay 100% of costs totaling $5,500,000 US, including the
        21% Value Added Tax ("V.A.T."), for work to be conducted on the
        concession within two years to earn a 49% participating interest.

        Commitment by Year ($000's US)

        Year             Amount
        ----             ------
        2007              4,630
        2008                870
                         ------
                          5,500
                         ------
                         ------

        San Jorge Basin Permit

        Pine Cliff through its 93 percent owned subsidiary, CanAmericas, has
        committed to pay 100% of costs totalling $4,620,000 US including
        V.A.T. to earn a 60% participating interest in the entire permit.
        Commitment by Year ($000's US)

        Year             Amount
        ----             ------
        2007                300
        2008              2,595
        2009              1,725
                         ------
                          4,620
                         ------
                         ------
    

    %SEDAR: 00021536E




For further information:

For further information: Additional information relating to the Company
may be found on SEDAR.COM as well as on the Company's web sight at
www.pinecliffenergy.com or by contacting George F. Fink, President, and CEO or
Garth E. Schultz, Vice President - Finance, and CFO at (403) 269-2289 or by
fax at (403) 265-7488

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