Twin Butte Energy Reports Fourth Quarter & Year End 2007 Results



    CALGARY, March 20 /CNW/ -


    Highlights

    Twin Butte Energy Ltd. ("Twin Butte" or the "Company") (TSX: TBE) is
pleased to announce its financial and operational results for the three months
and year ended December 31, 2007.

    
    -------------------------------------------------------------------------
                    Three months ended         Year ended December 31
                       December 31
    -------------------------------------------------------------------------
                                            %                              %
                     2007        2006  Change       2007        2006  Change
    -------------------------------------------------------------------------
    Financial
    ($ thousands,
    except per
    share amounts)
    -------------------------------------------------------------------------
      Petroleum
       and natural
       gas sales     9,146       4,855    88%      29,941      11,149   168%
      Cash flow(1)   3,255       2,054    49%      12,226       4,504   171%
      Per share
       basic &
       diluted        0.12        0.11     9%        0.50        0.35    43%
      Net income
       (loss)(3)     4,272        (881)              (979)     (4,082)
      Per share
       basic &
       diluted        0.15       (0.05)             (0.04)      (0.44)
      Capital
       expenditures
       (net of
       dispositions) 3,671       9,581   (62%)     47,659      14,703   224%
      Corporate
       acquisitions      -           -                  -      49,093
      Net debt(2)   23,242      14,558    60%      23,242      14,558    60%
    -------------------------------------------------------------------------
    Operating
    -------------------------------------------------------------------------
    Average daily
     production
      Crude oil
       (bbl per day)   390         298    31%         351         183    92%
      Natural gas
       (Mcf per day) 9,022       4,499   100%       7,657       2,577   197%
      Natural gas
       liquids (bbl
       per day)        113          41   176%          76          20   280%
      Barrels of oil
       equivalent
       (boe per
       day, 6:1)     2,006       1,089    84%       1,703         632   169%
    Average sales
     price
      Crude oil
       ($ per bbl)   79.04       59.31    33%       73.22       67.84     8%
      Natural gas
       ($ per Mcf)    6.67        7.29    (8%)       6.68        6.57     2%
      Natural gas
       liquids
       ($ per bbl)   74.28       56.64    31%       75.98       62.06    22%
      Barrels of oil
       equivalent
       ($ per boe,
       6:1)          49.55       48.48    (2%)      48.16       48.33     -%
    Operating
     netback
     ($ per boe)
      Petroleum and
       natural gas
       sales         49.55       48.48     2%       48.16       48.33     -%
      Realized gain
       (loss) on
       financial
       instruments   (0.84)          -               0.88           -
      Royalties      (9.99)      (7.21)   39%       (9.74)      (7.86)   24%
      Operating
       Expenses     (12.89)     (11.38)   13%      (11.95)     (11.32)    6%
      Transportation
       Expenses      (2.54)      (2.77)   (8%)      (2.50)      (2.56)   (2%)
      Operating
       netback       23.29       27.12   (14%)      24.85       26.59    (7%)
    -------------------------------------------------------------------------
    Common Shares
    -------------------------------------------------------------------------
    Shares
     outstanding,
     end of
     period     27,752,398  19,275,398    44%  27,752,398  19,275,398    44%
    Weighted
     average
     shares
     outstanding
     - basic &
     diluted    27,752,398  19,054,887    46%  24,284,620  12,762,870    90%
    -------------------------------------------------------------------------
    (1) Cash flow means earnings before future taxes, depletion, depreciation
        and accretion, stock based compensation, and unrealized loss (gain)
        on financial derivative contracts. See Management's Discussion &
        Analysis Non-GAAP Measures.
    (2) Net debt at December 31, 2007 excludes financial derivative contracts
        asset and liability in the net amount of $0.6 million. The net
        liability relates to an unrealized loss on financial derivative
        contracts recognized at December 31, 2007.
    (3) Net income for the three month period ended December 31, 2007
        includes a non-cash future income tax recovery of $6.4 million.


    Report to Shareholders

    The year ended December 31, 2007 was another successful year in the
execution of the Company's growth and development strategy. Highlights for
2007 include the following:

    -   Achieved 2007 exit target production rate of 2,100 boe/d;

    -   Increased 2007 average production by 169 percent to 1,703 boe/d up
        from 632 boe/d in 2006;

    -   Increased production per share in 2007 by 42 percent;

    -   Achieved average production of 2,006 boe/d in the fourth quarter
        representing an 84 percent increase from the fourth quarter 2006
        average of 1,089 boe/d;

    -   Increased 2007 cash flow by 171 percent over 2006 to $12.2 million;

    -   Increased cash flow per share in 2007 by 43 percent to $0.50 per
        share over 2006;

    -   Drilled and cased 18 (14.8 net) wells with a 100 percent success rate
        for the year;

    -   Completed technical work for the first multi frac horizontal location
        in the 37.5 million bbl Jayar light oil pool which was spud in
        February of 2008;

    -   Targeted high quality gas acquisitions in a low price environment
        with favourable metrics at Thunder Alberta (90 percent gas) and in
        British Columbia pursuant to the acquisition of E4 Energy Inc. ("E4")
        (65 percent gas). The assets acquired in British Columbia will not be
        affected by recently announced royalty changes;

    -   Closed two equity financings for a total of $28.65 million which was
        applied to the financing of the Thunder acquisition and the 2007
        capital program positioning the Company with excellent financial
        flexibility;

    -   Significantly increased the Company's net undeveloped land base to
        58,000 net undeveloped acres at year end from approximately 26,000
        net undeveloped acres at year end 2006 which further grew to
        approximately 143,000 net undeveloped acres following the E4 closing
        in February 2008;

    -   Increased Twin Butte's prospect inventory to over 75 locations;

    -   Increased reserves by 60 percent to 6,046 MBOE (2P) from 3,788 MBOE
        (2P) at year end 2006;

    -   Increased reserves per share in 2007 by 9 percent;

    -   Realized finding, development and acquisition costs for 2007 of
        $16.55/boe for proved plus probable additions, or $17.21/boe with the
        inclusion of future capital changes; and

    -   Subsequent to year end and close of the E4 acquisition the Company's
        total credit facility was increased to $62.5 million, providing
        $19 million of unutilized credit capacity.
    

    Operational Review
    ------------------
    Twin Butte is pleased to report to shareholders on the Company's
activities in 2007.
    Since inception the Company has strived to build the depth of our
technical team and increase our undeveloped land base to build a strong
organic component for Twin Butte shareholders. We believe the Company has
taken a material step forward in that regard in 2007 and early 2008 and this
effort will yield significant growth to our investors as the Company moves
forward. While the year was characterized by eroding natural gas prices
Twin Butte remained focused on building the Company showing significant growth
in production and Company land as well as in our prospect inventory.
    In December, the Company continued to execute the Acquire, Exploit and
Explore business model announcing the acquisition of E4 Energy Inc. which
subsequently closed on February 8, 2008. This was another key building block
in the growth of the Company providing critical mass in our Plains core area
and a new focus area in Fort St John British Columbia which will be unaffected
by recently announced Alberta royalty changes. The Fort St John area brings
multi zone opportunities, all season access and a wealth of play types from
conventional targets to the developing Montney resource play.
    Subsequent to closing the E4 acquisition the Company has grown its land
base to approximately 143,000 net undeveloped acres. Additionally, the Company
significantly increased the Geological and Geophysical ("G&G") technical group
bringing on Glenn Downey from E4 as VP Exploration, together with three
additional G&G personnel. Collectively, this group brings significant
additional technical experience to the Company in the Canadian Sedimentary
basin. The new staff compliments existing G&G staff and positions the Company
with the manpower to fully exploit the increasing number of farm-in,
exploration and acquisition opportunities in the current market.

    Production and Drilling
    -----------------------
    The Company met its previously announced 2007 exit production target of
2100 boe/d and production for the year averaged 1,703 boe/d up from 632 boe/d
in 2006, representing an increase of 169 percent in average daily production
volumes. Fourth quarter production averaged 2,006 boe/d comprised of
75 percent natural gas and 25 percent light oil and natural gas liquids
representing an increase of 84 percent from the fourth quarter of 2006 average
of 1,089 boe/d.
    The Company completed a net capital program of $3.7 million in Q4,
drilling 4 gross (4 net) wells in the Bulwark area and 1 gross (0.5 net) well
in the Thunder area. In total the Company completed a capital program (net of
property acquisitions and dispositions) of $20.0 million drilling 18 gross
(14.8 net) wells in 2007.

    Plains Area
    -----------
    At Bulwark, the Company continued to develop a Viking light oil pool with
a multi well drilling program. The program resulted in a tripling of
production from the area from an initial rate of approximately 55 boe/d at the
beginning of the year to a 2007 exit rate of approximately 160 boe/d. Success
continued into the first quarter of 2008 with 2 additional exploratory wells
drilled in February. One well was cased as a development well, while the other
was cased as a new pool discovery. Both wells are anticipated to be on
production by late March.
    Subsequent to the closing of the E4 transaction, the Company completed
construction of a battery facility at Provost and has recently cased the first
2 horizontal wells in a step out drilling program targeting the Dina RR oil
pool. This pool contains an estimated 10 million bbls of Original Oil in Place
("OOIP"), with only 120,000 bbls recovered to date from vertical production
wells. The new battery and disposal facility will reduce trucking costs and
allow the wells to be produced in an optimized manner. Based on success from
the first round of drilling management believes there is potential for a multi
well development program of up to 10 wells for this property. Two wells are in
our current 2008 budget leaving significant room for additional drilling based
on success.

    Thunder Area
    ------------
    Twin Butte drilled and cased its first well in the Thunder core area in
Q4 which was tied in to the Company's operated gas facility. This well came on
production at a restricted net rate of approximately 100 boe/d in
mid December. Subsequent to year end a second well was cased in the area with
a completion slated for Q2, 2008. The Company continues to develop new
exploration leads and is active with Crown land postings and seismic work to
develop the new leads. Additional drilling is planned for the Thunder area in
2008 to test current prospects.

    Jayar Area
    ----------
    At Jayar, the Company completed a horizontal well technical study and
commenced planning for Twin Butte's first horizontal well into this high
quality large OOIP light oil pool. This first high impact horizontal well is
targeting the Dunvegan light oil pool utilizing the "Packers Plus" multi frac
technology. The Jayar Dunvegan pool is an 85.5 percent working interest, low
permeability reservoir that has been developed to date utilizing vertical
drilling and completion technology. Technical data indicates that recent
advancements in horizontal drilling and completion techniques utilized in the
Bakken tight oil pool in Saskatchewan, and the Montney tight gas play in
British Columbia, are applicable to the Dunvegan zone at Jayar. Successful
application of this new Packers Plus technology presents significant upside
potential to the Company with vertical well production to date recovering less
than 2 million barrels out of an estimated 37.5 million barrels OOIP. The
initial well was spud in February with completion work planned for late March
based on weather conditions.

    British Columbia
    ----------------
    In the Fort St. John core area, subsequent to closing the E4 acquisition,
the Company commenced project work for an upcoming multi well development and
exploration program slated to begin in Q3 of 2008.
    The Company has also actively pursued farm-in opportunities focusing on
lands with resource potential and has recently signed a farm-in deal on a
4 section land block targeting the Montney formation. Twin Butte plans to
drill an earning well in early Q3 that will continue rights to depth drilled
for a 5 year term in the entire 4 section block. The lands directly offset a
recent land sale where a bonus price of $3.9 million was paid for each
section. This places an equivalent net value on the farm-in lands alone of
$9.4 million. Montney pay from area offset wells average 76 m in thickness
giving a potential original gas in place (OGIP) reserve estimate of greater
than 64 BCF per section. The play has the potential to have a material impact
on the Company. The lands are located approximately 3.0 miles to tie in point
which should allow for timely development of production from the play.

    Outlook: 2008 Guidance - Continued Per Share Growth
    ---------------------------------------------------
    We continue to believe in the long term outlook for natural gas and feel
that our value based approach, and countercyclical thinking have positioned
the Company very well for continued growth in reserves, production and cash
flow per share. Management remains committed to building a solid foundation
from which the Company will grow, illustrated by the Company's key
characteristics as follows:

    
    -   Stable production base (greater than) 3,000boe/d;

    -   Reserves of 8.9 MMboe (P+P);

    -   A reserve life index of 7.8 years (P+P);

    -   Tax pools of approximately $180 million;

    -   Net undeveloped land totaling approximately 143,000 acres;

    -   Solid balance sheet with current net debt of approximately
        $43 million, and total credit facilities of $62.5 million;

    -   Significant light oil exploitation upside at Jayar, Bulwark and
        Provost;

    -   Exciting exploration and resource potential in British Columbia; and

    -   Significant drilling inventory of (greater than) 75 locations.
    

