Stylus Energy Inc. announces 2006 year end results and operations update



    CALGARY, March 15 /CNW/ - Stylus Energy Inc. ("Stylus" or the "Company")
(TSX - STY) is pleased to present its audited financial and operational
results for the year ended December 31, 2006 and to provide an update on its
2007 activity.

    
    2006 Highlights

    ($ thousands except share and per share data)

                                Three        Three       Twelve       Twelve
                               months       months       months       months
                                ended        ended        ended        ended
    FINANCIAL             December 31  December 31  December 31  December 31
    -------------------------------------------------------------------------
                                 2006         2005         2006         2005
    -------------------------------------------------------------------------
    Natural gas sales           4,788        6,465       16,750       18,220

    Crude oil sales             1,027          714        4,339        2,256
    Natural gas liquids sales     464          205        1,161          628
    Royalty income                  6           31          108          104
    Total production revenue    6,286        7,415       22,358       21,208
    Net income (loss) after
     tax                       (1,694)         884       (3,640)       1,544
    Per share
      Basic ($)                 (0.06)        0.04        (0.14)        0.08
      Diluted ($)               (0.06)        0.04        (0.14)        0.08
    Funds from
     operations(7),(10)         1,960        4,151        8,323       10,940
      Per share
    Basic ($)                    0.08         0.19         0.33         0.55
    Diluted ($)                  0.08         0.18         0.32         0.53
    Capital expenditures,
     net of dispositions(1)     4,562       10,728       37,652       20,718
    Property and equipment
     acquired through
     corporate acquisition(1)       -          248            -       29,623
    Working capital
     deficit(2)               (23,024)      (7,090)     (23,024)      (7,090)

    Shareholders' equity       58,215       47,972       58,215       47,972
    Weighted average common
     shares outstanding
      Basic                26,680,160   22,269,205   25,277,172   20,051,406
      Diluted              26,680,160   23,021,905   25,277,172   20,627,090
    Issued share capital
     at end of period
    Common shares          27,650,910   24,069,857   27,650,910   24,069,857



                                Three        Three       Twelve       Twelve
                               months       months       months       months
                                ended        ended        ended        ended
    OPERATIONS            December 31  December 31  December 31  December 31
    -------------------------------------------------------------------------
                                 2006         2005         2006         2005
    -------------------------------------------------------------------------
    Average daily production

    Crude oil (bbl/d)(3)          204          114          173           93
    Natural gas liquids
     (bbl/d)                       76           40           49           31
    Natural gas (mcf/d)(4)      7,198        6,162        6,964        5,589
    Total oil equivalent
     (BOE/d)(5)                 1,479        1,181        1,383        1,056

    Average sales price
    Crude oil ($/bbl)(6)        54.80        68.24        68.71        66.69
    Natural gas liquids
     ($/bbl)                    66.56        55.93        64.29        54.76
    Natural gas ($/mcf)          7.23        11.40         6.59         8.93

    Netback ($/BOE)
    Total production revenue    46.19        68.27        44.29        55.04
    Royalties                   (9.43)      (10.29)       (8.90)       (7.46)
    Percent of production
     revenue                     20.4         15.1         20.1         13.6
    Production expense(7)      (13.83)      (11.63)      (11.32)      (11.89)
    Transportation expense      (1.22)       (1.11)       (1.21)       (1.27)
    Operating netback           21.71        45.24        22.86        34.42
    Net interest expense(8)     (2.04)       (0.95)       (1.67)       (0.80)
    Net cash general and
     administration
     expense(9)                 (5.37)       (5.95)       (5.14)       (6.43)
    Current tax (recovery)
     expense                     0.10        (0.04)        0.02        (0.04)
    Cash netback                14.40        38.30        16.05        27.15

    Wells drilled - gross           4            5           38           22
    Wells drilled - net           3.3          3.2         25.2         11.7
    Net success rate (percent)     72           85           71           66
    -------------------------------------------------------------------------

    (1)    Excludes capitalized non-cash additions to property, plant and
           equipment for asset retirement obligations and stock-based
           compensation expense
    (2)    Net debt including working capital deficit = current
           assets less current liabilities
    (3)    bbl/d = barrels per day
    (4)    mcf/d = thousand cubic feet per day
    (5)    BOE/d = barrels of oil equivalent per day, with gas
           converted at 6 mcf: 1 BOE
    (6)    Fourth quarter 2006 crude oil price reduced by $4.30 per bbl for
           over-accrual of September 2006 oil price at Vulcan
    (7)    Fourth quarter production expense includes $350,000 or $2.57 per
           BOE related to non-recurring third-party gas processing cost
           adjustments, repair and maintenance costs, equipment rentals and
           overhead adjustments.
    (8)    Net interest expense = interest expense less interest
           and other non-oil and gas income.
    (9)    Total general and administrative ("G&A") expense less overhead
           recoveries, capitalized overhead and non-cash stock based
           compensation expense. Fourth quarter G&A includes $55,000 or $0.40
           per BOE for consulting costs related to certification of
           disclosure controls under Multilateral Instrument 52-109
           Certification of Disclosure in Issuers' Annual and Interim Filings
           ("52-109").
    (10)   Funds from operations is a non-GAAP measure. It is equal to the
           total cash provided from operating activities as presented on the
           Consolidated Statements of Cash Flows plus the asset retirement
           obligations.

    2006 HIGHLIGHTS

    -   Fourth quarter production grew to 1,479 BOE per day, a 25 percent
        increase from production of 1,181 BOE per day in the same period a
        year ago. Fourth quarter production per basic share outstanding was
        up 5 percent from the same period one year ago.

    -   Average 2006 production increased to 1,383 BOE per day, an increase
        of 31 percent from average production of 1,056 BOE per day in 2005
        and an increase of four percent on a weighted average basic share
        outstanding basis.

    -   Stylus has increased its current production to 2,000 to 2,100 BOE per
        day based on the Vulcan Good Production Practice approval received on
        January 16, 2007. This equates to a 35 percent increase from fourth
        quarter 2006 average production and a 27 percent increase per
        weighted average basic share. The production growth achieved during
        2006 and the first quarter 2007 has come from Company-generated
        drilling prospects.

    -   Drilling success continued in the fourth quarter of 2006, with four
        (3.25 net) wells resulting in two (2.0 net) gas wells at Champion and
        one (0.35 net) oil well at Vulcan for a 72 percent net success rate.
        For the twelve months ended December 31, 2006, Stylus drilled
        38 (25.2 net) wells resulting in 21 (13.9 net) gas wells and seven
        (3.9 net) oil wells, for a net success rate of 71 percent.

    -   Funds from operations for 2006 totalled $8.3 million or $0.32 per
        diluted share, a decrease from $10.9 million and $0.53 per diluted
        share in 2005. Natural gas prices dropped 26 percent to $6.59 per mcf
        in 2006 compared to $8.93 per mcf in 2005, and the Company's
        production in 2006 was 84 percent natural gas. Spot natural gas
        prices have improved in 2007 and have averaged about $7.50 per mcf to
        date.

    -   The cash netback for 2006 was $16.05 per BOE, a decrease of
        40 percent from the prior year average cash netback of $27.15 per
        BOE. The 26 percent decline in natural gas prices and a 19 percent
        increase in average royalties were partially offset by a 20 percent
        decrease in G&A expenses per BOE, a five percent reduction in
        production expenses per BOE, and a five percent reduction in
        transportation expense per BOE.

    -   Total production expenses for the year, including operating, workover
        and lease rental expenses decreased five percent to $11.32 per BOE
        from $11.89 per BOE in 2005.

    -   Capital expenditures, net of dispositions, totalled $37.65 million in
        2006, an 82 percent increase compared to the prior year. Net debt,
        including working capital deficiency, at December 31, 2006 was
        $23.0 million, which is 1.1 times the 2007 proved developed producing
        net operating income as forecast in the Company's independent
        engineering evaluation.

    -   Total proved and probable reserves, net of production of 0.5 million
        BOE, increased 17 percent to 4.0 million BOE at December 31, 2006.
        Total proved reserves increased seven percent to 2.5 million BOE. The
        Company's reserve additions replaced 2006 production by a factor of
        2.2 times.
    -   At Champion, the Company has shut-in production capability of 300 to
        350 BOE per day net from various intermediate and shallow natural gas
        zones that are awaiting tie-in during 2007.

    -   Stylus has an inventory of 50 to 75 drilling locations at Vulcan and
        Champion to develop conventional oil and natural gas zones in the
        Second White Specks, Bow Island and Belly River/Edmonton sands at
        drill depths ranging from 800 to 1,800 metres.
    