    The Company will continue to focus on core areas, adding to our inventory
of opportunities and growing our land base through Crown land sales, joint
ventures and farm-in opportunities. The management team and Board of Directors
remains focused on cost effective per share growth in reserves, production and
cash flow which will be achieved through exploration and exploitation of the
existing asset base and the integration of accretive acquisitions following
management's "acquire, exploit and explore" business strategy.
    The Board of Directors have recently approved an initial capital budget
of $27 million which will include the drilling of 26 gross (25.8 net) wells.
The Company has excellent prospects for 2008 including low risk oil and gas
development in South East Alberta, Thunder and Fort St. John British Columbia,
as well as, high impact exploration and development prospects at Fort St. John
and at Jayar. Capital is allocated with $21.5 million for drilling and
facilities, and $5.5 million for land and seismic.
    Based on this budget the Company expects to realize average production in
2008 of 3,150 boe/d with exit production greater than 3,350 BOE/d. This
represents an increase in average daily production of approximately 85 percent
over 2007.
    The capital spending level parallels the forecasted 2008 annual cash flow
of $26.5 million and year end debt of approximately $43.5 million,
representing 1.4 times fourth quarter 2008 annualized cash flow.
    For budget purposes for the year, the Company has used an average gas
price of $6.44/GJ ($6.76/Mcf) at AECO and an average oil price of
US$76.25/bbl WTI, with a exchange rate of 1.0 C$/US$.

    
    Twin Butte 2008 Guidance is summarized as follows:
    --------------------------------------------------

    Average production rate               3,150 BOE/d
    Exit production rate                  3,350 BOE/d
    Cash flow                             $26.5 million
    Cash flow per share                   $0.63
    Capital program                       $27 million
    Year end net debt                     $43.5 million
    Authorized Bank Line                  $62.5 million
    Unused bank line capacity             $19 million
    Current shares outstanding (basic)    43.4 million
    Current shares outstanding (diluted)  46.0 million
    

    During the course of 2007, Twin Butte's management has positioned the
Company both operationally and financially with excellent growth potential for
2008 and beyond. The Company has a solid reserve and production base, a strong
balance sheet and a significant tax pool advantage. This combination will
enable Twin Butte to effectively pursue management's "acquire, exploit and
explore" growth strategy. We are very excited about the Company's future
prospects.

    On behalf of the Board of Directors,

    Ron Cawston
    President and C.E.O.
    March 19, 2008

    Reserves

    McDaniel & Associates Consultants Ltd. ("McDaniel"), an independent
qualified reserves evaluator, was again retained to complete the December 31,
2007 reserve evaluation on 100% of Twin Butte's oil and gas reserves. The
report indicated 6,045.6 MBOE of Twin Butte working interest proved plus
probable reserves, up 60% from 3,788.3 MBOE at the end of 2006. Finding,
development and acquisition costs including future development capital and
revisions were $17.21 per boe on a proved plus probable basis for 2007.
    The following tables outline the Company's reserves as at December 31,
2007 as independently evaluated by McDaniel in accordance with National
Instrument 51-101 Standards of Disclosure of Oil and Gas Activities ("NI
51-101"). For the complete NI 51-101 disclosures please refer to the Company's
Annual Information Form which will be filed on SEDAR on or before March 31,
2007.

    
    Summary of Oil & Gas Reserves
    -------------------------------------------------------------------------
                                                                       Total
                            Proved         Total         Total   Proved plus
                         Producing        Proved      Probable      Probable
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    Light/Medium Oil
     (Mbbl)
    Working Interest         661.7         898.8         542.7       1,441.5
    Net After Royalty        621.2         834.5         501.0       1,335.6

    Natural Gas (MMcf)
    Working Interest      16,507.4      18,766.8       6,981.8      25,748.6
    Net After Royalty     13,030.9      14,702.3       5,465.5      20,167.8

    Natural Gas Liquids
     (Mbbl)
    Working Interest         209.9         237.0          75.6         312.6
    Net After Royalty        140.5         158.7          50.9         209.6

    Oil Equivalent (Mboe)
    Working Interest       3,622.8       4,263.6       1,782.0       6,045.6
    Net After Royalty      2,933.4       3,443.7       1,462.8       4,906.5
    -------------------------------------------------------------------------
    Before Tax Present
     Value ($M)
    -------------------------------------------------------------------------
    Discounted @
    0%                   102,186.6     112,736.7      53,939.2     166,675.9
    5%                    81,703.1      89,179.5      33,739.9     122,919.4
    10%                   69,601.5      74,814.3      23,957.8      98,772.1
    15%                   61,348.8      64,847.5      18,064.4      82,911.8
    -------------------------------------------------------------------------
    

    The Company increased the net present value of proved plus probable
reserves, discounted at 10% before tax, to $98.8 million, up 48% from
$66.6 million at December 31, 2006. The commodity prices forecast and used by
McDaniel in the report include a 2008 AECO hub spot gas price of C$6.45/GJ and
a 2008 WTI oil price of US$90.00/bbl.
    A significant portion of Twin Butte's 2007 capital program was devoted to
the conversion of probable reserves into proven reserves. As a result, total
proven reserves now comprise 71% of total proved plus probable reserves, as
compared to 61% at year-end 2006. Similarly, proved producing reserves now
comprise 60% of total proved plus probable reserves, as compared to 37% at
year-end 2006:

    
    Corporate Working Interest Reserves Reconciliation
    (Forecast Prices and Costs)

    Oil Equivalent (Mboe)                                   TP          TP+P
    -------------------------------------------------------------------------
    Opening Balance                                    2,314.0       3,788.2
    Extensions/Discoveries                               819.6       1,193.8
    Revisions                                            250.6        -221.9
    Acquisitions                                       1,521.5       1,933.6
    Dispositions                                         -20.4         -26.4
    Production                                          -621.7        -621.7
    Closing Balance                                    4,263.6       6,045.6
    -------------------------------------------------------------------------


    Finding, Development, and Acquisition Costs
                                                                 Proved plus
    Capital Costs ($MM)                                 Proved      Probable
    -------------------------------------------------------------------------
    Exploration & Development, with FDC                   27.1          21.9
    Acquisitions (net of Dispositions), with FDC          27.7          27.7
    Total Expenditures, with FDC                          54.8          49.5
    Total Change in FDC (discounted 10%)                   7.1           1.9
    -------------------------------------------------------------------------

                                                                 Proved plus
    FD&A Costs ($/boe)                                  Proved      Probable
    -------------------------------------------------------------------------
    Exploration & Development including capitalized
    G&A & Revisions, with FDC                            25.31         22.50
    All-in FD&A, with FDC                                21.29         17.21
    

    FD&A costs in 2007 were $21.29 per boe proved and $17.21 per boe proved
plus probable including FDC and revisions.
    Twin Butte's activities in 2007 replaced production by 413% on a total
proved basis and 462% on a proved plus probable basis.

    
    Reserve Life Index

                                                                 Proved plus
                                                        Proved      Probable
    -------------------------------------------------------------------------

    Total Company Interest Reserves (Mboe)               4,264         6,046
    Fourth quarter 2007 production (boe/d)               2,006         2,006
    RLI based on fourth quarter annualized
     production (years)                                    5.8           8.3
    -------------------------------------------------------------------------


    December 31, 2007 Net Asset Value per Fully Diluted Share Information

    Using Reserve Value at December 31, 2007 - Forecast Pricing and Costs:

                                                    5% Before     10% Before
    ($MM except share amounts)                            Tax            Tax
    -------------------------------------------------------------------------
    Proved Plus Probable Reserve Value                   122.9          98.8
    Undeveloped Land                                       8.7           8.7
    Tax Pools(1)                                           3.9           7.5
    Estimated Net Debt                                   -23.2         -23.2
    Total Net Assets                                     112.3          91.8
    Fully Diluted Shares Outstanding (MM)(2)              27.8          27.8
    Estimated Net Asset Value per Fully Diluted Share    $4.05         $3.31
    -------------------------------------------------------------------------

    (1) Tax pool valuation only for pools in excess of reserve NPV.
    (2) Antidilutive options using a December 31, 2007 closing share price of
        $2.20/share were excluded.
    

    On a comparative basis, the Company's net asset value per fully diluted
share at year-end 2007 increased 6.8% as compared to December 31, 2006.

    Certain information regarding the Company contained herein may constitute
forward-looking statements within the meaning of applicable securities laws.
Forward-looking statements may include estimates, plans, anticipations,
expectations, intentions, opinions, forecasts, projections, guidance or other
similar statements that are not statements of fact. Although the Company
believes that the expectations reflected in such forward-looking statements
are reasonable, it can give no assurance that such expectations will prove to
be correct. These statements are subject to certain risks and uncertainties
and may be based on assumptions that could cause actual results to differ
materially from those anticipated or implied in the forward-looking
statements. The Company's forward-looking statements are expressly qualified
in their entirety by this cautionary statement.
    In this news release, reserves and production data are commonly stated in
barrels of oil equivalent ("boe") using a six to one conversion ratio when
converting thousands of cubic feet of natural gas ("Mcf") to barrels of oil
("bbl") and a one to one conversion ratio for natural gas liquids ("NGLs" or
"ngls"). Such conversion may be misleading, particularly if used in isolation.
A boe conversion ratio of 6 Mcf: 1 bbl is based on energy equivalency
conversion method primarily applicable at the burner tip and does not
represent a value equivalency at the wellhead.

    Management's Discussion and Analysis

    Dated as of March 19, 2008

    The following discussion and analysis as provided by the management of
Twin Butte Energy Ltd. ("Twin Butte" or the "Company") should be read in
conjunction with the unaudited financial statements and management's
discussion and analysis for the year ended December 31, 2007 and the unaudited
financial statements for the three quarters ended March 31, 2007, June 30,
2007 and September 30, 2007.

    Basis of Presentation - The reporting and measurement currency is the
Canadian dollar.

    Non-GAAP Measures - The Management's Discussion and Analysis ("MD&A")
contains the term cash flow from operations or cash flow which should not be
considered an alternative to, or more meaningful than, cash flow from
operating activities as determined in accordance with Canadian generally
accepted accounting principles ("GAAP") as an indicator of the Company's
performance. All references to cash flow from operations or cash flow
throughout this report are based on cash flow from operating actives before
changes in non-cash working capital. The Company also presents cash flow from
operations per share whereby per share amounts are calculated using weighted
average shares outstanding consistent with the calculation of earnings per
share. These measures may not be comparable to other companies.

    boe Presentation - Barrels of oil equivalent ("boe") may be misleading,
particularly if used in isolation. A boe conversion rate of 6 Mcf: 1 bbl is
based on an energy equivalency conversion method primarily applicable at the
burner tip and does not represent a value equivalency at the wellhead. All boe
conversions in the report are derived by converting gas to oil at the ratio of
six thousand cubic feet of gas to one barrel of oil.

    Forward-Looking Information - Certain statements contained in this MD&A
constitute forward-looking information within the meaning of securities laws.
Forward-looking information may relate to our future outlook and anticipated
events or results and may include statements regarding the future financial
position, business strategy, budgets, projected costs, capital expenditures,
financial results, taxes and plans and objectives of or involving Twin Butte
Energy Ltd. Particularly, statements regarding our future operating results
and economic performance, are forward-looking statements. In some cases,
forward-looking information can be identified by terms such as "may", "will",
"should", "expect", "plan", "anticipate", "believe", "intend", "estimate",
"predict", "potential", "continue" or other similar expressions concerning
matters that are not historical facts.
    These statements are based on certain factors and assumptions regarding
expected growth, results of operations, performance and business prospects and
opportunities. While we consider these assumptions to be reasonable based on
information currently available to us, they may prove to be incorrect.
    Forward looking-information is also subject to certain factors, including
risks and uncertainties, that could cause actual results to differ materially
from what we currently expect. These factors include risk associated with oil
and gas exploration, production, marketing, and transportation such as loss of
market, volatility of commodity prices, currency fluctuations, imprecision of
reserve estimates, environmental risk, competition from other producers and
ability to access sufficient capital from internal and external resources.
    Other than as required under securities laws, we do not undertake to
update this information at any particular time.