    Forward-looking Statements
    Certain of the statements contained herein including, without limitation,
financial and business prospects and financial outlook, management's
assessment of future plans and operations, timing of regulatory applications
and anticipated approvals, anticipated production expenses, transportation
expenses, royalty rates, operating costs, general and administrative expenses,
depletion, depreciation and accretion expense and capital expenditures and the
timing and the method of funding thereof may be forward-looking statements.
Words such as "may", "will", "should", "could", "anticipate", "believe",
"expect", "intend", "plan", "potential", "continue" and similar expressions
may be used to identify these forward-looking statements. These statements
reflect management's current beliefs and are based on information currently
available to management. Forward-looking statements involve significant risk
and uncertainties. A number of factors could cause actual results to differ
materially from the results discussed in the forward-looking statements
including, but not limited to, risks associated with oil and gas exploration,
development, exploitation, production, marketing and transportation, loss of
markets, volatility of commodity prices, currency fluctuations, imprecision of
reserve estimates, environmental risks, competition from other producers,
inability to retain drilling rigs and other services, incorrect assessment of
the value of acquisitions, failure to realize the anticipated benefits of
acquisitions, delays resulting from or inability to obtain or delay in
obtaining required regulatory approvals and ability to access sufficient
capital from internal and external sources and the risk factors outlined under
"Risks and Uncertainty" in the attached MD&A and elsewhere herein. The
recovery and reserve estimates of Stylus' reserves are estimates only and
there is no guarantee that the estimated reserves will be recovered. As a
consequence, actual results may differ materially from those anticipated in
the forward-looking statements. Readers are cautioned that the foregoing list
of factors is not exhaustive. Additional information on these and other
factors that could effect Stylus' operations and financial results are
included in reports on file with Canadian securities regulatory authorities
and may be accessed through the SEDAR website (www.sedar.com) and at Stylus'
website (www.stylusenergy.com). Although the forward-looking statements
contained herein are based upon what management believes to be reasonable
assumptions, management cannot assure that actual results will be consistent
with these forward-looking statements. Investors should not place undue
reliance on forward-looking statements. These forward-looking statements are
made as of the date hereof and Stylus assumes no obligation to update or
review them to reflect new events or circumstances except as required by
applicable securities laws.
    Forward-looking statements and other information contained herein
concerning the oil and gas industry and Stylus' general expectations
concerning this industry are based on estimates prepared by management using
data from publicly available industry sources as well as from reserve reports,
market research and industry analysis and on assumptions based on data and
knowledge of this industry which Stylus believes to be reasonable. However,
this data is inherently imprecise, although generally indicative of relative
market positions, market shares and performance characteristics. While Stylus
is not aware of any misstatements regarding any industry data presented
herein, the industry involves risks and uncertainties and is subject to change
based on various factors.
    BOE Presentation: The calculations of barrels of oil equivalent ("BOE")
are based on a conversion rate of nine thousand cubic feet ("mcf") of natural
gas to one barrel ("bbl") of crude oil. BOE's may be misleading, particularly
if used in isolation. A BOE conversion ratio of 6 mcf: 1 bbl is based on an
energy equivalency conversion method primarily applicable at the burner tip
and does not represent a value equivalency at the wellhead.
    Reserves: The estimates of reserves and future net revenue for individual
properties may not reflect the same confidence level as estimates of reserves
and future net revenue for all properties, due to the effects of aggregation.

    OPERATIONS REPORT

    On January 1, 2006, Stylus had no production from its Vulcan property in
southwestern Alberta. By the end of 2006, the Company's Vulcan field was
producing from two oil pools and one gas pool, and the Company's current
production rate is about 2,900 (1,150 net) BOE per day.
    The initial discovery well at Vulcan was drilled almost exactly two years
ago, but the first extended production commenced January 2, 2006. Over the
course of 2006, Stylus invested $15.3 million net in exploration and
development drilling and new production facilities in order to develop the
Vulcan field.
    The Company's strategy of targeting under-explored regions of the Western
Canadian Sedimentary Basin and using exploration techniques and information
that were not used in the area in the past was validated at Vulcan. Since the
initial discovery well drilled in March 2005, Stylus has spent $22.7 million
net at Vulcan and found total proved and probable reserves of 1.5 million BOE
net for a full-cycle cost of $15.22 per BOE.
    Modern 3D seismic was the key to the successful development at Vulcan,
and also the key to accessing the undeveloped lands held by major companies in
the area. During 2006, Stylus spent $6.5 million on seismic and $2.1 million
on land in order to secure the inventory needed to manage a portfolio of
exploration and development projects. The Company also invested $6.8 million
in production facilities to ensure control over the Company's production.
These facilities will permit the development of shallow gas and adjacent
properties that were previously too far from infrastructure to be commercial.

    
    Core area review

    VULCAN

    Vulcan is Stylus' largest producing property, and was the focus for
capital investment during 2006. Vulcan highlights for 2006 are as follows:

    -   The total proved and probable reserve value at Vulcan represents
        40 percent of the Company's total proved and probable reserve net
        present value discounted at 10 percent ("NPV10").

    -   During 2006, Vulcan production averaged 336 BOE per day or 24 percent
        of the total Company production. Vulcan production is producing an
        estimated 1,150 BOE per day net and 56 percent of total Company
        production following the approval by the Alberta Energy and Utilities
        Board of the Company's Good Production Practice application on
        January 16, 2007.

    -   Most of the production capability of the Company in the Vulcan area
        was shutin during 2006 as the Company constructed production
        infrastructure and obtained regulatory approval to produce several
        high productivity wells in the gas pool.

    -   Stylus drilled 14 (7.13 net) wells during 2006, resulting in nine
        (4.78 net) gas wells and five (2.35 net) oil wells, for a net success
        rate of 100 percent. Production or production capability has been
        established in the Sunburst, Bow Island, Belly River and Horseshoe
        Canyon coals in the area.

    -   The Company delineated the Vulcan Basal Mannville G gas pool and the
        Vulcan Basal Mannville I oil pool in the Cretaceous-age Sunburst sand
        reservoir at a depth of about 2,000 metres. A waterflood is planned
        for the I pool in 2007.

    -   Stylus discovered a Bow Island oil pool and placed the discovery well
        (0.5 net) on production in November 2006 at a rate of about 25
        (12.5 net) bbls per day of light, sweet oil. Four to five (2.0 to
        2.5 net) additional drilling locations in this pool are planned for
        2007

    -   A gas compression facility (50 percent working interest) with a
        licence capacity of 15 mmcf per day and an oil battery (50 percent
        working interest) with a licence capacity of 1,000 bbls per day was
        constructed in 2006.

    -   Since inception, Stylus has spent $22.7 million net at Vulcan and
        found total proved and probable reserves of 1.5 million BOE net for a
        full-cycle cost of $15.22 per BOE.

    -   The Company has an inventory of 41 (20.5 net) drilling locations in
        shallow oil and gas.

    CHAMPION

    In late 2005, the Company negotiated a farmin on 13 gross (13 net)
sections of land about 10 kilometres south of Vulcan. These lands were
sparsely drilled, but were prospective for Cretaceous Belly River and Edmonton
Group sands with conventional gas and coal bed methane gas potential. In
December 2005, Stylus shot a proprietary 3D seismic program over the area to
identify shallow and deep drilling targets. The Champion highlights for 2006
are:

    -   Stylus drilled nine (9.0 net) wells during 2006, resulting in seven
        (7.0 net) Belly River and Edmonton gas wells, one (1.0 net) Second
        White Specks gas well, and one (1.0 net) Bow Island oil well, for a
        net success rate of 100 percent. Three (3.0 net) of the wells were
        deep exploration wells targeting Sunburst and Glauconitic targets at
        a depth of 2,000 metres, and although the primary targets were not
        successful, each well was cased and completed for uphole zones.

    -   The Company constructed a single-well oil battery and placed one
        (1.0 net) oil well on production in November 2006. The well is
        currently producing at a rate of about 20 (20 net) bbls per day.

    -   Conventional sand reservoirs in the eight (8.0 net) gas wells have
        been completed and tested at stabilized aggregate production test
        rates of up to 700 mcf per day. Further drilling and completions
        during the first quarter of 2007 has added additional production
        capability. The behind pipe aggregate production capability is
        projected to be about 300 to 350 BOE per day net.

    -   The Company has recognized proved and probable reserves of
        174,000 BOE at Champion as at December 31, 2006, but has included
        $2.5 million in future development capital to tie-in the existing
        Champion wells.

    -   The Company has an inventory of 34 (34 net) drilling locations.
    

    MONARCH

    In May 2006, the Company executed an agreement with a large, integrated
exploration and production company to farmin ("2006 farmin") on approximately
30,300 net acres of undeveloped mineral leases. In January 2007, Stylus
negotiated a second farmin ("2007 farmin") of 6,240 net acres of mineral
leases that are adjacent to or encompass shallow rights that complement the
2006 farmin leases.
    The primary targets in this area include Sunburst and Glauconite sands,
in a sparsely drilled exploration fairway that extends south from the
Company's discovery at Vulcan. Secondary targets include a multitude of
intermediate and shallow horizons prospective for oil and natural gas similar
to the targets in the Champion area.
    In August 2006, Stylus conducted a 119 square mile proprietary 3D seismic
program for $5.8 million to further define exploration leads previously
identified by existing well control and trade seismic data in the area. The
initial drilling program in the first quarter of 2007 is designed to test
different play concepts identified throughout the extensive farmin land base.
    The drilling results to date are:

    
    -   During 2006, Stylus drilled and abandoned one (1.0 net) well. The
        timing of this initial earning well was a requirement of the 2006
        farmin and had to be drilled before the Company's new 3D seismic was
        available. This well did confirm the presence of thick, high-quality
        reservoir sands in the Glauconite formation that were water-bearing.
        The new 3D seismic program has identified structurally higher
        locations on this prospect.