    
    Petroleum and Natural Gas Sales

    Twin Butte realized the following production volumes, commodity prices and
revenues:

                             Three months ended              Year ended
                                 December 31                 December 31
    -------------------------------------------------------------------------
                              2007          2006          2007          2006
    -------------------------------------------------------------------------
    Average Twin Butte
     Realized Commodity
     Prices(1)
    Crude oil ($ per bbl)    79.04         59.31         73.22         67.84
    Natural gas ($ per Mcf)   6.67          7.29          6.68          6.57
    Natural gas liquids
     ($ per bbl)             74.28         56.64         75.98         62.06
    Barrels of oil
     equivalent
     ($ per boe, 6:1)        49.55         48.48         48.16         48.33
    (1) The average selling prices reported are before realized financial
        instrument gains/losses and transportation charges.


    Benchmark Pricing

    WTI crude oil (US$ per bbl)                          72.27         66.09
    WTI crude oil (Cdn$ per bbl)                         77.29         74.99
    AECO natural gas (Cdn$ per Mcf)(2)                    6.45          6.51
    Exchange rate - US$/Cdn$                             0.935         0.881
    (2) The AECO natural gas price reported is the average daily spot price.


    Revenue
    -------------------------------------------------------------------------
    $'s
    Crude oil            2,835,867     1,624,100     9,387,329     4,520,835
    Natural gas          5,539,760     3,016,495    18,667,325     6,177,856
    Natural gas liquids    770,320       214,880     1,886,755       450,958
    -------------------------------------------------------------------------
    Total petroleum and
     natural gas sales   9,145,947     4,855,475    29,941,409    11,149,649
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    Average Daily Production
    -------------------------------------------------------------------------

    Crude oil & natural
     gas liquids (bbl/day)     503           339           427           202
    Natural gas (Mcf/day)    9,022         4,499         7,657         2,577
    -------------------------------------------------------------------------
    Total (boe/d)            2,006         1,089         1,703           632
    -------------------------------------------------------------------------
    

    Revenues for the three months ended December 31, 2007 were $9.1 million,
as compared to $4.9 million for the three months ended December 31, 2006
representing an increase of $4.2 million or 88%. This increase in revenue is
attributed primarily to year over year fourth quarter production average
increasing by 84% to 2,006 boe/d in 2007 from 1,089 boe/d in 2006. The
increase in revenue is also partially attributed to a 2% increase in the
average realized commodity price from $48.48 per boe in 2006 to $49.55 in
2007.
    Revenues for the year ended December 31, 2007 were $29.9 million as
compared to $11.1 million in 2006, representing an increase of 168%. This
increase is due mainly to a 169% increase in yearly average production volumes
with comparable average realized prices in 2007 and 2006. The increase in year
over year volumes is partially related to the majority of the Company's
operations which did not commence until June 2006.
    The Company's weighting to natural gas for the fourth quarter of 2007 and
the year ended December 31, 2007 was 75%, compared to a weighting of 69% for
the fourth quarter of 2006 and 68% for the year ended December 31, 2006. The
increase in the Company's natural gas weighting is primarily the result of the
Thunder property acquisition completed in June 2007.

    Royalties

    Royalties for the three months ended December 31, 2007 were $1.8 million,
as compared to $0.7 million for the three months ended December 31, 2006. As a
percentage of revenues, the average royalty rate for the fourth quarter of
2007 was 20% compared to 15% for the comparative period of 2006. Royalties for
the year ended December 31, 2007 were $6.1 million, as compared to
$1.8 million for the year ended December 31, 2006. As a percentage of
revenues, the average royalty rate for the year ended December 31, 2007 was
20% compared to 16% for the comparative period of 2006.
    The increase in the average royalty rates for both the three months ended
and year ended December 31, 2007 compared to the same period in 2006, results
primarily from the elimination of the Alberta Royalty Tax Credit ("ARTC") in
2007 and slightly higher royalty rates associated with production acquired in
June 2007.

    Operating Expenses

    Operating expenses were $2.4 million or $12.89 per boe for the quarter
ended December 31, 2007 as compared to $1.1 million or $11.38 per boe for the
three months ended December 31, 2006. Operating expenses were $7.4 million or
$11.95 per boe for the year ended December 31, 2007 as compared to
$2.6 million or $11.32 per boe for the year ended December 31, 2006. Higher
operating costs in the Thunder area acquired in the June 2007 property
acquisition resulted in an increase in operating expenses on a per boe basis
in 2007. The Company is working to reduce these costs in 2008.

    Transportation Expenses

    Transportation expenses for the three months ended December 31, 2007 were
$0.5 million or $2.54 per boe compared to $0.3 million or $2.77 per boe in the
prior year comparative quarter. Transportation expenses for the year ended
December 31, 2007 were $1.6 million or $2.50 per boe compared to $0.6 million
or $2.56 per boe in the prior year. Increases in total transportation expenses
are the result of increases in production volumes but transportation expenses
on a per unit basis remain consistent.

    
    General and Administrative ("G&A") Expenses

                             Three months ended              Year ended
                                 December 31                 December 31
    -------------------------------------------------------------------------
                              2007          2006          2007          2006
    -------------------------------------------------------------------------
    G&A expenses         1,012,183       831,381     3,425,183     1,620,738
    Recoveries            (149,034)      (99,338)     (392,720)     (132,194)
    Capitalized G&A
     expenses             (181,029)     (212,431)     (718,965)     (379,609)
    -------------------------------------------------------------------------
    Total net G&A
     expenses              682,120       519,612     2,313,498     1,108,935
    -------------------------------------------------------------------------
    

    General and administrative expenses, net of recoveries and capitalized
G&A, were $0.7 million, or $3.70 per boe for the current quarter as compared
to $0.5 million or $5.19 per boe in the prior year comparative quarter.
General and administrative expenses, net of recoveries and capitalized G&A,
were $2.3 million, or $3.72 per boe for the year ended December 31, 2007 as
compared to $1.1 million or $4.81 per boe for the year ended December 31,
2006. The increase in G&A costs is directly attributable to increased office
and staffing costs. However, with the increased production volumes the Company
has realized a reduction in general and administrative expenses on a per boe
basis. Management anticipates further reduction in general and administrative
expenses on a per boe basis in 2008.

    Stock Based Compensation Expense

    During the three month period ended December 31, 2007, the Company
expensed $0.2 million in stock based compensation as compared to $1.6 million
in the three month period ended December 31, 2006. Stock based compensation
expense amounts to $0.6 million for the year ended December 31, 2007 compared
to $3.8 million for the year ended December 31, 2006. The reduction in stock
based compensation expense in 2007 compared to 2006 is the result of all stock
based compensation expense relating to management warrants issued in 2006
being recognized in 2006. Stock based compensation expense in 2007 relates
only to outstanding stock options.

    Interest Expense

    For the three months ended December 31, 2007, interest expense was
$0.4 million, an increase of $0.3 million from $0.1 million for the prior year
comparative quarter. For the year ended December 31, 2007, interest expense
was $0.9 million compared to $0.5 million for the year ended December 31,
2006. Higher interest costs in the fourth quarter and the year ended
December 31, 2007 are due to higher average debt levels. Bank indebtedness
levels have increased primarily as a result of a $28 million property
acquisition in June 2007.

    Unrealized Loss on Financial Derivative Contracts and Realized Gain on
    Financial Derivatives

    On January 1, 2007, the Company adopted new accounting standards for
financial instruments and hedging. Accordingly, realized and unrealized gains
on commodity derivative contracts are recognized in the current period. See
note 1 of the financial statements for a description of the new accounting
policies.
    During 2007, the Company entered into fixed price swap and costless
collar contracts for natural gas and oil. As part of our financial management
strategy, Twin Butte has adopted a disciplined commodity price risk management
program. The purpose of the program is to reduce volatility in the financial
results and to stabilize and hedge future cash flow against the unpredictable
commodity price environment.
    The Company has recognized a realized loss on financial derivatives in
the amount of $0.2 million for the three month period ended December 31, 2007
and a realized gain of $0.5 million for the year ended December 31, 2007.
    The following is a summary of all natural gas sales price derivative
contracts in effect as at December 31, 2007:


    
    Daily quantity
    per giga-joule                                               Fixed price
    ("GJ")                 Remaining term of contract           per GJ (AECO)
    -------------------------------------------------------------------------

    2,000 GJ           January 1 to December 31, 2008                  $6.50
    2,500 GJ              April 1 to October 31, 2008                  $6.45
    1,000 GJ           January 1 to December 31, 2008                  $6.64

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

    Subsequent to year end the Company entered into an additional gas hedge
for the period of April 1, 2008 to October 31, 2008 on 1,000 GJ/d at a fixed
price of $7.075/GJ (AECO).
    The following is a summary of all oil sales price derivative contracts in
effect as at December 31, 2007:

    
    Daily quantity
    per barrel       Remaining term of     Fixed price       Costless Collar
    ("bbl")                   contract    per bbl (WTI)         per bbl (WTI)
    -------------------------------------------------------------------------

    100 bbl         January 1 to             US $70.65
                     December 31, 2008
    60 bbl          January 1 to             US $87.25
                     December 31, 2007
    60 bbl          January 1 to                                 US $88.00 -
                     March 31, 2008                               US $100.50

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

    Subsequent to year end the Company entered into an additional oil hedge
for the period of April 1, 2008 to Decemer 31, 2008 on 100 bbl/d at a costless
collar per bbl (WTI) range of US $90.00 to US $120.00.
    In accordance with the new accounting standards for financial instruments
and hedging, the Company has calculated the fair value of the above contracts
and recorded an unrealized asset on financial derivative contracts in the
amount of $0.3 million and a liability on financial derivative contracts in
the amount of $0.8 million as at December 31, 2007.

    Depletion, Depreciation and Accretion Expense

    For the three month period ended December 31, 2007, depletion and
depreciation of capital assets and the accretion of the asset retirement
obligations was $4.8 million or $25.69 per boe compared to $3.1 million or
$30.87 per boe for the three month period ended December 31, 2006. For the
year ended December 31, 2007, depletion and depreciation of capital assets and
the accretion of the asset retirement obligations was $18.6 million or $29.48
per boe compared to $7.9 million or $33.87 per boe for the year ended
December 31, 2006.
    The increase in depletion, depreciation and accretion expense for the
three months ended and year ended December 31, 2007 as compared to the same
periods in 2006 is due to higher production volumes, but reflects a decrease
in costs on a per unit basis. Per unit costs have decreased in 2007 when
compared to 2006 due to proven reserve additions at a lower cost than historic
depletion, depreciation and accretion expense per boe.

    Income Taxes

    Future income tax recovery amounted to $6.4 million for the three month
period ended December 31, 2007 compared to a future income tax recovery in the
amount of $1.8 million for the three month period ended December 31, 2006. For
the year ended December 31, 2007, future income tax recovery amounted to
$6.6 million compared to a future income tax recovery of $3.1 million for the
prior year comparative period. The increased recognition of future income tax
recovery in 2007 is primarily the result of increases in the Company's
forecasted future cash flow which allows the Company to recognize the future
benefit of its existing tax pools.
    The Company has existing tax losses and pools of approximately
$160.4 million of which $61.3 million are non-capital losses and the Company
has no current tax expense. Based on current reserve forecasts the Company
will be able to realize the benefit of the majority of the non-capital losses.

    Cash Flow from Operations, and Net Income (Loss) and Comprehensive Income
    (Loss)

    Cash flow from operations for the three month period ended December 31,
2007 was $3.3 million, an increase of 58% from fourth quarter 2006 cash flow
of $2.1 million. Cash flow per share basic and diluted amounted to $0.12 for
the fourth quarter of 2007, an increase from $0.11 in the fourth quarter of
2006. Cash flow from operations for the year ended December 31, 2007 was
$12.2 million, an increase of 171% from the year ended December 31, 2006 cash
flow of $4.5 million. This represents an increase of 43% in cash flow per
share basic and diluted to $0.50 per share for 2007 compared to $0.35 per
share for 2006.
    The Company posted net income and comprehensive income of $4.3 million
for the three month period ended December 31, 2007, equating to a basic and
diluted net income per share of $0.15, compared to a net loss and
comprehensive loss of $0.9 million for the three month period ended
December 31, 2006, equating to a basic and diluted net loss per share of
$0.05. Net loss and comprehensive loss for the year ended December, 2007 was
$1.0 million, or $0.04 per share basic and diluted, compared to a net loss and
comprehensive loss for the prior year comparative period of $4.1 million, or
$0.32 per share basic and diluted.
    The net loss and comprehensive loss of $1.0 million for the year ended
December 31, 2007 includes non cash items including depletion, depreciation
and accretion expense of $18.6 million, future income tax recovery of
$6.6 million, unrealized loss on financial derivative contracts of
$0.6 million, and stock based compensation expense of $0.6 million.
    The following table summarizes netbacks for the past six quarters on a
barrel of oil equivalent basis:

    
                        Q4 2007  Q3 2007  Q2 2007  Q1 2007  Q4 2006  Q3 2006

    -------------------------------------------------------------------------
    ($ per boe)
    -------------------------------------------------------------------------
    Petroleum and natural
     gas sales            49.55    42.91    51.38    50.76    48.48    47.45
    Royalties             (9.99)   (9.08)  (10.52)   (9.55)   (7.21)   (7.91)
    Realized gain
     (loss) on financial
     instruments          (0.84)    3.07     0.93        -        -        -
    Operating expenses   (12.89)  (11.86)  (10.96)  (11.73)  (11.38)  (11.76)
    Transportation
     expenses             (2.54)   (2.47)   (2.31)   (2.69)   (2.77)   (2.40)
    -------------------------------------------------------------------------
    Operating netback     23.29    22.57    28.52    26.79    27.12    25.38
    General and
     administrative
     expenses             (3.70)   (3.19)   (4.25)   (4.03)   (5.19)   (4.30)
    Interest expense      (1.96)   (2.07)   (0.77)   (0.47)   (1.42)   (1.76)
    -------------------------------------------------------------------------
    Cash flow from
     operations           17.63    17.31    23.51    22.29    20.51    19.32
    -------------------------------------------------------------------------
    

    The Company's first fully operational quarter of activity was the three
month period ended September 30, 2006.

    Quarterly Financial Summary

    The following table highlights Twin Butte's performance for the past six
quarters:

    
                       Dec. 31, Sep. 30, June 30, March 31, Dec. 31, Sep. 30,
                          2007     2007     2007      2007     2006     2006
    -------------------------------------------------------------------------
    ($ thousands,
    except per share
    amounts)
    -------------------------------------------------------------------------
    Average production
     (boe/d)             2,006    2,042    1,445     1,309    1,089    1,047
    Petroleum and
     natural gas sales   9,146    8,060    6,755     5,981    4,855    4,569
    Operating netback
     (per boe)           23.29    22.57    28.52     26.79    27.12    25.38

    Cash flow from
     operations          3,255    3,254    3,091     2,626    2,054    1,861
    Per share basic
     & diluted            0.12     0.12     0.14      0.13     0.11     0.10

    Net income (loss)    4,272   (4,818)   3,483    (3,915)    (881)  (2,267)
    Per share basic
     & diluted            0.15    (0.18)    0.16     (0.19)   (0.07)   (0.13)

    Capital expenditures
     (net of
     dispositions)       3,671    3,615   31,981     8,391    9,581    4,666
    Total assets       120,151  112,804  116,389    81,899   78,697   67,060
    Net debt excluding
     financial
     derivative
     contracts
     liability          23,242   22,823   38,042     9,001   14,558    7,517
    -------------------------------------------------------------------------
    

    Capital Expenditures

    During 2007, the Company invested $47.7 million (net of dispositions)
with the drilling of 18 gross wells (14.8 net) for a success rate of 100
percent. Included in capital expenditures is the Thunder (West Central
Alberta) property acquisition completed June 28, 2007 for $28.1 million. The
following tables summarizes capital expenditures, drilling results and
undeveloped land positions for 2007 and 2006.

    
    Capital Expenditures     Three months ended              Year ended
    ($ thousands)                December 31                 December 31
    -------------------------------------------------------------------------
                              2007          2006          2007          2006
    -------------------------------------------------------------------------
    Land acquisition             -           188         1,633           574
    Geological and
     geophysical               329            82           895         1,106
    Drilling and
     completions             1,821         6,997        10,167         7,860
    Equipping and
     facilities              1,551         2,101         6,504         2,336
    Property acquisitions     (267)          (30)       28,137         2,403
    Property dispositions        -             -          (466)            -
    Other                      237           241           788           425
    -------------------------------------------------------------------------
    Total net capital
     expenditures            3,671         9,581        47,659        14,703
    -------------------------------------------------------------------------


    Drilling Results

    -------------------------------------------------------------------------
    Year ended December 31           2007                       2006
    -------------------------------------------------------------------------
                             Gross           Net         Gross           Net
    -------------------------------------------------------------------------
    Crude oil                  9.0           7.5           6.0           5.0
    -------------------------------------------------------------------------
    Natural gas                9.0           7.3           4.0           4.0
    -------------------------------------------------------------------------
    Dry and abandoned            -             -             -             -
    -------------------------------------------------------------------------
    Total                     18.0          14.8          10.0           9.0
    -------------------------------------------------------------------------
    Success rate (%)                        100%                        100%
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
    Three months ended
    December 31                      2007                       2006
    -------------------------------------------------------------------------
                             Gross           Net         Gross           Net
    -------------------------------------------------------------------------
    Crude oil                  3.0           3.0           3.0           2.6
    -------------------------------------------------------------------------
    Natural gas                2.0           1.5           4.0           4.0
    -------------------------------------------------------------------------
    Dry and abandoned            -             -             -             -
    -------------------------------------------------------------------------
    Total                      5.0           4.5           7.0           6.6
    -------------------------------------------------------------------------
    Success rate (%)                        100%                        100%
    -------------------------------------------------------------------------


    Undeveloped Land

    -------------------------------------------------------------------------
    Year ended December 31                                2007          2006
    -------------------------------------------------------------------------
    Gross Acres                                         78,769        32,760
    -------------------------------------------------------------------------
    Net Acres                                           57,896        26,324
    -------------------------------------------------------------------------
    

    Liquidity and Capital Resources

    At December 31, 2007, the Company had net debt of $23.2 million,
excluding financial derivative contracts asset in the amount of $0.3 million
and financial derivative contracts liability in the amount of $0.8 million
relating to unrealized gains and losses on financial derivative contracts
recognized at December 31, 2007. The Company has a total credit facility with
a Canadian chartered bank in the amount of $40.0 million. The credit facility
is composed of a $32.5 million demand revolving operating credit facility and
a $7.5 million acquisition and development credit facility. Subsequent to year
end, the total credit facility has been increased to $62.5 million in relation
to the acquisition of E4 Energy Inc that was completed in February 2008.

    Share Capital

    On May 31, 2007, the Company consolidated its share capital on a 1:5
basis. All share and per share amounts have been restated to reflect this
share consolidation.
    On February 27, 2007, the Company closed a bought deal private placement
of 2,927,000 flow-through Common Shares at a price of $4.10 per share, for
gross proceeds of $12,000,700 ($11,300,734 net of share issue costs).
    On July 17, 2007, the Company closed a bought deal private placement of
5,550,000 Common Shares at a price of $3.00 per share, for gross proceeds of
$16,650,000 ($15,588,744 net of share issue costs). The proceeds were used to
repay debt incurred in relation to the property acquisition that was completed
June 28, 2007.
    Subsequent to year end, on February 8, 2008, the Company closed the
acquisition of E4 Energy Inc. ("E4"), a publicly traded company for total
consideration of approximately $55.6 million, before closing adjustments
(based on a Company share price of $2.45) and transaction costs and including
net debt of approximately $17.2 million. The Company issued 15,663,027 common
shares to the former shareholders of E4.
    As of March 19, 2008 the Company currently has 43,415,425 Common Shares
and 2,579,000 stock options outstanding.

    Contractual Obligations

    The issuance of flow through shares in February 2007 for proceeds of
$12.0 million will require the Company to spend $12.0 million of flow-through
share eligible Canadian Exploration Expenditures, as defined in the Canadian
Income Tax Act, by December 31, 2008. As at December 31, 2007 the Company has
incurred approximately $2.9 million of this commitment.
    The Company has other commitments and guarantees in the normal course of
business, consisting of an office space lease and equipment rentals which are
not considered material.

    Related Party Transactions

    During the year and during which time a former director was related to a
professional firm, the Company expensed and capitalized legal fees totaling
$159 thousand for services rendered by that professional firm. The fees were
incurred in the normal course of business and recorded at the exchange amount.
    During the year the Company incurred costs totaling $815 thousand for
services rendered by companies in which a director of Twin Butte is an officer
and a director. These costs were incurred in the normal course of business and
recorded at the exchange amount.

    Newly Adopted Accounting Policies

    On January 1, 2007, the Company adopted the new CICA Handbook sections
3855 - Financial Instruments - Recognition and Measurement, 3861 - Financial
Instruments - Disclosure and Presentation, 3865 - Hedges, and 1530 -
Comprehensive Income. The newly adopted accounting policies are disclosed in
the notes to the financial statements. There were no other significant
accounting policies newly adopted during the year ended December 31, 2007.

    Critical Accounting Estimates

    Management is required to make judgments and use estimates in the
application of generally accepted accounting principles that have a
significant impact on the financial results of the Company.

    Full Cost Accounting

    The Company follows the Canadian Institute of Chartered Accountants'
guideline on full cost accounting in the oil and gas industry to account for
oil and gas properties. Under this method, all costs associated with the
acquisition of, exploration for and development of natural gas and crude oil
reserves are capitalized and costs associated with production are expensed.
The capitalized costs are depreciated, depleted and amortized using the
unit-of-production method based on estimated proved reserves. Reserve
estimates can have a significant impact on earnings, as they are a key
component in the calculation of depreciation, depletion and accretion
("DD&A"). A downward revision in a reserve estimate could result in a higher
DD&A charge to earnings. In addition, if net capitalized costs are determined
to be in excess of the calculated ceiling, which is based largely on reserve
estimates, the excess must be written off as a expense and charged against
earnings. In the event of a property disposition, proceeds are normally
deducted from the full cost pool without recognition of a gain or loss unless
there is a change in the DD&A rate of 20 percent or greater.

    Asset Retirement Obligations

    The Company records a liability for the fair value of legal obligation
associated with the retirement of long-lived tangible assets in the period in
which they are incurred, normally when the asset is purchased or developed. On
recognition of the liability there is a corresponding increase in the carrying
amount of the related asset and the asset retirement obligation. The total
amount of asset retirement obligation is an estimate based on the Company's
net ownership interest in all wells and facilities and the estimated costs to
abandon and reclaim the wells and facilities and the estimated timing of the
costs to be incurred in the future periods. The total amount of the estimated
cash flows required to settle the asset retirement obligation; the timing of
those cash flows are estimates subject to measurement uncertainty. Any changes
in these estimates would impact the asset retirement liability.

    Reserves Determination

    The proved crude oil, natural gas and natural gas liquid reserves used in
determining our depletion rates, the magnitude of the borrowing base available
to us from our lender and the ceiling test are based upon management's best
estimates, and are subject to uncertainty. Through the use of geological,
geophysical and engineering data, the reservoirs and deposits of natural gas,
crude oil and natural gas liquids are examined to determine quantities
available for future production, given existing operating and economic
conditions and technology. The evaluation of recoverable reserves is an
ongoing process impacted by current production, continuing development
activities and changing economic conditions as reflected in crude oil and
natural gas prices and costs. Consequently, the reserves are estimates which
are subject to variability. To assist with the reserve evaluation process, we
employ the services of independent oil and gas reservoir engineers.

    Income Taxes

    The determination of the Company's income and other tax liabilities
require interpretation of complex laws and regulations often involving
multiple jurisdictions. All tax filings are subject to audit and potential
reassessment after lapse of considerable time. Accordingly, the actual income
tax liability may differ significantly from the liability estimated or
recorded.

    Other Estimates

    The accrual method of accounting requires management to incorporate
certain estimates including estimates of revenues, royalties and production
costs as at a specific reporting date, but for which actual revenues and costs
have not yet been received, and estimates on capital projects which are in
progress or recently completed where actual costs have not been received at a
specific reporting date.

    Ceiling Test

    Under the full cost accounting method, a ceiling test is performed at
least annually to ensure that the net capitalized costs in each country do not
exceed the undiscounted future net revenues from proved reserves, plus the
cost of unproved properties. Any excess capitalized costs will be written off
as an expense and charged to earnings; however, future depletion and
depreciation expense would be reduced.

    Update on Regulatory Matters

    On October 25, 2007, the Alberta government announced the New Alberta
Royalty Framework which proposes changes to the current royalty regime in
Alberta. These proposed changes, at prices in effect at January 1, 2008, are
not expected to have a material impact Twin Butte's corporate royalty rate.