    -   During the first quarter of 2007, the Company drilled three (3.0 net)
        exploration earning wells. One (1.0 net) well and has been completed
        in the Glauconite zone. On test, the well recovered non-commercial
        quantities of oil, but set up additional exploration locations to
        delineate a Glauconite oil prospect. This well was also completed in
        a secondary zone uphole as a 2007 farmin earning well and recovered
        water with traces of natural gas. One (1.0 net) well encountered low
        permeability Sunburst reservoir and tested traces of natural gas. A
        shallow oil show in this well has not been evaluated to date. One
        (1.0 net) well tested a Sunburst prospect that encountered wet
        reservoir and was abandoned without testing.
    

    Drilling Activity

    During 2006, Stylus drilled 38 (25.2 net) wells with a 71 percent net
success rate compared to 22 (11.7 net) wells in 2005 with a 73 percent net
success rate. Of the 38 gross wells drilled during 2006, 32 were operated by
Stylus and the Company-operated drilling achieved an 80 percent net success
rate. Of the 38 gross wells drilled in 2006, 50 percent were classified as
exploration wells and 50 percent were development wells.
    In 2005 and 2006, the Company's drilling activity shifted to deeper
targets in the deep basin in southwestern Alberta at a depth of about
1,900 metres and away from the shallow drilling targets of northeast Alberta
at a depth of less than 500 metres. The number of net wells drilled in 2006
increased 115 percent and the total metres drilled increased 135 percent to
36,519 net metres.

    
    WELLS DRILLED

    (Year ended December 31)                        2006                2005
                                        -------------------------------------
                                         Gross       Net     Gross       Net
                                        -------------------------------------
    Oil                                      7       4.8         2       1.1
    Natural gas                             21      13.9        14       6.7
    Dry & Abandoned                         10       6.5         6       3.9
    Total                                   38      25.2        22      11.7
    Success rate (percent)                  74        71        73        66
    Average depth drilled (metres)       1,430     1,449     1,168     1,324


    Undeveloped Land

    In 2006, Stylus expanded its land holdings in its core exploration area in
southwestern Alberta. The Company's total land holdings at December 31, 2006,
consisted of 229,366 net acres compared to 217,372 net acres at the end of
2005. Land additions during 2006 occurred primarily in the core areas at
Champion and Monarch.
    The undeveloped land holdings of the Company increased three percent from
the prior year to 134,650 net acres at December 31, 2006, compared to 130,649
net acres at the end of 2005. Stylus has an average working interest of
67 percent in its undeveloped land base.

    LAND HOLDINGS
    (At December 31)

    Acres          Undeveloped           Developed           Total
                  -----------------------------------------------------------
                     Gross       Net     Gross       Net     Gross       Net
                  -----------------------------------------------------------
    Vulcan           7,040     4,480     5,280     3,219    12,320     7,699
    Abee            14,720     7,386     3,200     1,325    17,920     8,710
    Hector-Scandia     640       352    13,671     9,624    14,311     9,976
    Portage          3,200     1,280    56,960    26,633    60,160    27,913
    Hangingstone    70,400    51,046    28,160    19,922    98,560    70,969
    Other NE
     Alberta        33,280    24,346    40,320    11,902    73,600    36,248
    Other           71,756    45,760    53,284    22,090   125,039    67,851
                  -----------------------------------------------------------
    Total 2006     201,036   134,650   200,875    94,715   401,910   229,366
                  -----------------------------------------------------------
                  -----------------------------------------------------------
    Total 2005     206,021   130,649   204,708    86,723   410,729   217,372
                  -----------------------------------------------------------
                  -----------------------------------------------------------
    Total 2004     149,120    96,081   149,280    61,743   298,400   157,824
                  -----------------------------------------------------------
                  -----------------------------------------------------------
    


    RESERVES AT DECEMBER 31, 2006

    Stylus' independent engineering evaluations, effective December 31, 2006,
were prepared by McDaniel & Associates Consultants Ltd. ("McDaniel") in
accordance with the Canadian Securities Administrator's National Instrument
51-101 ("NI 51-101"). For the previous year ended December 31, 2005, McDaniel
& Associates Consultants Ltd. ("McDaniel") evaluated the properties that
originated in Stylus Exploration Inc., and Sproule Associates Ltd. ("Sproule")
evaluated the properties that originated in Kinloch Resources Inc.
    Under NI 51-101, proved reserves are defined as having a high degree of
certainty to be recoverable, and probable reserves are defined as those
reserves that are less certain to be recovered than proved reserves. The
targeted levels of certainty, in aggregate, are at least 90 percent
probability that the quantities actually recovered will equal or exceed the
estimated proved reserves and at least a 50 percent probability that the
quantities actually recovered will equal or exceed the sum of the estimated
proved plus probable reserves.
    The following tables summarize the McDaniel evaluation of the Company's
interest in reserves and future net production revenue from these reserves.
All evaluations of future net production revenues set forth in the following
tables are stated prior to any provision for income tax and indirect costs but
after estimated abandonment costs. It should not be assumed that the present
worth of future net cash flow represents fair market value of the reserves.
There is no assurance that the price and cost assumptions in the constant
price, and cost, and forecast cost and price assumptions will be attained, and
variances could be material.

    
    Highlights:

    -   Total proved ("TP") reserves grew by seven percent to 2.5 million BOE
        ("mmBOE") at December 31, 2006.

    -   Total proved plus probable ("TPP") reserves grew by 17 percent to
        4.0 mmBOE at December 31, 2006.

    -   TPP reserves were increased by 2.2 BOE for each BOE that was produced
        during 2006, for a 216 percent reserve replacement.

    -   The NPV10 reserves value as at December 31, 2006 totaled
        $70.9 million, a decrease of five percent from the $74.5 million as
        at December 31, 2005. The proved producing reserves represent
        72 percent of the total NPV10.

    -   At Champion and Monarch, a total of $13.5 million was invested in 3D
        seismic, undeveloped land, and exploration farmin wells to establish
        core land positions at a TPP FD&A cost of $77.50 per BOE in 2006.

    -   The recycle or reinvestment ratio was 0.64 in 2006 using the cash
        flow netback of $16.05 and the TPP FD&A cost of $35.47 per BOE,
        reflecting the emphasis in 2006 of building a core area in southern
        Alberta with large 3D seismic programs and exploration farmin
        drilling.


    Forecast Prices and Costs

    Summary Of Oil And Gas Reserves - Gross(1) And Net(2) Reserves

    As at
     December 31,       Light and         Natural Gas and        Natural
     2006            Medium Crude Oil   Coal Bed Methane(3)    Gas Liquids
                    ---------------------------------------------------------
                     Gross       Net     Gross       Net     Gross       Net
                    ---------------------------------------------------------
                     (mbbl)    (mbbl)    (mmcf)    (mmcf)    (mbbl)    (mbbl)
                    ---------------------------------------------------------
    PROVED
    Developed
     Producing         452       394     9,893     7,041        89        57
    Developed
     Non-Producing       -         -     725.6     539.4         -         -
    Undeveloped        167       128       199       114        10         5
    TOTAL PROVED       619       521    10,818     7,693        99        62
    PROBABLE           428       356     6,113     4,321        38        24
    TOTAL PROVED
     PLUS PROBABLE   1,047       877    16,930    12,015       137        86

    May not add due to rounding

    Notes:

    (1) "Gross" means the total of Stylus' working interest share in the
        total remaining recoverable reserves before deducting royalties owned
        by others and without including any royalty interest of Stylus.

    (2) "Net" means the total of Stylus' working interest and royalty
        interest share in the total remaining recoverable reserves after
        deducting the amounts attributable to the royalties owned by others,
        including Crown and freehold royalties.

    (3) Includes proved developed non-producing coal bed methane reserves of
        47.5 (37.1 net) mmcf and probable coal bed methane reserves of
        252.5 (212.4 net) mmcf.


    Net Present Value of Reserves (Before Income Taxes)
    As at December 31, 2006(1)(2)(3)
    ($ thousands)

                         Undiscounted             Discounted at
    -------------------------------------------------------------------------
                                            5%       10%       15%       20%
    PROVED
    Developed Producing       64,351    56,889    51,228    46,787    43,209
    Developed Non-Producing      297       192        92         5       -70
    Undeveloped                1,674       818       192      (268)     (611)
    TOTAL PROVED              66,321    57,899    51,512    46,524    45,528
    PROBABLE                  37,848    26,372    19,373    14,809    11,666
    TOTAL PROVED PLUS
     PROBABLE                104,170    84,271    70,886    61,333    54,194

    May not add due to rounding.

    Notes:

    (1) Utilizing McDaniel January 1, 2007, price forecast

    (2) As required by NI 51-101, undiscounted well abandonment costs of
        $3.5 million for total proved reserves and $3.9 million for total
        proved and probable reserves are included in the net present value
        determination.

    (3) Undiscounted and discounted values are stated before the provision of
        income taxes, interest, debt service charges and general and
        administrative expenses. It should not be assumed that the
        undiscounted and discounted future net revenues estimated by McDaniel
        represent the fair market value of the reserves.