    Outlook

    The Company continues to believe in the longer term outlook for natural
gas prices due to improving supply and demand fundamentals and the relative
valuation of natural gas compared to crude oil. When this is combined with the
execution of key "gas weighted" acquisitions in 2007 the Company is positioned
to deliver significant growth per share to Twin Butte shareholders.
    The business combination with E4 Energy on February 8, 2008 was a key
building block in the Company's growth increasing the Company prospect
inventory and significantly increasing the undeveloped land base to
approximately 143,000 net undeveloped acres. The E4 acquisition brings a large
oil in place reservoir with significant development potential to our existing
Plains area and an exciting new core area in N.E. British Columbia. The N.E.
British Columbia assets are characterized by high working interest, multi zone
opportunities and resource play opportunities that add significant growth
potential to the Company.
    For 2008 the board of directors of Twin Butte have approved a capital
program of $27 million which parallels forecast 2008 funds from operations of
$26.5 million ($0.63/share). The Company anticipates drilling 26 wells during
the year with approximately $5.5 million allocated to land and seismic that
will ensure continued expansion of our prospect inventory. Average production
for 2008 is forecast to be approximately 3,150 boe/d with exit production in
excess of 3,350 boe/d.
    The management team and Board of Directors remain focused on per share
growth in reserves, production and cash flow which will be achieved through
exploration and exploitation of the existing asset base and the integration of
accretive acquisitions following management's "acquire, exploit and explore"
business strategy.
    Twin Butte has an experienced management team, a solid reserve and
production base, a strong balance sheet and a significant tax pool advantage.
In 2008, management will continue to employ a disciplined approach that will
take advantage of our expanded opportunity base and focus on per share value
creation for our shareholders. The Company is positioned both operationally
and financially with excellent growth potential for 2008 and beyond.

    Assessment of Business Risks

    The following are the primary risks associated with the business of Twin
Butte. These risks are similar to those affecting other companies competing in
the conventional oil and natural gas section. Twin Butte's financial position
and results of operations are directly impacted by these factors and include:

    
    Operational risk associated with the production of oil and natural gas:

    -   Reserve risk in respect to the quantity and quality of recoverable
        reserves;
    -   Exploration and development risk of being able to add new reserves
        economically;
    -   Market risk relating to the availability of transportation systems to
        move the product to market;
    -   Commodity risk as crude oil and natural gas prices fluctuate due to
        market foces;
    -   Financial risk such as volatility of the Canadian/US dollar exchange
        rate, interest rates and debt service obligations;
    -   Environmental and safety risk associated with well operations and
        production facilities;
    -   Changing government regulations relating to royalty legislation,
        income tax laws, incentive programs, operating practices and
        environmental protection relating to the oil and natural gas
        industry; and
    -   Continued participation of Twin Butte's lenders.

    Twin Butte seeks to mitigate these risks by:

    -   Acquiring properties with established production trends to reduce
        technical uncertainty as well as undeveloped land with development
        potential;
    -   Maintaining a low cost structure to maximize product netbacks and
        reduce impact of commodity price cycles;
    -   Diversifying properties to mitigate individual property and well
        risk;
    -   Maintaining product mix to balance exposure to commodity prices;
    -   Conducting rigorous reviews of all property acquisitions;
    -   Monitoring pricing trends and developing a mix of contractual
        arrangements for the marketing of products with creditworthy
        counterparties;
    -   Maintaining a hedging program to hedge commodity prices with
        creditworthy counterparties;
    -   Adhering to the Company's safety program and adhering to current
        operating best practices;
    -   Keeping informed of proposed changes in regulations and laws to
        properly respond to and plan for the effects that these changes may
        have on our operations;
    -   Carrying industry standard insurance; and
    -   Establishing and maintaining adequate resources to fund future
        abandonment and site restoration costs.
    

    Future Accounting Policy Changes

    The CICA issued the new accounting standard; Section 1535 capital
disclosures which takes effect on January 1, 2008. Section 1535 specifies the
disclosure of an entity's objectives, policies and processes for managing
capital, quantitative data about what it manages as capital, any externally
imposed capital requirements, and the consequences of non-compliance. This
section is expected to have minimal impact on the Company's financial
statements. The Company has implemented these disclosures in the 2007 year end
financial statements.
    The CICA issued the new accounting standard; Section 3862, financial
instruments disclosures and section 3863, financial instrument presentation
which takes effect on January 1, 2008. These sections require the Company to
increase disclosure on the nature, extent and risk arising from the financial
instruments and how the Company manages those risks.

    Internal Control Reporting

    In March 2006 Canadian Securities Administrators decided to not proceed
with proposed multilateral instrument 52-111 "Reporting on Internal Controls
over Financial Reporting" and instead proposed to expand multilateral
instrument 52-109 "Certification of Disclosure in Issuers' Annual and Interim
Fillings." The major changes resulting from this are that the Chief Executive
Officer and Chief Financial Officer will be required to certify in the annual
certificates that they have evaluated the effectiveness of internal controls
over financial reporting ("ICOFR") as of the end of the financial year and
disclose in the annual MD&A their conclusions about the effectiveness of
ICOFR. There will be no requirement to obtain an internal control audit
opinion from the issuer's auditors concerning management's assessment of the
effectiveness of ICOFR. There is also no requirement to design and evaluate
internal controls against an external control framework. This proposed
amendment is expected to apply for the year ended December 31, 2009. Twin
Butte is continuing with its evaluation of ICOFR to ensure it meets the
criteria for the proposed certification of December 31, 2009.
    To ensure sound corporate governance, we continue to commit ourselves to
establishing and maintaining adequate disclosure controls and procedures, as
well as internal control over financial reporting in order to provide
reasonable assurance regarding the reliability of our financial disclosure,
and ultimately, maintaining our clients' trust and investors' confidence.

    Disclosure Controls and Procedures and Internal Control Over Financial
    Reporting

    Twin Butte has implemented a system of internal controls that it believes
adequately protects the assets of the Company and is appropriate for the
nature of its business and the size of its operations. These internal controls
include disclosure controls and procedures designed to ensure that information
required to be disclosed by the Company is accumulated and communicated to
management as appropriate to allow timely decisions regarding required
disclosure. The Company's Chief Executive Officer (CEO) and Chief Financial
Officer (CFO) have concluded, based on their evaluation that Twin Butte's
disclosure controls and procedures are effective to provide reasonable
assurance that material information related to the Company is made known to
them and have been operating effectively. It should be noted that while the
Company's CEO and CFO believe that Twin Butte's disclosure controls and
procedures provide a reasonable level of assurance that the system of internal
controls are effective, they do not guarantee that the disclosure controls and
procedures will prevent all errors and fraud. A control system, no matter how
well conceived or operated, can provide only reasonable, not absolute,
assurance that the objectives of the control system are met.
    In addition, in accordance with Multilateral Instrument 52-109, the
Company has, under the supervision of its CEO and CFO, designed a process of
internal control over financial reporting, which has been affected by the
Company's board of directors and management. The process was designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in
accordance with Canadian generally accepted accounting principles ("GAAP").
    Based on the CEO and the CFO's review of the design of internal controls
over financial reporting, the CEO and CFO have concluded that the design of
internal controls is adequate for the nature of the Corporation's business and
size of its operations. As a small organization, and similar to other small
organizations, the Company's management is composed of a small number of key
individuals, resulting in a situation where limitations on the segregation of
duties as well as expertise in such areas as complex calculations and
estimations do not exist, as such these risks are compensated by more
effective supervision and monitoring by the CEO and CFO as well as reliance on
third party expertise where appropriate. It is important to note that in order
to eliminate the potential risk associated with these issues the Company would
be required to hire additional staff in order to provide greater segregation
of duties and expertise in certain areas. Since the increased costs of such
hiring would be financially constrictive to Twin Butte, the Corporation has
chosen to disclose the potential risk in its annual filings and proceed with
increased staffing as the Company's growth supports such overhead expansion.

    Additional Information

    Additional information relating to Twin Butte, including Twin Butte's AIF
and financial statements (to be filed before March 31, 2008) can be found on
SEDAR at www.sedar.com.

    
    TWIN BUTTE ENERGY LTD
    Balance Sheets (unaudited)

    -------------------------------------------------------------------------
                                                   December 31   December 31
                                                          2007          2006
    -------------------------------------------------------------------------

    Assets

    Current Assets
      Accounts receivable                         $  5,727,286  $  4,554,362
      Deposits and prepaid expenses                    558,263       606,175
      Financial derivative contracts (note 9)          266,898             -
    -------------------------------------------------------------------------
                                                     6,552,447     5,160,537

    Future income taxes (note 7)                     9,164,477     2,029,400

    Property and equipment (note 3)                104,433,701    71,506,633

    -------------------------------------------------------------------------
                                                  $120,150,625  $ 78,696,570
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Liabilities and Shareholders' Equity

    Current Liabilities
      Accounts payable and accrued liabilities    $  8,278,779  $ 13,399,101
      Bank indebtedness (note 4)                    21,248,583     6,318,985
      Financial derivative contracts (note 9)          827,135             -
    -------------------------------------------------------------------------
                                                    30,354,497    19,718,086

    Asset retirement obligation (note 5)             6,945,541     3,073,325

    -------------------------------------------------------------------------
                                                    37,300,038    22,791,411

    Shareholders' Equity
      Share capital (note 6)                        93,722,668    66,397,721
      Contributed surplus (note 6)                   1,014,991       415,713
      Deficit                                      (11,887,072)  (10,908,275)
    -------------------------------------------------------------------------
                                                    82,850,587    55,905,159

    -------------------------------------------------------------------------
                                                  $120,150,625  $ 78,696,570
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Commitments (note 10)

    See accompanying notes to financial statements



    TWIN BUTTE ENERGY LTD
    Statements of Income (Loss), Comprehensive Income (Loss) and Deficit
    (unaudited)

    -------------------------------------------------------------------------
                              Three Months Ended
                                 December 31          Year Ended December 31
                              2007          2006          2007          2006
    -------------------------------------------------------------------------

    Revenue:
      Petroleum and
       natural gas
       sales          $  9,145,947  $  4,855,475  $ 29,941,409  $ 11,149,649
      Royalties         (1,843,787)     (722,516)   (6,057,074)   (1,812,873)
      Realized (loss)
       gain on
       financial
       derivatives        (154,511)            -       545,552             -
      Unrealized loss
       on financial
       derivative
       contracts
       (note 9)           (401,267)            -      (560,237)            -
    -------------------------------------------------------------------------
                         6,746,382     4,132,959    23,869,650     9,336,776

    Expenses:
      Operating          2,379,065     1,139,496     7,429,785     2,612,084
      Transportation       468,823       277,845     1,552,291       590,699
      General and
       administrative      682,120       519,812     2,313,498     1,108,935
      Stock based
       compensation        151,804     1,644,167       599,278     3,819,663
      Interest             362,471       141,795       908,788       520,604
    -------------------------------------------------------------------------
      Depletion,
       depreciation
       and accretion     4,813,044     3,122,048    18,603,817     7,878,607
    -------------------------------------------------------------------------
                         8,857,327     6,845,163    31,407,457    16,530,592

    -------------------------------------------------------------------------
    Loss before
     income taxes       (2,110,945)   (2,712,204)   (7,537,807)   (7,193,816)

    Income taxes
      Future tax
       recovery         (6,383,038)   (1,831,487)   (6,559,010)   (3,111,945)
    -------------------------------------------------------------------------
                        (6,383,038)   (1,831,487)   (6,559,010)   (3,111,945)

    -------------------------------------------------------------------------
    Net income (loss)
     and comprehensive
     income (loss)       4,272,093      (880,717)     (978,797)   (4,081,871)

    Deficit, beginning
     of period         (16,159,165)  (10,027,558)  (10,908,275)   (6,826,404)

    -------------------------------------------------------------------------
    Deficit, end of
     period           $(11,887,072) $(10,908,275) $(11,887,072) $(10,908,275)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    Basic & diluted
     loss per share   $       0.15  $      (0.05) $      (0.04) $      (0.32)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Weighted average
     common shares
     outstanding
      Basic             27,752,398    19,054,887    24,284,620    12,762,870
      Diluted           27,752,398    19,054,887    24,284,620    12,762,870

    See accompanying notes to financial statements



    TWIN BUTTE ENERGY LTD
    Statements of Cash Flows (unaudited)


    -------------------------------------------------------------------------
                              Three Months Ended
                                 December 31          Year Ended December 31
                              2007          2006          2007          2006
    -------------------------------------------------------------------------

    Cash provided by
     (used in):

    Operations:
      Net income
       (loss)         $  4,272,093  $   (880,717) $   (978,797) $ (4,081,871)
      Items not
       involving
       cash:
        Depletion,
         depreciation
         and accretion   4,813,044     3,122,048    18,603,817     7,878,607
        Future income
         taxes          (6,383,038)   (1,831,487)   (6,559,010)   (3,111,945)
        Unrealized loss
         on financial
         derivative
         contracts         401,267             -       560,237             -
        Stock based
         compensation      151,804     1,644,167       599,278     3,819,663
    -------------------------------------------------------------------------
                         3,255,170     2,054,011    12,225,525     4,504,454
      Changes in
       non-cash
       working
       capital             125,552    (2,697,272)    1,562,268    (4,081,809)
    -------------------------------------------------------------------------
                         3,380,722      (643,261)   13,787,793       422,645

    Financing:
      Change in
       bank debt           452,825       771,644    14,929,598    (5,126,820)
      Issuance of
       share capital,
       net of share
       issue costs          (2,580)      485,942    26,748,879    13,021,809
      Changes in
       non-cash
       working
       capital                   -        37,354             -             -
    -------------------------------------------------------------------------
                           450,245     1,294,940    41,678,477     7,894,989
    -------------------------------------------------------------------------
    Investing:
      Expenditures on
       property and
       equipment        (3,670,959)   (9,580,622)  (48,124,391)  (14,703,138)
      Acquisition
       expenditures              -             -             -    (8,252,364)
      Proceeds on
       disposition of
       property and
       equipment                 -             -       465,721             -
      Changes in
       non-cash
       working
       capital            (160,008)    8,928,943    (7,807,600)   11,012,281
    -------------------------------------------------------------------------
                        (3,830,967)     (651,679)  (55,466,270)  (11,943,221)

    -------------------------------------------------------------------------
    Decrease in cash
     and cash
     equivalents                 -             -             -    (3,625,587)

    Cash and cash
     equivalents,
     beginning of
     period                      -             -             -     3,625,587
    -------------------------------------------------------------------------

    Cash and cash
     equivalents,
     end of period    $          -  $          -  $          -  $          -
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Cash interest
     paid             $    354,206  $    291,673  $    898,768  $    553,054


    See accompanying notes to financial statements



    Notes to Financial Statements - December 31, 2007

    Twin Butte Energy Ltd. ("Twin Butte" or the "Company") is engaged in the
    acquisition of, exploration for, and development of petroleum and natural
    gas properties in Western Canada. On February 3, 2004, a Plan of
    Arrangement was completed involving Twin Butte (formerly AltaRex Corp.),
    AltaRex Medical Corp., and Nova Bancorp Investments Ltd. Pursuant to the
    Arrangement, Twin Butte was transformed into an oil and gas exploration
    and production company.

    Certain of the comparative amounts have been reclassified to conform to
    the presentation adopted in the current period.

    1.  SIGNIFICANT ACCOUNTING POLICIES

    These financial statements have been prepared by management in accordance
    with accounting principles generally accepted in Canada. As such, the
    precise determination of many assets, liabilities, revenues and expenses
    are dependent on future events, the preparation of financial statements
    for a period necessarily includes the use of estimates and approximations
    which have been made using careful judgment. Actual results could differ
    from the estimates. These financial statements have, in management's
    opinion, been properly prepared within reasonable limits of materiality
    and within the framework of the accounting policies summarized below.

    Summary of significant accounting policies:

        a) Oil and gas operations

           i)    Capitalization of costs

           The Company follows the full-cost method of accounting for oil and
           natural gas properties whereby all costs of acquisition,
           exploration and development of petroleum and natural gas reserves
           are capitalized and accumulated in a single cost centre
           representing the Company's activity undertaken exclusively in
           Canada. Such costs include land acquisition costs, geological and
           geophysical expenses, lease rentals costs on non-producing
           properties, costs of drilling both productive and non-productive
           wells, related production equipment costs, and overhead charges
           directly related to these activities.

           Proceeds received on the disposition of oil and gas properties are
           credited against property and equipment except when the
           disposition results in a change in the depletion rate of the 20%
           or more, in which case a gain or loss is recognized.

           Office and computer equipment are depreciated using the straight
           line method ranging between three and five years.

           ii)   Depletion and depreciation

           Capitalized costs, excluding costs related to unproven reserves
           and salvage values, are depleted and depreciated using the unit-of
           -production method based on the estimated gross proven oil and
           natural gas reserves before royalties as determined by independent
           engineers. Oil and natural gas reserves are converted on an energy
           equivalent basis.

           iii)  Ceiling test

           Petroleum and natural gas assets are evaluated on an annual basis
           to determine that the costs are recoverable and do not exceed the
           fair value of the properties (the "ceiling test"). The costs are
           assessed to be recoverable if the sum of the undiscounted cash
           flows expected from the production of proved reserves and the
           lower of cost and fair value of unproved properties exceed the
           carrying value of the petroleum and natural gas assets. If the
           carrying value of the petroleum and natural gas is not assessed to
           be recoverable, an impairment loss is recognized to the extent
           that the carrying value exceeds the sum of the discounted cash
           flows expected from the production of proved and probable reserves
           and the lower of cost and fair value of unproved properties. The
           cash flows are estimated using future commodity prices and costs
           and are discounted using the Company's risk-free rate.

        b) Asset retirement obligations

              The Company records the fair value of an asset retirement
              obligation ("ARO") as a liability in the period in which it
              incurs a legal obligation associated with the retirement of
              long-lived assets that result from the acquisition,
              construction and development of the assets. The associated
              asset retirement costs are capitalized as part of the carrying
              amount of the long-lived asset and depleted and depreciated
              using a unit of production method over estimated proved
              reserves. The recorded ARO increases over time through
              accretion charges to earnings. Revisions to the estimated
              amount and timing of the obligations are reflected as increases
              or decreases to the ARO. Actual asset retirement expenditures
              are charged to the ARO to the extent of the recorded liability
              with any difference recorded as a gain or loss in the period in
              which settlement occurs.

        c) Joint operations

              A portion of the company's exploration and development
              activities are conducted jointly with others. Accordingly, the
              financial statements reflect only the company's proportionate
              interest in such activities.

        d) Flow-through common shares

              The Company has financed a portion of its exploration and
              development activities through the issuance of flow-through
              common shares. Under the terms of the flow-through shares, the
              income tax attributes of the related expenditures are renounced
              to the subscribers. To recognize the foregone tax benefits to
              the Company, the flow-through shares issued are recorded net of
              the tax benefits when renouncement documents are filed with the
              tax authorities.

        e) Foreign currency translation

              Monetary assets and liabilities denominated in foreign
              currencies are translated at exchange rates in effect at the
              balance sheet date. Non-monetary assets and liabilities
              denominated in foreign currencies are translated at rates in
              effect on the dates the assets were acquired or liabilities
              were assumed. Revenues and or losses on these items are
              included in the statements of operations.

        f) Income taxes

              The Company follows the liability method of income tax
              allocation. Under this method, future income taxes are
              recognized for the future income tax consequences attributable
              to differences between the carrying values of assets and
              liabilities and their respective income tax basis. Future
              income tax assets and liabilities are measured using
              substantively enacted income tax rates expected to apply to
              taxable income in the years in which temporary differences are
              expected to be recovered or settled. The effect on future
              income tax assets and liabilities of a change in rates is
              included in earnings in the period that includes the date of
              substantial enactment. Future income tax assets are recorded in
              the financial statements if realization is considered more
              likely than not.

        g) Stock-based compensation and other stock-based payments

              The Company grants stock options to executive officers,
              directors, employees and consultants pursuant to a stock option
              plan. Awards of stock options granted to employees, officers
              and directors are accounted for in accordance with the fair
              value method and result in compensation expense. The expense is
              recognized in income over the shorter of the service period of
              the employees to whom the option was granted or the vesting
              period of the specific option. The corresponding credit is
              recorded as a contributed surplus. Any consideration paid on
              the exercise of stock options and the corresponding value
              previously recorded to contributed surplus is credited to share
              capital.

        h) Per share information

              Basic per share amounts are calculated using the weighted
              average number of common shares outstanding during the period.
              Diluted per share amounts are calculated adjusting the weighted
              average number of shares for the dilutive effect of options,
              using the treasury stock method. Under this method, the
              dilutive effect of options uses proceeds received on the
              exercise of options plus the unamortized portion of stock-based
              compensation to purchase common shares at the average price
              during the period. The weighted average number of shares
              outstanding is then adjusted by the net change.

        i) Financial instruments

              On January 1, 2007, the Company adopted the new CICA Handbook
              sections 3855 - Financial Instruments - Recognition and
              Measurement, 3861 - Financial Instruments - Disclosure and
              Presentation, 3865 - Hedges, and 1530 - Comprehensive Income.
              The financial instruments standard establishes the recognition
              and measurement criteria of financial assets, financial
              liabilities and derivatives. All financial instruments are
              required to be measured at fair value on initial recognition of
              the instrument, except for certain related party transactions.
              Measurement in subsequent periods depends on whether the
              financial instrument has been classified as held-for-trading,
              available-for-sale, held-to-maturity, loans and receivables, or
              other financial liabilities as defined by the standard.

              Financial assets and financial liabilities held-for-trading are
              measured at fair value with changes in those fair values
              recognized in net earnings (loss). Financial assets available-
              for-sale are measured at fair value, with changes in those fair
              values recognized in other comprehensive income (loss).
              Financial assets held-to-maturity, loans and receivables and
              other financial liabilities are measured at amortized cost
              using the effective interest method of amortization.

              The Company has no financial instruments or activities that
              give rise to other comprehensive income (loss). The Company's
              cash and cash equivalents are designated as held-for-trading
              and are measured at carrying value, which approximates fair
              value due to the short-term nature of these instruments.
              Accounts receivable are designated as loans and receivables.
              Accounts payable and accrued liabilities and bank indebtedness
              are designated as other liabilities. The adoption of these new
              standards had no effect on the Company's 2006 financial
              statements.

        j) Cash and cash equivalents

              Cash and cash equivalents consist of cash and term deposits
              with a maturity date of three months or less.

        k) Revenue recognition

              Revenue associated with the sale of crude oil and natural gas
              are recognized when title passes to the purchaser.

        l) Measurement uncertainty

              Management is required to make estimates and assumptions that
              affect the reported amounts of assets and liabilities and the
              disclosure of contingent assets and liabilities as at the date
              of the financial statements and the reported amounts of revenue
              and expenses. The amounts recorded for depletion and
              amortization of petroleum and natural gas properties and
              equipment and the provision for future asset retirement
              obligation costs are based on estimates. The ceiling test is
              based on estimates of proved reserves, production rates, future
              oil and gas prices, future costs and other relevant
              assumptions. The amounts recorded for future taxes are based on
              estimates of future taxable income and anticipated income tax
              rates. The fair value of stock options is based on estimates
              using the Black-Scholes option pricing model and is recorded as
              stock-based compensation expense in the financial statements.
              By their nature, these estimates are subject to measurement
              uncertainty and the effect on the financial statements of
              changes in such estimates in future periods could be
              significant.

        m) Future accounting changes

              The CICA issued three new accounting standards, section 1535
              "Capital Dislcosures", section 3862 "Financial Instruments -
              Disclosures", and section 3863 "Financial Instruments -
              Presentation". These standards become effective for the Company
              in the first quarter of 2008.

              Section 1535 requires the disclosure of the Company's
              objectives, policies and processes for managing capital. This
              includes qualitative information regarding the Company's
              objectives, policies and processes for management of capital
              and quantitative data about what the Company manages as
              capital. These disclosures are based on information that is
              provided internally by the Company's key management. The
              Company has provided these disclosures in the 2007 financial
              statements (note 6).

              Sections 3862 and 3863 replace section 3861 "Financial
              Instruments - Disclosure and Presentation" which revises and
              enhances financial instruments disclosure requirements and
              leaves unchanged its presentation requirements. These new
              sections place increased emphasis on disclosures about the
              nature and extent of risks arising from financial instruments
              and how the Company manages those risks.