    Pricing Assumptions

    The January 1, 2007 pricing forecasts presented below have been prepared
by McDaniel. These prices have been utilized in determining the preceding
reserves and cash flow forecasts.

                             ------------------------------------------------
                                                        Natural    Inflation
                              Crude Oil                     Gas         Rate
                             ------------------------------------------------
                                          Edmonton
    Year                      WTI Oil        Light         AECO
                             ($US/bbl)   ($Cdn/bbl)   ($Cdn/mcf) (% per year)
                             ------------------------------------------------
    2007                        62.50        70.80         7.19          2.0
    2008                        61.20        69.30         7.40          2.0
    2009                        59.80        67.70         7.77          2.0
    2010                        58.40        66.10         7.88          2.0
    2011                        56.80        64.20         8.09          2.0
    2012                        58.00        65.60         8.30          2.0
    2013                        59.10        66.80         8.51          2.0
    2014                        60.30        68.20         8.66          2.0
    2015                        61.50        69.50         8.87          2.0
    2016                        62.70        70.90         9.03          2.0
    2017                        64.00        72.30         9.19          2.0

    Constant Prices and Costs

    NET PRESENT VALUE OF RESERVES (BEFORE INCOME TAXES)
    As at December 31, 2006(1)(2)(3)
    ($ thousands)

                         Undiscounted                          Discounted at
    -------------------------------------------------------------------------
                                            5%       10%       15%       20%
    PROVED
    Developed Producing       53,914    47,649    42,914    39,208    36,225
    Developed Non-Producing     (362)     (379)     (408)     (437)     (464)
    Undeveloped                1,820       921       270      (206)     (560)
    TOTAL PROVED              55,373    48,190    42,776    38,564    35,201
    PROBABLE                  29,736    20,652    15,117    11,503     9,009
    TOTAL PROVED PLUS
     PROBABLE                 85,109    68,842    57,893    50,068    44,210

    May not add due to rounding

    Notes:

    (1) Price Assumptions: WTI US$61.05 per bbl; Edmonton Light crude
        Cdn$67.06; Alberta Spot Field Gas Cdn $5.93 per mcf.

    (2) As required by NI 51-101, undiscounted well abandonment costs of
        $2.9 million for total proved reserves and $3.0 million for total
        proved and probable reserves are included in the net present value
        determination.

    (3) Undiscounted and discounted values are stated before prior to the
        provision of income taxes, interest, debt service charges and general
        and administrative expenses. It should not be assumed that the
        undiscounted and discounted future net revenues estimated by McDaniel
        represent the fair market value of the reserves.


    Reserve Reconciliation

    RECONCILIATION OF COMPANY NET RESERVES(1) BY PRINCIPAL PRODUCT TYPE
    Forecast Prices and Costs

                       Crude Oil &
                       Natural Gas
                          Liquids           Natural Gas          Total
                          (mbbl)              (mmcf)             (mBOE)
                   ----------------------------------------------------------
                              Proved              Proved              Proved
                                Plus                Plus                Plus
                    Proved  Probable    Proved  Probable    Proved  Probable
                   ----------------------------------------------------------
    Opening,
     December 31,
     2005              482       604     7,955    11,988     1,808     2,602
    Extensions          68       140       755     1,139       194       330
    Improved Recovery   22        43         -         -        16        33
    Technical
     Revisions          12        70        54      (389)       21         5
    Discoveries        123       249       726     1,059       243       425
    Acquisitions         -         -         -         -         -         -
    Dispositions         -         -       (34)      (26)       (6)       (4)
    Economic Factors     -         -         1         7         1         1
    Present Value
     Accretion          (1)       (1)        1         7         -         1
    Production        (115)     (129)   (1,775)   (1,777)     (410)     (425)
    Closing,
     December 31,
     2006              583       963     7,693    12,015     1,866     2,966

    May not add due to rounding

    Note:

    (1) "Net" means the total of Stylus' working interest and royalty
        interest share in the total remaining recoverable reserves after
        deducting the amounts attributable to the royalties owned by others,
        including Crown and freehold royalties.
    

    Finding and Development Costs (F&D) and Finding, Development and Net
    Acquisition Costs (FD&A)

    NI 51-101 specifies how finding and development ("F&D") costs should be
calculated if they are reported. The exploration and development costs
incurred in the year, along with the change in estimated undiscounted future
development costs, must be aggregated and then divided by the applicable
reserve additions. The calculation specifically excludes the effects of
acquisitions and dispositions on both reserves and costs.
    By excluding acquisitions and dispositions, Stylus believes that the
provisions of NI 51-101 do not fully reflect Stylus' ongoing reserve
replacement costs. In 2005, the acquisition of Kinloch had a significant
impact on Stylus' annual reserve replacement costs, and excluding these
amounts could result in an inaccurate portrayal of Stylus' cost structure.
Although the Company did not acquire any assets during 2006, for consistency
Stylus will continue its practice of reporting finding, development and
acquisition ("FD&A") costs that will incorporate all acquisitions net of any
dispositions during the year.
    During 2006, Stylus spent $39.4 million before dispositions of which
$28.9 million, or 73 percent of the total capital expenditures, was invested
in further expanding the Company's southern Alberta core areas at Vulcan,
Champion and Monarch.
    In 2006, the Company incurred total capital expenditures of $15.3 million
at Vulcan. A total of $13.5 million was invested at Champion and Monarch, of
which $7.6 million was for 3D seismic and undeveloped land. These costs are
included in the Company F&D and FD&A calculations.

    
    FORECAST PRICES AND COSTS(1)

                                     2006                     2005
    -------------------------------------------------------------------------
                                             Total                     Total
                                            Proved                    Proved
                                              plus                      plus
                             Proved(3)  Probable(3)    Proved(3)  Probable(3)
    -------------------------------------------------------------------------
    2006 CAPITAL COSTS
     ($ thousands)
    Exploration and
     development               39,241       39,421       21,223       21,223
    Acquisitions, net of
     dispositions              (1,780)      (1,780)      29,623       29,623
                               37,641       37,461       50,846       50,846
    Change in future
     development cost(2)          327        3,953        6,907        8,700
                               37,788       41,414       57,753       59,546

    2006 GROSS RESERVE
     ADDITIONS(3) (mBOE)
    Exploration and
     development                  672        1,106          667          821
    Acquisitions, net
     of dispositions              (11)         (15)       1,421        1,855
                                  660        1,092        2,091        2,676

    FINDING & DEVELOPMENT
     COSTS ($/BOE)
    2006 F&D costs,
     including FDC and
     excluding acquisitions
     and dispositions
     (NI 51-101)                58.92        39.04        42.17        36.45
    2006 FD&A costs,
     including FDC,
     acquisitions and
     dispositions               57.23        37.94        27.62        22.25
    2006 F&D costs,
     excluding FDC,
     excluding acquisitions
     and dispositions           58.44        35.47        31.87        25.85
    2006 FD&A costs,
     excluding FDC, net
     of dispositions            56.73        34.31        34.31        19.00

    (1) A December 31, 2003 reserve report was not done for Stylus
        Exploration and therefore NI 51-101 compliant 2004 and three-year
        average F&D costs and FD&A costs are not available.

    (2) The aggregate of the exploration and development costs incurred in
        the most recent financial year and the change during that year in
        estimated future development costs generally will not reflect total
        finding and development costs related to reserve additions for that
        year.

    (3) Based on Gross reserve additions, meaning the total of Stylus'
        working interest share in the total remaining recoverable reserves
        before deducting royalties' owned by others and without including any
        royalty interest of Stylus.


    Reserve Life Index

    The Company's reserve life index using annualized fourth quarter
production is 4.7 years (2005 - 5.5 years) for proved BOE reserves and
7.4 years (2005 - 7.9 years) for proved plus probable BOE reserves. Reserve
life calculated using annualized fourth quarter production may be more
reflective of reserve life due to the level of new production added during the
year.

                                     2006                       2005
                        -----------------------------------------------------
                             Using         Using        Using        Using
                           Annualized     Average     Annualized    Average
                         Q4 Production  Production  Q4 Production  Production
                        -----------------------------------------------------



    Production (BOE per
     day)                       1,479        1,383        1,181        1,056
    Proved reserves(1) (mBOE)   2,521        2,521        2,366        2,366
    Proved reserve life
     index (years)                4.7          5.0          5.5          6.1
    Proved plus probable
     reserves(1) (mBOE)         4,006        4,006        3,419        3,419
    Proved plus probable
     reserve life index
     (years)                      7.4          8.0          7.9          8.9

    (1) Based on Gross reserve additions, meaning the total of Stylus'
        working interest share in the total remaining recoverable reserves
        before deducting royalties' owned by others and without including any
        royalty interest of Stylus.


    Reserve Replacement

    The Company's 2006 capital investment program replaced production by a
factor of 1.3 (2005 - 4.4) times on a proved basis and 2.2 (2005 - 5.9) times
on a proved plus probable basis.