    2.  ACQUISITION EXPENDITURES

    On June 1, 2006, the Company closed the amalgamation agreements dated
    April 1, 2006 with Drilcorp Energy Ltd. ("Drilcorp") and Kerogen
    Petroleum Ltd. ("Kerogen") to acquire all the issued and outstanding
    shares of Drilcorp and Kerogen. Twin Butte indirectly acquired each of
    Drilcorp and Kerogen by creating two wholly-owned subsidiaries that
    amalgamated with Drilcorp and Kerogen, respectively. The two wholly-owned
    subsidiaries were subsequently wound up into Twin Butte such that Twin
    Butte owns all assets formerly owned by Drilcorp and Kerogen.

    The purchase price paid by Twin Butte for all of Drilcorp's shares was a
    total of 3,926,009 common shares of Twin Butte and $7,856,597. The
    purchase price paid by Twin Butte for all of Kerogen's shares was a total
    of 2,878,434 common shares of Twin Butte.

    The acquisition was accounted for using the purchase method of accounting
    as follows:

    Consideration

        ---------------------------------------------------------------------
                                        Drilcorp       Kerogen         Total
        ---------------------------------------------------------------------

        Shares                      $ 23,569,792  $ 17,270,567  $ 40,840,359
        Cash                           7,856,597             -     7,856,597
        Transaction costs                255,123       140,644       395,767
        ---------------------------------------------------------------------

        Total consideration         $ 31,681,512  $ 17,411,211  $ 49,092,723


    Purchase Price at Fair Value

        ---------------------------------------------------------------------
                                        Drilcorp       Kerogen         Total
        ---------------------------------------------------------------------

        Petroleum and natural gas
         properties                 $ 44,784,967  $ 18,823,624  $ 63,608,591
        Future income tax asset          131,236       138,939       270,175
        Net working capital
         deficiency                  (11,477,777)   (1,245,954)  (12,723,731)
        Asset retirement obligation   (1,756,914)     (305,398)   (2,062,312)
        ---------------------------------------------------------------------

        Total purchase price        $ 31,681,512  $ 17,411,211  $ 49,092,723

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

    The net working capital deficiency consists of the following:

        ---------------------------------------------------------------------
                                        Drilcorp       Kerogen         Total
        ---------------------------------------------------------------------

        Accounts receivable         $  3,292,113  $    856,979  $  4,149,092
        Deposits and prepaid
         expenses                        331,961        54,436       386,397
        Accounts payable and
         accrued liabilities          (4,443,943)   (1,369,472)   (5,813,415)
        Bank indebtedness            (10,657,908)     (787,897)  (11,445,805)
        ---------------------------------------------------------------------

        Net working capital
         deficiency                 $(11,477,777) $ (1,245,954) $(12,723,731)
        ---------------------------------------------------------------------

    3.  PROPERTY AND EQUIPMENT

    -------------------------------------------------------------------------
                                                   December 31,  December 31,
                                                          2007          2006
                                     Accumulated
                                             Net           Net
                                     Depletion &          Book          Book
                              Cost  Depreciation         Value         Value
    -------------------------------------------------------------------------

    Petroleum and
     natural gas
     properties       $130,494,240  $ 26,142,186  $104,352,054  $ 71,468,938
    Office and
     computer
     equipment             114,260        32,613        81,647        37,695
    -------------------------------------------------------------------------

    Total             $130,608,500  $ 26,174,799  $104,433,701  $ 71,506,633
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    The Company has capitalized $718,965 of general and administrative
    expenses directly related to exploration and development activities for
    the year ended December 31, 2007 ($379,609 - December 31, 2006).

    The cost of undeveloped property excluded from the depletion base as at
    December 31, 2007 was $8,158,643 ($5,630,449 - December 31, 2006). Future
    development costs on proved reserves of $13,457,000 as at December 31,
    2007 are included in the calculation of depletion and depreciation
    ($5,785,700 - December 31, 2006).

    The Company performed a ceiling test calculation as at December 31, 2007
    to assess the recoverable value of the property and equipment. The oil
    and gas future price is based on the January 1, 2008 commodity price
    forecast of the Company's independent reserve evaluators. The Company had
    no impairment under the December 31, 2007 year end ceiling test.

    For calculation of the December 31, 2007 ceiling test, the benchmark
    prices used were as follows:

                                       Oil                       Natural Gas
                        Edmonton Par Price                     AECO - C Spot
                          40 API CAD $/bbl                       CAD $/MMbtu
    -------------------------------------------------------------------------
    2008                             89.00                              6.81
    2009                             85.70                              7.39
    2010                             82.20                              7.39
    2011                             78.50                              7.39
    2012                             77.40                              7.49
    2013                             76.20                              7.70
    2014                             77.70                              7.97
    2015                             79.30                              8.23
    2016                             80.80                              8.44
    2017                             82.50                              8.70
    2018                             84.10                              8.92

    % increase thereafter            2.00%                             2.00%
    -------------------------------------------------------------------------

    4.  BANK INDEBTEDNESS

    As at December 31, 2007, the Company had a $40.0 million demand revolving
    credit facility with a Canadian chartered bank. The credit facility
    provides that advances may be made by way of direct advances, banker's
    acceptances, or standby letters of credit/guarantees. The credit facility
    is composed of a $32.5 million demand revolving operating credit facility
    and a $7.5 million acquisition and development credit facility. Interest
    rates on the demand revolving operating credit facility fluctuate based
    on a pricing grid and range from bank prime to bank prime plus 2.0%,
    depending upon the Company's then current debt to cash flow ratio of
    between less than one times to greater than three times. A debt to cash
    flow ratio of less than one times has interest payable at the bank's
    prime lending rate. A debt to cash flow ratio greater than three times
    has interest payable at the bank's prime lending rate plus 2.0%. Advances
    on the acquisition and development credit facility bear interest at the
    bank's prime lending rate plus 0.25%. The credit facility is secured by a
    demand debenture and a general security agreement covering all assets of
    the Company.

    In addition, the Company had secured a $5.5 million bridge loan in June
    2007 to finance a property acquisition. Interest on the loan is payable
    at the bank's prime lending rate plus 1.00%. In July 2007 the bridge loan
    was repaid and cancelled.

    Subsequent to year end (note 11) and in conjunction with the acquisition
    of E4 Energy Inc. ("E4") the demand revolving operating credit facility
    was increased to $55.0 million resulting in a total credit facility
    increase to $62.5 million.

    5.  ASSET RETIREMENT OBLIGATIONS

    Asset retirement obligations are based on the Company's net ownership in
    wells and facilities, and management's estimate of future costs to
    abandon and reclaim those wells and facilities as well as an estimate of
    the future timing of the costs to be incurred.

    The Company has estimated the present value of its total asset retirement
    obligation to be $6,945,541 at December 31, 2007, based on a total future
    liability of $12,192,840. Payments to settle asset retirement obligations
    occur over the operating lives of the underlying assets, estimated to be
    from 1 year to 19 years with the majority of the costs to be incurred
    between 2008 and 2016. A credit-adjusted risk free rate of eight percent
    and an inflation rate of two percent were used to calculate the present
    value of the asset retirement obligation.

    Changes to the asset retirement obligation are as follows:

                                                     Year Ended   Year Ended
                                                    December 31, December 31,
                                                           2007         2006
    -------------------------------------------------------------------------
    Asset retirement obligation, beginning of year  $ 3,073,325  $         -

    Liabilities incurred                                540,749       76,481
    Acquisitions                                      3,521,094    2,062,312
    Liabilities related to property dispositions        (35,940)           -
    Revisions in estimated cash outflows               (403,449)     876,988
    Accretion of asset retirement obligation            249,762       57,544
    -------------------------------------------------------------------------

    Asset retirement obligation, end of year        $ 6,945,541  $ 3,073,325
    -------------------------------------------------------------------------


    6.  SHARE CAPITAL

    Authorized

    An unlimited number of voting Common Shares and an unlimited number of
    Preferred Shares.

    Issued
    -------------------------------------------------------------------------
                                                      Number of
                                                         shares       Amount
    -------------------------------------------------------------------------
    Common Shares

    Balance, December 31, 2005                        3,556,269  $ 5,713,339

    Issued on conversion of convertible demand notes  2,464,686    4,770,984

    Issued pursuant to exercise of flow-through
     share warrants for cash                          1,400,000    3,010,000

    Issued pursuant to private placement for cash     3,400,000    6,800,000

    Issued pursuant to acquisitions (note 2)          6,804,443   40,840,359

    Issued pursuant to exercise of management
     warrants for cash                                1,650,000    3,300,000

    Contributed surplus related to management
     warrants exercised                                       -    3,403,950

    Tax effect of 2005 flow through share issue                   (1,352,720)

    Share issue and financing costs net of tax                -      (88,191)

    -------------------------------------------------------------------------
    Balance, December 31, 2006                       19,275,398  $66,397,721
    -------------------------------------------------------------------------

    Issued pursuant to private placement of
     flow-through shares                              2,927,000   12,000,700

    Issued pursuant to private placement of
     common shares                                    5,550,000   16,650,000

    Share issue and financing costs net of tax                -   (1,325,753)

    -------------------------------------------------------------------------
      Balance, December 31, 2007                     27,752,398  $93,722,668
    -------------------------------------------------------------------------

    Common Share Consolidation

    On May 31, 2007, the Company consolidated its share capital on a 1:5
    basis. All Common Share, stock options, and per share amounts have been
    restated to reflect this share consolidation.

    Issue of Common Shares

    On June 7, 2006, the Company amended and restated its articles and
    converted the previously issued and outstanding non-voting Common Shares
    of the Company to voting Common Shares on a one for one basis.
    Accordingly, all Common Shares are disclosed as voting Common Shares.

    On February 3, 2004, the Company issued $4,770,985 10% demand notes,
    convertible into non-voting, common shares of the Company at a ratio of
    517 non-voting shares per $1,000 or principle outstanding. The fair value
    of the equity component of these notes associated with the conversion
    option has been estimated to be $nil. The convertible demand notes were
    converted to 2,464,686 Common Shares of the Company in March 2006.

    At December 31, 2005, a total of 1,400,000 warrants ("warrants") to
    acquire Common Shares at an exercise price of $2.15 per share were
    outstanding. The warrants were issued pursuant to a private placement of
    flow- through shares with an expiry of December 31, 2006. All warrants
    were exercised in 2006.

    During the second quarter of 2006 the Company pursuant to a private
    placement issued 3.4 million Common Shares at a price of $2.00 per share
    for gross proceeds of $6.8 million.

    On February 27, 2007 the Company closed a bought deal private placement
    of 2,927,000 flow-through Common Shares at a price of $4.10 per share,
    for gross proceeds of $12,000,700 ($11,300,734 net of issue costs).
    Pursuant to the flow-through share offering, Twin Butte is committed to
    incur $12,000,700 of qualifying resource expenditures prior to
    December 31, 2008 (note 11). Twin Butte will renounce the qualifying
    resource expenditures to holders of the flow-through shares effective on
    or before December 31, 2007. The future income tax effect and reduction
    to share capital will be accounted for in the first quarter of 2008, the
    date that the Company has filed the renouncement documents with tax
    authorities.

    On July 17, 2007 the Company closed a bought deal private placement of
    5,550,000 Common Shares at a price of $3.00 per share, for gross proceeds
    of $16,650,000 ($15,588,744 net of issue costs).

    Management Warrants

    The Company has issued 1.65 million warrants ("management warrants") that
    are registered in the name of Twin Butte Energy Ltd. and are held
    pursuant to the terms of an employee benefit trust. Each management
    warrant entitles the holder to acquire one Common Share at an exercise
    price of $2.00 per share with each management warrant expiring
    December 31, 2006. The warrants are to be exercised at the discretion of
    the Company within 10 business days of notice to exercise.

    The management warrants and the Common Shares to be acquired on exercise
    of the management warrants are to be held pursuant to a private escrow
    agreement and the Common Shares on exercise of the management warrants
    will remain registered in the name of the Company. The Common shares are
    to be released from escrow with 50% of the Common Shares released May 31,
    2007 and the remaining 50% on May 31, 2008.

    All management warrants were exercised during 2006.

    Management of Capital Structure

    Since inception of the Company in 2004 as an oil and gas exploration and
    production company, $130.6 million has been incurred in capital
    expenditures and acquisitions (net of dispositions of $0.5 million). This
    has been funded by cash flow from operations (before changes in non-cash
    working capital) of $16.2 million, the issuance of new equity of
    $88.0 million and increased bank debt and working capital of
    $26.4 million.

    The Company's objective when managing capital is to maintain a flexible
    capital structure which will allow it to execute on its capital
    investment program, which includes investing in oil and gas activities
    which may or may not be successful. Therefore the Company continually
    strives to balance the proportion of debt and equity in its capital
    structure to take into account the level of risk being incurred in its
    capital expenditures.