                                                           2006         2005
    -------------------------------------------------------------------------
    Production (mBOE)                                       505          385
    Proved reserve additions(1) (mBOE)                      663        1,702
    Proved reserve replacement ratio                        1.3          4.4
    Proved plus probable reserve additions(1) (mBOE)      1,096        2,287
    Proved plus probable reserve replacement ratio          2.2          5.9

    (1) Based on Gross reserve additions, meaning the total of Stylus'
        working interest share in the total remaining recoverable reserves
        before deducting royalties' owned by others and without including any
        royalty interest of Stylus.


    Recycle Ratio

    The recycle ratio is a measure for evaluating the effectiveness of a
company's re-investment program. It accomplishes this by comparing the
operating netback per barrel of oil equivalent to that year's reserve finding
and development costs.

                                                           2006         2005
    -------------------------------------------------------------------------
    Operating netback ($/BOE)                             22.86        34.42
    Proved F&D costs, including future development
     costs ($/BOE)                                        58.92        42.16
    Proved recycle ratio                                   0.39         0.82
    Proved plus probable F&D costs, including future
     development ($/BOE)                                  35.47        36.45
    Proved plus probable recycle ratio                     0.64         0.94

    RESERVES

    2007 OUTLOOK

    The Company estimates its 2007 capital program of $22.8 million to be
funded primarily by cash flow and debt, using an average natural gas price of
Cdn $7.23 per mcf and an average Edmonton Light oil price of Cdn $72.37 per
bbl. Average royalties are estimated to be 27 percent, average production
expenses are projected to be $8.15 per BOE, and general and administrative
costs are estimated at $2.86 per BOE.

    Highlights of the planned 2007 capital program are:

    -   Allocate 72 percent to drilling and completions, 23 percent to
        equipping and production facilities, and five percent to seismic and
        land acquisition

    -   A drilling program of 25 (19.0 net) wells, including 12 (9.5 net)
        exploration wells and 13 (9.8 net) development wells

    -   First quarter capital spending of about $6.5 million to drill ten
        (5.12 net) wells

    -   Two (0.62 net) gas wells have been drilled at Portage and tested at a
        combined rate of 1.7 mmcf per day (92 BOE per day net)

    -   One (0.5 net) well drilled at Barney in northern Alberta has resulted
        in the discovery of a new gas pool. This exploratory well will be
        tested this year and sets up a multi-well drilling and tie-in program
        for the winter of 2007/2008

    -   One (1 net) gas well at Champion drilled in the first quarter of 2007
        has tested at a stabilized natural gas rate of about 1.0 mmcf per
        day. This brings the Champion behind-pipe production capability
        awaiting tie-in to about 300 to 350 net BOE per day. Gas gathering
        pipelines are expected to be constructed during the summer of 2007 at
        a cost of $2.5 million, followed by a infill drilling program
    

    MANAGEMENT'S DISCUSSION AND ANALYSIS OF  FINANCIAL CONDITION AND RESULTS
    OF OPERATIONS

    The following Management's Discussion and Analysis of Financial Condition
and Results of Operations ("MD&A") is provided by the management of Stylus
Energy Inc. ("Stylus" or the "Company") to review the financial position and
the results of its operations for the year ended December 31, 2006 as compared
to the previous year. This MD&A should be read in conjunction with the audited
consolidated financial statements including notes for the year ended December
31, 2006, and the audited consolidated financial statements including notes
for the year ended December 31, 2005. Information for the three months ended
December 31, 2006 and December 31, 2005 is unaudited.
    Stylus Exploration Inc. ("Stylus Exploration"), a private company, and
Kinloch Resources Inc. ("Kinloch"), a publicly traded company, merged their
business and operations through a plan of arrangement whereby Stylus
Exploration and Kinloch amalgamated effective March 1, 2005 to create Stylus
Energy Inc. The business combination has been accounted for as a reverse
takeover of Kinloch by Stylus Exploration. As such, the comparative numbers
for Stylus for the year ended December 31, 2005 are those of Stylus
Exploration for the twelve months with the results of operations of Kinloch
recognized from the date of amalgamation.
    This commentary is based upon information available to and is dated
March 14, 2007. Additional information relating to Stylus, including Stylus'
Annual Information Form, is available on SEDAR (www.sedar.com).

    Advisories

    Basis of Presentation: The financial data presented below has been
prepared in accordance with Canadian generally accepted accounting principles
("GAAP"). The reporting and the measurement currency is the Canadian dollar.
    Non-GAAP Measurements: The MD&A contains the terms "funds from
operations" and "netbacks", which are non-GAAP measures. The Company uses
these measures to help evaluate its performance. These measurements should not
be considered an alternative to, or more meaningful than, net income (loss) or
cash provided by operations as determined in accordance with GAAP as
indicators of the Company's performance. The reconciliation between cash flow
from operating activities and funds from operations can be found in the Funds
and Earnings table contained in this MD&A. The Company presents funds from
operations per share, whereby per share amounts are calculated using weighted
average shares outstanding consistent with the calculation of earnings per
share. These measurements are presented because management believes the
information is useful as a financial indicator of a company's ability to
generate cash to internally fund exploration and development activities and to
service debt. Funds from operations is also used by research analysts to value
and compare oil and gas exploration and production companies, and is
frequently included in published research when providing investment
recommendations. The Company considers corporate netbacks a key measure as it
demonstrates its profitability relative to current commodity prices. Stylus'
determination of these measurements may not be comparable to that reported by
other companies.
    BOE Presentation: The calculations of barrels of oil equivalent ("BOE")
are based on a conversion rate of six thousand cubic feet ("mcf") of natural
gas to one barrel ("bbl") of crude oil. BOE's may be misleading, particularly
if used in isolation. A BOE conversion ratio of 6 mcf: 1 bbl is based on an
energy equivalency conversion method primarily applicable at the burner tip
and does not represent a value equivalency at the wellhead.
    Forward-looking Statements: Certain of the statements contained herein
including, without limitation, financial and business prospects and financial
outlook, management's assessment of future plans and operations, timing of
regulatory applications and anticipated approvals, anticipated production
expenses, transportation expenses, royalty rates, operating costs, general and
administrative expenses, depletion, depreciation and accretion expense and and
capital expenditures and the timing and the method of funding thereof may be
forward-looking statements. Words such as "may", "will", "should", "could",
"anticipate", "believe", "expect", "intend", "plan", "potential", "continue"
and similar expressions may be used to identify these forward-looking
statements. These statements reflect management's current beliefs and are
based on information currently available to management. Forward-looking
statements involve significant risk and uncertainties. A number of factors
could cause actual results to differ materially from the results discussed in
the forward-looking statements including, but not limited to, risks associated
with oil and gas exploration, development, exploitation, production, marketing
and transportation, loss of markets, volatility of commodity prices, currency
fluctuations, imprecision of reserve estimates, environmental risks,
competition from other producers, inability to retain drilling rigs and other
services, incorrect assessment of the value of acquisitions, failure to
realize the anticipated benefits of acquisitions, delays resulting from or
inability to obtain or delay in obtaining required regulatory approvals and
ability to access sufficient capital from internal and external sources and
the risk factors outlined under "Risks and Uncertainty" in the attached MD&A
and elsewhere herein. The recovery and reserve estimates of Stylus' reserves
are estimates only and there is no guarantee that the estimated reserves will
be recovered. As a consequence, actual results may differ materially from
those anticipated in the forward-looking statements. Readers are cautioned
that the foregoing list of factors is not exhaustive. Additional information
on these and other factors that could effect Stylus' operations and financial
results are included in reports on file with Canadian securities regulatory
authorities and may be accessed through the SEDAR website (www.sedar.com) and
at Stylus' website (www.stylusenergy.com). Although the forward-looking
statements contained herein are based upon what management believes to be
reasonable assumptions, management cannot assure that actual results will be
consistent with these forward-looking statements. Investors should not place
undue reliance on forward-looking statements. These forward-looking statements
are made as of the date hereof and Stylus assumes no obligation to update or
review them to reflect new events or circumstances except as required by
applicable securities laws.
    Forward-looking statements and other information contained herein
concerning the oil and gas industry and Stylus' general expectations
concerning this industry are based on estimates prepared by management using
data from publicly available industry sources as well as from reserve reports,
market research and industry analysis and on assumptions based on data and
knowledge of this industry which Stylus believes to be reasonable. However,
this data is inherently imprecise, although generally indicative of relative
market positions, market shares and performance characteristics. While Stylus
is not aware of any misstatements regarding any industry data presented
herein, the industry involves risks and uncertainties and is subject to change
based on various factors.

    
    Production

                Three      Three                Twelve     Twelve
               months     months                months     months
                ended      ended                 ended      ended
             December   December              December   December
                   31         31          %         31         31          %
    -------------------------------------------------------------------------
                 2006       2005     Change       2006       2005     Change
    -------------------------------------------------------------------------
    Total
     Production
    Crude oil
     (bbl)     18,741     10,465        79      63,148     33,826        87
    NGL (bbl)   6,978      3,667        90      18,057     11,474        57
    Natural gas
     (mcf)    662,188    566,889        17   2,541,843  2,039,971        25
    Total
     (BOE)    136,084    108,613        25     504,845    385,296        31

    Daily
     Production
    Crude oil
     (bbl/d)      204       114         79         173         93        87
    NGL (bbl/d)    76        40         90          49         31        57
    Natural gas
     (mcf/d)    7,198     6,162         17       6,964      5,589        25
    Total
     equivalent
     (BOE/d)    1,479     1,181         25       1,383      1,056        31
    -------------------------------------------------------------------------
    

    Production for the year ended December 31, 2006 increased 31 percent to
1,383 BOE per day from 1,056 BOE per day in the prior year. Crude oil and
natural gas liquids ("NGL") production represented 16 percent of the Company's
average total production in 2006, compared to 12 percent in the prior year and
none in 2004.
    The year-over-year production increase is due primarily to the onset of
production at Vulcan, Alberta, an exploration discovery made in March 2005. In
September 2006, the Company completed construction and commissioning of its
Vulcan oil battery and natural gas compression facility. This facility permits
the Company to recover NGL's and crude oil at Vulcan and to deliver raw
natural gas to two natural gas and NGL processing plants in the area. With the
facility in place, the Company is now able to proceed with development of the
shallow gas and oil zones at Vulcan and to conserve solution gas from the
Company's Vulcan I Pool ("I Pool"). The licence capacity of the oil battery is
1,000 bbls per day and the licence capacity of the gas compression facility is
15 mmcf per day.
    On January 16, 2007, Stylus received regulatory approval to produce
several shut-in wells in the Vulcan G Pool, which has increased the total
production from the Vulcan field as of the date of this report to about
2,900 (1,150 net) BOE per day. Vulcan comprised 24 percent of the Company's
2006 average production of 1,383 BOE per day and currently represents about
56 percent of the Company's current production of 2,000 to 2,100 BOE per day.
    Production for the fourth quarter of 2006 increased 25 percent to
1,479 BOE per day as compared to 1,181 BOE per day in the same quarter of
2005. Fourth quarter production declined by three percent relative to the
average production of 1,523 BOE per day in the third quarter of 2006 due to
production curtailments during November and December 2006 caused by
regulatory, facility and pipeline issues at Vulcan, Hangingstone South and
Portage.
    At Vulcan, average oil production decreased from 262 (131 net) bbls per
day in the third quarter of 2006 to 134 (67 net) bbls per day in the fourth
quarter of 2006 when two (1.0 net) high-productivity oil wells in the I Pool
came off test on October 1, 2006 and the Maximum Rate Limitation of 50
(25 net) barrels per day per well was applied, as required by the Alberta
Energy and Utilities Board ("AEUB").
    A pressure maintenance water flood project is under consideration for the
I Pool in 2007 in order to permit higher oil production rates and to increase
the recoverable oil reserves. AEUB approval of a water flood project would be
required and an application for approval is anticipated for the second quarter
of 2007 with approval anticipated to take between three and six months after
application.
    Offsetting the decreased oil production rate from the I Pool were three
(2.0 net) new oil producers located at Vulcan (0.5 net), Champion (1.0 net)
and Nipisi (0.5 net) that commenced production during the fourth quarter of
2006.
    At Hangingstone South, approximately 110 BOE per day net natural gas
production was shut-in at the end of October 2006 due to a permanent and
scheduled increase in the operating pressure of the TransCanada main sales gas
transmission pipeline. Stylus' natural gas production is custom processed in a
third-party gas plant at Hangingstone, and the custom processor failed to make
the required facility modifications to deliver sales gas to the TransCanada
pipeline. Partial production resumed in late December 2006, but the Company's
natural gas sales are still curtailed to about 50 percent of production
capacity as the third-party plant continues to experience ongoing disruptions
due to high line pressures. The Hangingstone fourth quarter average production
was reduced by 60 BOE per day as a result of this facility issue. Stylus is
currently working to divert its Hangingstone production to another gas plant
nearby that has not been affected by the higher line pressures.
    At Portage, a pipeline break resulted in the loss of 16 BOE per day net
for the fourth quarter. Repairs are underway during the first quarter of 2007,
as this is a winter access only area.
    Offsetting reduced natural gas sales at Hangingstone were increased
natural gas production volumes from two (0.8 net) new natural gas wells at
Vulcan that commenced production during December 2006. The new Vulcan natural
gas wells yield NGL that resulted in increased NGL production during the
fourth quarter.

    
    Prices

                Three      Three                Twelve     Twelve
               months     months                months     months
                ended      ended                 ended      ended
             December   December              December   December
                   31         31          %         31         31          %
    -------------------------------------------------------------------------
                 2006       2005     Change       2006       2005     Change
    -------------------------------------------------------------------------
    Crude oil
     ($/bbl)    54.80      68.24        (20)     68.71      66.69          3
    NGL ($/bbl) 66.56      55.93         19      64.29      54.76         17
    Natural gas
     ($/mcf)     7.23      11.40        (37)      6.59       8.93        (26)
    Natural gas
     ($/BOE)    43.39      68.43        (37)     39.54      53.59        (26)
    -------------------------------------------------------------------------
    

    The Company's average natural gas selling price for the year ended
December 31, 2006 decreased 26 percent to $6.59 per mcf as compared to $8.93
per mcf in the same period in 2005. The Company's natural gas price mirrored
the average AECO Spot price for 2006 of $6.56 per mcf. Natural gas spot prices
at AECO declined from a high in January 2006 of $8.67 per mcf to a low in
September 2006 of $4.72 per mcf, before recovering to average $7.42 per mcf in
November and December 2006. The mild winter of 2005/2006 resulted in a surplus
of natural gas in storage at the start of the summer season, and weaker
natural gas prices through the summer of 2006.
    The Company's annual production in 2006 was 84 percent weighted to
natural gas; therefore, the low natural gas prices negatively affected the
Company's revenues per BOE for the year and the quarter ended December 31,
2006. The AECO 'C' Spot price, which is the Alberta gas trading price,
averaged $6.56 per mcf during 2006.
    The average crude oil price in 2006 was almost flat year-over-year with a
three percent increase to $68.71 per bbl from $66.69 per bbl in the same
period a year earlier. The Company's crude oil price in 2006 averaged $4.09
per bbl less than the Edmonton Light Crude Oil benchmark price of $72.80 per
bbl.
    In the fourth quarter of 2006, the Company's average crude oil price was
$54.80 per bbl, which includes a reduction of $4.30 per bbl for an
over-accrual of $73,000 in oil revenues at Vulcan in September 2006.
    The Company did not employ commodity hedges during 2006 and does not have
any hedges in place as of the date of this report.

    
    Revenue

    ($ thousands except as indicated)
                Three      Three                Twelve     Twelve
               months     months                months     months
                ended      ended                 ended      ended
             December   December              December   December
                   31         31          %         31         31          %
    -------------------------------------------------------------------------
                 2006       2005     Change       2006       2005     Change
    -------------------------------------------------------------------------
    Gross oil
     revenues   1,027        714         44      4,339      2,256         92
    Gross NGL
     revenues     464        205        126      1,161        628         85
    Gross
     natural
     gas
     revenues   4,788      6,465        (26)    16,750     18,220         (8)
    Royalty
     income         6         31        (81)       108        104          4
    -------------------------------------------------------------------------
    Total
     production
     revenue    6,285      7,415        (15)    22,358     21,208          5
    -------------------------------------------------------------------------
    Total
     production
     revenue
     ($/BOE)    46.19      68.27        (32)     44.29      55.04        (20)
    -------------------------------------------------------------------------
    Interest and
     other
     income        32          1      2,103         45         25         80
    -------------------------------------------------------------------------
    Total
     revenue    6,317      7,416        (15)    22,403     21,233          6
    -------------------------------------------------------------------------
    Total
     revenue
     ($/BOE)    46.42      68.28        (32)     44.37      55.10        (19)
    -------------------------------------------------------------------------
    

    Total production revenues per BOE for the twelve months ended December
31, 2006 decreased 20 percent compared to the same period of 2005, primarily
due to lower natural gas price during 2006, but total production revenue
increased six percent compared to the same period in 2005, as the combination
of higher 2006 total production volumes and the Company's increased weighting
to crude oil and NGL was sufficient to offset the lower natural gas price.
    Total production revenues for the three months ended December 31, 2006
were down 15 percent as the average price for natural gas dropped 37 percent
compared to the same period of 2005. The lowest quarterly average natural gas
price in 2006 occurred during the fourth quarter of 2006 and contrasted
unfavourably with the highest quarterly average natural gas price in same
period of 2005.