    In the management of capital, the Company includes share capital and
    total debt (defined as the sum of current assets, current liabilities and
    bank debt) in the definition of capital.

    The key measures that the Company utilizes in evaluating its capital
    structure are total debt to cash flow from operating activities (before
    changes in non-cash working capital) and the current credit available
    from its creditors in relation to the Company's budgeted capital program.
    Total debt to cash flow from operating activities (before changes in non-
    cash working capital) is calculated as total debt divided by cash flow
    from operating activities (before changes in non-cash working capital)
    and represents the time period it would take to pay off the debt if no
    further capital expenditures were incurred and if cash flow from
    operating activities (before changes in non-cash working capital) stayed
    constant. At December 31, 2007 total debt excluding financial derivative
    contracts asset and liability was $23.2 million and cash flow from
    operating activities (before changes in non- cash working capital) for
    the year ended December 31, 2007 was $12.2 million, resulting in a total
    debt to cash flow from operations (before changes in non- cash working
    capital) ratio of 1.9. Annualized fourth quarter 2007 cash flow from
    operating activities (before changes in non-cash working capital) was
    $13.2 million, resulting in a total debt excluding financial derivatives
    contracts asset and liability to cash flow from operating activities
    (before changes in non-cash working capital) ratio of 1.8. Both of these
    ratios are in an acceptable range for the Company.

    The Company manages its capital structure and makes adjustments by
    continually monitoring its business conditions, including; the current
    economic conditions; the risk characteristics of the underlying assets;
    the depth of its investment opportunities, forecasted investment levels;
    the past efficiencies of our investments; the efficiencies of the
    forecasted investments and the desired pace of investment; current and
    forecasted total debt levels; current and forecasted natural gas prices
    and other factors that influence natural gas prices and cash flow from
    operating activities (before changes in non-cash working capital), such
    as foreign exchange and basis differential.

    In order to maintain or adjust the capital structure, the Company will
    consider: its forecasted debt to forecasted cash flow from operating
    activities (before changes in non-cash working capital) ratio while
    attempting to finance an acceptable investment program including
    incremental investment and acquisition opportunities; the current level
    of bank credit available from the bank syndicate; the level of bank
    credit that may be obtainable from its banking syndicate as a result of
    natural gas reserve growth; the availability of other sources of debt
    with different characteristics than the existing bank debt; the sale of
    assets; limiting the size of the investment program and new common equity
    if available on favorable terms. During 2007, the Company's strategy in
    managing its capital was unchanged from the prior year.

    Stock Options

    The following table sets forth a reconciliation of stock option plan
    activity through to December 31, 2007:

                                         Number of Options  Weighted Average
                                                              Exercise Price
    -------------------------------------------------------------------------

    Outstanding at December 31, 2005                     -               $ -
    Granted                                      1,575,000              4.00
    Forfeited                                     (110,000)             4.00
    -------------------------------------------------------------------------
    Outstanding at December 31, 2006             1,465,000             $4.00
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Granted                                        840,000              2.93
    Forfeited                                     (500,000)             4.00
    -------------------------------------------------------------------------
    Outstanding at December 31, 2007             1,805,000             $3.15
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    There were 321,667 options exercisable as at December 31, 2007 at an
    average exercise price of $3.99 per share. The 1,805,000 options
    outstanding at December 31, 2007 have a weighted average remaining
    contractual life of 3.98 years.

    Stock Based Compensation

    The Company accounts for its stock based compensation plan using the fair
    value method. Under this method, a compensation cost is charged over the
    vesting period for options or warrants granted to employees, consultants,
    officers, and directors with a corresponding increase to contributed
    surplus.

    The following table reconciles the Company's contributed surplus balance.

                                                     Year Ended   Year Ended
                                                    December 31, December 31,
                                                           2007         2006
    -------------------------------------------------------------------------
    Contributed surplus balance at beginning
     of year                                        $   415,713  $         -

    Stock based compensation for stock options
     granted                                            599,278      415,713
    Stock based compensation for management warrants          -    3,403,950
    Transfer to share capital on exercise of
     management warrants                                      -   (3,403,950)

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

    Contributed surplus balance at end of year      $ 1,014,991  $   415,713
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    The fair value of each option granted is estimated on the date of grant
    using the Black-Scholes option pricing model with assumptions and
    resulting values for grants for the year ended December 31 as follows:

                                                              2007      2006
    -------------------------------------------------------------------------

    Expected volatility                                        50%       50%
    Risk free rate of return                                  4.5%      4.5%
    Expected stock option life                             3 years   3 years
    Dividend yield rate                                       0.0%      0.0%
    Weighted average fair value of stock option grants       $1.12     $1.50
    Weighted average fair value of warrant grants                -     $2.05
    -------------------------------------------------------------------------

    Earnings Per Share

    The following table sets forth the details of the denominator used for
    the computation of basic and diluted earnings per share:

                                Three months ended         Year ended
                                    December 31            December 31
    -------------------------------------------------------------------------
                                    2007        2006        2007        2006
    -------------------------------------------------------------------------

    Weighted average number
     of basic shares          27,752,398  19,054,887  24,284,620  12,762,870
    Effect of dilutive
     securities:
      Employee stock options           -           -           -           -
      Management warrants              -           -           -           -
      Flow-through warrants            -           -           -           -
    -------------------------------------------------------------------------
    Weighted average number
     of diluted shares        27,752,398  19,054,887  24,284,620  12,762,870
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    All of the issued stock options were excluded from the calculation of
    diluted weighted average shares outstanding as to include them would be
    anti- dilutive.

    7.  TAXES

    Tax Expense

    The combined provision for taxes in the statement of operations and
    retained deficit reflects an effective tax rate which differs from the
    expected statutory tax rate. Differences were accounted for as follows:

                                                           2007         2006
    -------------------------------------------------------------------------

    Loss before taxes                               $(7,537,807) $(7,193,816)
    Statutory income tax rate                            32.12%       34.50%
    Expected income taxes                            (2,421,144)  (2,481,867)
      Non-deductible crown charges                            -       88,789
      Resource allowance                                      -     (179,190)
      Stock based compensation                          192,488    1,317,784
      Recognition of previously unrecognized
       non-capital loss carryforwards                (6,266,007)  (2,160,373)
      Change in expected tax rate                     1,096,356      302,912
      Expiry of non-capital losses                    1,695,675
      Other                                            (856,378)           -
    -------------------------------------------------------------------------

    Future income tax recovery                      $(6,559,010) $(3,111,945)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Future Income Taxes

                                                           2007         2006
    -------------------------------------------------------------------------

    Property, plant, and equipment                  $ 6,605,800 $ 12,213,900
    Asset retirement obligations                     (1,736,400)    (930,900)
    Share issue cost                                   (700,000)    (386,600)
    Eligible scientific research & experimental
     development expenditures                        (4,060,800)  (4,393,000)
    Non-capital loss carryforwards                  (18,097,600) (23,603,800)
    Valuation allowance                               8,824,523   15,071,000
    -------------------------------------------------------------------------

    Future income tax asset                         $(9,164,477) $(2,029,400)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    As at December 31, 2007, the Company has tax deductions of approximately
    $160.4 million that are available to shelter future taxable income.
    Included in the above is $61.3 million in non-capital losses that expire
    as follows:
                  ----------------------------------------
                  Year of expiry ($millions)
                  ----------------------------------------

                  2008                              $ 31.3
                  2009                                 8.8
                  2014                                 3.9
                  2015                                 1.1
                  2026                                16.2

    8.  RELATED PARTY TRANSACTIONS

    During the year ended December 31, 2007 and during which time a former
    director was related to a professional firm, the Company expensed and
    capitalized legal fees totaling $158,623 (2006 - $433,102) for services
    rendered by that professional firm. No amount is included in accounts
    payable and accrued liabilities related to these transactions. These fees
    were incurred in the normal course of business and recorded at the
    exchange amount.

    During the year ended December 31, 2007, the Company incurred costs
    totaling $814,916 (2006 - $404,209) for services rendered by companies in
    which a director of Twin Butte is an officer and a director. These costs
    were incurred in the normal course of business and recorded at the
    exchange amount. As at December 31, 2007, the Company has $74,234
    included in accounts payable and accrued liabilities related to these
    transactions.

    9.  FINANCIAL INSTRUMENTS

    Financial instruments of the Company carried on the balance sheet consist
    mainly of accounts receivable and current liabilities including bank
    indebtedness. The estimated fair value of the financial instruments
    approximates their carrying values due to their short terms to maturity.
    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 risk. The Company is exposed to interest rate risk to the extent
    that changes in market interest rates will impact any bank indebtedness
    that has a floating interest rate.

    Natural Gas Sales Price Derivative Contracts

    The following is a summary of natural gas sales price derivative
    contracts in effect as at December 31, 2007, that have fixed future sales
    prices:

    Daily quantity    Remaining term of contract    Fixed price per GJ (AECO)
    per giga-joule
    ("GJ")
    -------------------------------------------------------------------------

    2,000 GJ          January 1 to December 31, 2008                   $6.50
    2,500 GJ          April 1 to October 31, 2008                      $6.45
    1,000 GJ          January 1 to December 31, 2008                   $6.64

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

    The fair value of the above natural gas contracts, mark-to-market at
    December 31, 2007, is an unrealized gain of $266,898 ($ nil - 2006).

    Oil Sales Price Derivative Contracts

    The following is a summary of oil sales price derivative contracts in
    effect as at December 31, 2007, that have future sales price commitments:

    Daily
    quantity
    per barrel                                  Fixed price  Costless Collar
    ("bbl")     Remaining term of contract     per bbl (WTI)    per bbl (WTI)
    -------------------------------------------------------------------------

    100 bbl     January 1 to December 31, 2008    US $70.65
    60 bbl      January 1 to December 31, 2007    US $87.25
    60 bbl      January 1 to March 31, 2008                      US $88.00 -
                                                                  US $100.50
    -------------------------------------------------------------------------

    The fair value of the above oil contracts, mark-to-market at December 31,
    2007, is an unrealized loss of $827,135 ($ nil - 2006).

    10. COMMITMENTS

    The Company is committed to future minimum payments for natural gas
    transmission and processing, operating leases on compression equipment,
    farm-in agreements and future premiums on financial derivative
    contracts.

    The Company is committed to incur $12.0 million of flow-through share
    eligible Canadian Exploration Expenditures, as defined in the Canadian
    Income Tax Act, by December 31, 2008. As at December 31, 2007 the Company
    has incurred approximately $2.9 million of this commitment.

    As at December 31, 2007, the Company had contractual obligations and
    commitments for base office rent and equipment as follows:

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

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

                        2008               $ 277,482
                        2009                 284,220
                        2010                 284,220
                        2011                  27,645
                        2012                   1,800
                        ----------------------------

    11. SUBSEQUENT EVENTS

    Acquisition of E4 Energy Inc. and Credit Facility

    On February 8, 2008, the Company closed the acquisition of E4 Energy Inc.
    ("E4"), a publicly traded company for total consideration of
    approximately $55.6 million, before closing adjustments (based on a
    Company share price of $2.45) and including net debt. The Company issued
    15,663,027 common shares to the former shareholders of E4. In addition,
    the Company's total demand revolving credit facility credit facility was
    increased from $40.0 million to $62.5 million.

    Fixed Price Swap Hedges

    In January 2008 the Company entered into a fixed price swap hedge
    arrangement on a total of 1,000 GJ/d for the period of April 1, 2008 to
    October 31, 2008 at a price of $7.075/GJ as follows:

                 Volume (GJ/d)   Price ($/GJ)          Index

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

                 1,000 GJ         $7.0750/GJ    AECO Monthly

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

    In March 2008 the Company entered into a costless collar hedge
    arrangement on a total of 100 bbl/d for the period of April 1, 2008 to
    December 31, 2008 as follows:

            Volume (bbl/d)     Costless Collar USD per bbl (WTI)

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

            100 bbl                      US $90.00 - US $120.00

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

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

    %SEDAR: 00001562E




For further information:

For further information: Ron Cawston, President and Chief Executive
Officer, Telephone: (403) 215-2040, Fax: (403) 215-2055; or R. Alan Steele,
Vice President Finance and Chief Financial Officer, Telephone: (403) 215-2692,
Fax: (403) 215-2055, www.twinbutteenergy.com

Organization Profile

Twin Butte Energy Ltd.

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