    
    Royalties

    ($ thousands except as indicated)

                Three      Three                Twelve     Twelve
               months     months                months     months
                ended      ended                 ended      ended
             December   December              December   December
                   31         31          %         31         31          %
    -------------------------------------------------------------------------
                 2006       2005     Change       2006       2005     Change
    -------------------------------------------------------------------------
    Crown
     royalties  1,202      1,218         (1)     4,475      3,717         20
    Gross
     overriding
     and
     freehold
     royalties    499        634        (21)     1,839      1,661         11
    -------------------------------------------------------------------------
    Subtotal    1,701      1,852         (8)     6,314      5,378         17
    Alberta
     Royalty
     Tax Credit  (123)       (65)        90       (492)      (210)       134
    ADOE Royalty
     credits(1)  (253)      (640)       (61)    (1,122)    (2,061)       (46)
    Alberta
     Capital
     and
     Processing
     Fee Credit
     ("GCA")      (43)       (30)        43       (207)      (232)       (11)
    -------------------------------------------------------------------------
    Net
     Royalties  1,282      1,117         15      4,493      2,875         56
    -------------------------------------------------------------------------
    $/BOE        9.43      10.29         (8)      8.90       7.46         19
    Average
     corporate
     royalty
     rate
     (percent)   20.4       15.1         35       20.1       13.6         48
    -------------------------------------------------------------------------

    (1) Royalty credits are related to the Alberta Department of Energy
        ("ADOE Royalty Credit") financial assistance program for operators of
        gas wells shut-in by the AEUB bitumen conservation policy, which
        became effective in October 2004. If the AEUB subsequently approves
        production from shut-in zones, gas producers will pay an incremental
        gross over-riding royalty ("GORR") to the Crown along with Crown
        royalties otherwise payable, based on the number of years the gas
        production was shut-in and triggered by the corresponding royalty
        credit to the operator. The GORR is established at one percent after
        the first year of shut-in, increasing at one percent per year based
        on the period of time such intervals received royalty credits, to a
        maximum GORR of 10 percent. The GORR recoverable by the Crown would
        be limited to the total royalty credit amount received by a gas well
        operator.
    

    Net royalties increased in the three and twelve months ended December 31,
2006 as compared to the same periods in 2005 as a result of increased
production volumes, higher gross overriding royalties and lower ADOE Royalty
Credits and GCA Credits. The large reduction in the ADOE Royalty Credits in
the three and twelve months ended December 31, 2006 is due to the payout of
certain wells for which the ADOE Royalty Credits are granted, the consumption
of the ADOE Royalty Credit balance-forward from 2004, the 10 percent annual
reduction in ADOE Royalty Credits as per the program, and the reduction of the
average natural gas reference price used to calculate the ADOE Royalty
Credits.
    The increase in the average corporate royalty rate for the three and
twelve months ended December 31, 2006 reflects the relative percentage
decrease in ADOE Royalty Credits as compared to total royalty payable, the
impact of the higher average royalty rates for the new Vulcan production and
an adjustment to prior period GCA credits of $0.10 million. During the three
and twelve months ended December 31, 2005, the total ADOE Royalty Credits
offset approximately 52.5 percent and 55.5 percent, respectively, of the Crown
royalties payable, whereas in the three and twelve months ended December 31,
2006 the total ADOE Royalty Credit offset approximately 21 percent and 25
percent, respectively, of the Crown royalties payable.
    The average corporate royalty rates for 2007, before credits for ARTC,
GCA, and ADOE Royalty Credits, are anticipated to be consistent with average
rates for 2006.  The ARTC program has been cancelled by the Alberta Government
effective January 1, 2007, thereby eliminating the 25 percent ARTC credit on
the first $2 million in eligible crown royalties' payable each year.

    
    Production Expenses

    ($ thousands except as indicated)

                Three      Three                Twelve     Twelve
               months     months                months     months
                ended      ended                 ended      ended
             December   December              December   December
                   31         31          %         31         31          %
    -------------------------------------------------------------------------
                 2006       2005     Change       2006       2005     Change
    -------------------------------------------------------------------------
    Operating
     expenses   1,729      1,049         65      5,219      3,852         35
    Workover
     expenses      39         99        (61)       185        389        (52)
    Lease
     rentals      114        115         (1)       309        341         (9)
    -------------------------------------------------------------------------
    Total
     production
     expenses   1,882      1,263         49      5,713      4,582         25
    -------------------------------------------------------------------------
    $/BOE       13.83      11.63         19      11.32      11.89         (5)
    -------------------------------------------------------------------------
    

    Total production expenses per BOE in the twelve months ended December 31,
2006 decreased five percent to $11.32 per BOE from $11.89 per BOE in the same
period of 2005, largely as a result of the onset of lower cost per BOE
production at Vulcan and a reduction of workover expenses.
    Total production expenses during the fourth quarter of 2006 increased
19 percent to $13.83 per BOE from $11.62 per BOE in the same period of 2005 as
a result of several non-recurring items described in the following two
paragraphs. The combination of these non-recurring items increased overall
production expense for the fourth quarter of 2006 by $350,000 or $2.57 per
BOE. The production expense for the fourth quarter of 2006 before the
non-recurring items is estimated at $11.26 per BOE.
    The Company incurred non-recurring operating expenses for plant repair
and maintenance, equipment rentals and overhead recovery adjustments and other
items totalling approximately $207,000 that added $1.52 per BOE to fourth
quarter production expense.
    At Burnt Pine, Alberta a mid-stream gas processor that contracted with
Stylus to manage its gas plant unilaterally declared its contractual
arrangements with the Company uneconomic and charged an estimated $100,000 or
$10.66 per BOE in additional operating expense for the Burnt Pine field
retroactive to August 1, 2006. Stylus has not agreed to the new fees at Burnt
Pine, but has recorded the higher costs. The Company is currently in
discussions with the facility owner to find a mutually acceptable arrangement
for fees at Burnt Pine, which represents about 50 BOE per day net. In the
fourth quarter of 2006 the mid-stream processor also invoiced additional
charges of $43,000 ($0.32 per BOE) relating to 2005 expenses for several
northeast Alberta properties. The total increase in fees related to the
mid-stream company added $1.05 per BOE to the Company's fourth quarter overall
production expense.
    In general, the Company owns and operates a portion of the infrastructure
required to produce its natural gas properties, and at some properties pays
custom processing fees to third-parties for further transportation and
processing to deliver sales gas to markets. The Company has a number of
non-core properties that have high operating costs, particularly in northeast
Alberta where in 2002 and 2003 the Company had natural gas wells shut-in as
part of the AEUB's bitumen conservation policy. The fields and the undeveloped
lands associated with the gas over bitumen areas have declined in production
with the result that the fixed operating costs associated with the gas
processing facilities are being divided into smaller volumes every year.
    At Vulcan, the Company's production expenses averaged about $8.40 per BOE
for the twelve months ended December 31, 2006. The Company's oil battery and
compressor facility are fully operational now that the Good Production
Practice approval has been received; and therefore, production expenses are
expected to trend lower in 2007. As of the date of this report, Vulcan
represents about 56 percent of the Company's current total production, and the
Company's total production expenses per BOE are also anticipated to trend
lower in 2007.

    
    Transportation Expenses

    ($ thousands except as indicated)

                Three      Three                Twelve     Twelve
               months     months                months     months
                ended      ended                 ended      ended
             December   December              December   December
                   31         31          %         31         31          %
    -------------------------------------------------------------------------
                 2006       2005     Change       2006       2005     Change
    -------------------------------------------------------------------------
    Transportation
     expenses     166        120         38        611        488         25
    -------------------------------------------------------------------------
    $/BOE        1.22       1.11         10       1.21       1.27         (5)
    -------------------------------------------------------------------------

    Transportation expenses increased in the three and twelve months ended
December 31, 2006 as a result of increased volumes. The Company anticipates
that transportation expenses per BOE for 2007 will be similar to the
transportation expenses per BOE recorded for the twelve months ended
December 31, 2006.

    General and Administration Expenses

    ($ thousands except as indicated)

                Three      Three                Twelve     Twelve
               months     months                months     months
                ended      ended                 ended      ended
             December   December              December   December
                   31         31          %         31         31          %
    -------------------------------------------------------------------------
                 2006       2005     Change       2006       2005     Change
    -------------------------------------------------------------------------
    Gross G&A
     expenses   1,122       922          22      4,168      3,401         23
    Less
     overhead
     recoveries  (334)     (167)        100     (1,223)      (564)       117
    Less
     capitalized
     overhead     (58)     (109)        (47)      (350)      (364)        (4)
    -------------------------------------------------------------------------
    Net G&A
     expenses     731       646          13      2,596      2,473          5
    -------------------------------------------------------------------------
    $/BOE        5.37      5.95         (10)      5.14       6.43        (20)
    

    Total gross and net general and administrative ("G&A") expenses for the
twelve months ended December 31, 2006 increased compared to the same period in
2005 primarily as a result of additional employees and consultant costs.
    The increase in the net expenses for the three months ended December 31,
2006 compared to the same period for 2005 is primarily due to increased salary
costs and includes $55,000 ($0.40 per BOE) of consulting costs associated with
the design of internal controls. Multilateral Instrument 52-109 ("52-109")
requires certification at December 31, 2006 by the Chief Executive Officer
("CEO") and the Chief Financial Officer ("CFO") that the Company has designed
a process of internal control over financial reporting to provide reasonable
assurance regarding the reliability of financial reporting and the preparation
of consolidated financial statements for external purposes.
    The higher production volumes for the three and twelve months ended
December 31, 2006 resulted in lower per BOE net G&A expenses as compared to
the same period for 2005.
    The Company-operated capital program and production operations generated
overhead recoveries. The larger capital program in 2006 resulted in higher
total operator overhead recoveries for the three and twelve months ended
December 31, 2006 as compared to the same periods in 2005.
    Effective March 1, 2005, the Company began capitalizing the portion of
salaries of certain employees directly related to exploration activities of
the Company. In the fourth quarter of 2006, a total of $58,000 of exploration
salaries was capitalized and a total of $350,000 was capitalized for the
twelve months ended December 31, 2006.
    G&A expenses noted in the table above do not include stock-based
compensation costs, which are shown separately in the Non-cash Stock-based
Compensation Expense table that follows.
    The Company is appropriately staffed for the scope of its current capital
program and production operations. The G&A expenses for 2007 are anticipated
to be similar to those for 2006.

    
    Non-cash Stock-based Compensation Expense

    ($ thousands except as indicated)

                Three      Three                Twelve     Twelve
               months     months                months     months
                ended      ended                 ended      ended
             December   December              December   December
                   31         31          %         31         31          %
    -------------------------------------------------------------------------
                 2006       2005     Change       2006       2005     Change
    -------------------------------------------------------------------------
    Total
     non-cash
     stock-based
     compensation
     expense      168        226        (26)       604       447         35

    Less: portion
     capitalized
     to property
     and
     equipment    (10)       (28)       (64)       (81)      (71)        14
    -------------------------------------------------------------------------
    Net non-cash
     stock-based
     compensation
     expense      158        198        (20)       523       376         39
    -------------------------------------------------------------------------
    $/BOE         1.16      1.82        (36)      1.04       0.97         7
    -------------------------------------------------------------------------
    

    The Company accounts for its stock-based compensation plan using the
fair-value method and a Black-Scholes option pricing model. Under this method,
compensation costs are charged over the vesting period for the stock options
with a corresponding increase to contributed surplus. Net non-cash stock-based
compensation expense increased for the twelve months ended December 31, 2006
compared to the same period for 2005 due to additional stock options granted
in the third quarter of 2006.
    In the second quarter of 2006, 10,000 options were granted, 15,000
options were cancelled and 48,000 options were exercised. During the three
months ended September 30, 2006, the Company granted 568,000 options to
directors, officers and employees of Stylus and 62,778 options were cancelled.
During the three months ended December 31, 2006, no options were granted,
5,000 options were cancelled and 85,553 options were exercised.
    Effective March 1, 2005, the Company began capitalizing the stock-based
compensation of employees directly involved in exploration activities of the
Company.

    
    Interest Expense
    ($ thousands except as indicated)

                     Three     Three              Twelve    Twelve
                    months    months              months    months
                     ended     ended               ended     ended
                  December  December            December  December
                        31        31         %        31        31         %
    -------------------------------------------------------------------------
                      2006      2005    Change      2006      2005    Change
    -------------------------------------------------------------------------
    Bank loan
     interest
     expense           309       104       197       728       331       120
    Part 12.6
     interest
     expense             -         -         -       159         -         -
    -------------------------------------------------------------------------
    Total interest
     expense           309       104       197       887       331       168
    -------------------------------------------------------------------------
    Total interest
     expense
     ($/BOE)          2.27      0.96       136      1.76      0.86       105
    -------------------------------------------------------------------------
    

    For the three and twelve months ended December 31, 2006, bank loan
interest expense increased compared to the same periods of 2005 due to the
increase in the amount of bank debt. Bank debt has risen in 2006 as a result
of the increased expenditures on capital projects during the twelve months
ended December 31, 2006 relative to the same period of 2005.
    Part 12.6 interest expense accrual of $0.16 million is a non-recurring
expense related to the Canada Revenue Agency ("CRA") audits of Kinloch and of
a predecessor company acquired by Kinloch for the 2002 and 2003 taxation
years. As a result of the audits, tax deductions related to certain wells
classified as Canadian Exploration Expense ("CEE") and renounced to
subscribers pursuant to flow-through share issues were reclassified by the CRA
as Canadian Development Expense. As a result of the reclassification, Stylus
anticipates being assessed Part 12.6 interest and penalties totalling
$158,273, which are included in the total interest expense for the
twelve months ended December 31, 2006.

    
    Depletion, Depreciation and Accretion Expense ("DD&A")
    ($ thousands except as indicated)

                     Three     Three              Twelve    Twelve
                    months    months              months    months
                     ended     ended               ended     ended
                  December  December            December  December
                        31        31         %        31        31         %
    -------------------------------------------------------------------------
                      2006      2005    Change      2006      2005    Change
    -------------------------------------------------------------------------
    Depletion and
     depreciation    3,830     2,327        65    12,734     7,863        62
    Accretion
     expense            72        39        85       200       150        33
    -------------------------------------------------------------------------
    Total DD&A       3,902     2,366        65    12,934     8,013        61
    -------------------------------------------------------------------------
    Total DD&A
     ($/BOE)         28.68     21.79        32     25.62     20.80        23
    -------------------------------------------------------------------------
    

    The Company engages McDaniel & Associates Consultants Ltd. to prepare an
independent evaluation of the proved and probable reserves of the Company in
accordance with National Instrument 51-101 ("NI 51-101") relating to reserve
estimates. Under NI 51-101, proved reserves are defined as having a high
degree of certainty to be recoverable and the targeted level of certainty, in
aggregate, is at least 90 percent probability that the quantities actually
recovered will equal or exceed the estimated proved reserves.
    The Company' exploration focus in southern Alberta is to drill
exploration farmin wells to earn petroleum and natural gas interests from
industry competitors. These farmin wells earn undeveloped lands for the
Company and are added to the DD&A pool as the costs are incurred. In 2006, the
Company spent $10.5 million net (48 percent) of its total drilling and
completion expenditures and $4.3 million net (63 percent) of its total
production equipment and facilities expenditures at Vulcan.  In addition, a
further $5.7 million in drilling and completion expenditures were incurred at
Champion and Monarch, projects that are still in the exploration phase of
development.  Most of the wells associated with these costs are included in
the DD&A calculation, but did not produce during 2006. The lack of production
history for these wells results in reserve assignments that are weighted to
probable reserves, which increased 41 percent in 2006 compared to 2005.
    The DD&A expense calculation uses only proved reserves; therefore, the
per BOE DD&A rate for the three and twelve months ended December 31, 2006 has
increased compared to the same periods in 2005.The DD&A pool increased
52 percent during the twelve months ended December 31, 2006, whereas total
proved reserves increased by seven percent in 2006 as compared to the prior
year. The total DD&A rate is anticipated to drop as probable reserves move
into proven reserves in 2007.
    The DD&A pool excludes $8.2 million of net book value for undeveloped
land and $15.2 million for seismic. Independent evaluators have appraised the
fair market value of the Company's undeveloped land and seismic as greater
than book value as at December 31, 2006.  Undeveloped land book values are
moved into the DD&A pool at the expiry date of the land or when developed. For
seismic, if the net book value is greater than the appraised value at a
property level, the difference is moved into the depletion pool quarterly as
the seismic is used.
    For the twelve months ended December 31, 2006, accretion expense was
$0.20 million versus $0.15 million for the twelve months ended December 31,
2005. For the three months ended December 31, 2006, accretion expense was
$0.07 million compared to $0.04 million for the three months ended
December 31, 2005.

    
    Income Taxes
    ($ thousands)

                                         Three     Three    Twelve    Twelve
                                        months    months    months    months
                                         ended     ended     ended     ended
                                      December  December  December  December
                                            31        31        31        31
    -------------------------------------------------------------------------
                                          2006      2005      2006      2005
    -------------------------------------------------------------------------
    Large corporations tax                 (14)       15       (13)       15
    Future income tax expense
     (recovery)                           (406)      703    (1,701)      535
    -------------------------------------------------------------------------
    Total tax expense (recovery)          (420)      718    (1,714)      550
    -------------------------------------------------------------------------
    

    The Company records future tax assets and liabilities to account for the
expected future tax consequences of events that have been recorded in its
consolidated financial statements and its tax returns. These amounts are
estimates and the actual tax consequences may differ from the estimates due to
changing tax rates and regimes, as well as changing estimates of cash flows
and capital expenditures in current and future periods. A valuation allowance
is recorded to the extent that there is uncertainty regarding utilization of
future tax assets.
    Stylus recorded an income tax recovery in the year ended December 31,
2006 of $1.7 million based on its pre-tax loss of $5.4 million.
Notwithstanding the statutory tax rate for 2006 is 32.49 percent, as a result
of reductions in the projected Federal and Alberta Provincial income tax
rates, the estimated average future income tax rate decreased to approximately
29.0 percent.  The reduction in future tax rate contributed approximately
$0.37 million of the total future income tax recovery in the second quarter.
    Current income tax recovery in the year 2006 relates to reversal of prior
years accruals due to acquisitions and amalgamations.
    On December 6, 2005, the Company issued $5 million of flow-through
shares. In accordance with Canadian generally accepted accounting principles
and the Emerging Issues Abstract 146 - Flow Through Shares publication, when
the CEE were renounced in the first quarter of 2006, the future income tax
liability was increased and the share capital was reduced by approximately
$1.69 million.
    On June 30, 2006, the Company issued 2,106,000 flow-through common shares
at $4.75 per share for gross proceeds of $10,003,500 less share issue costs of
$676,280. In February 2007, in accordance with the terms of its flow-through
offering described above and pursuant to certain provisions of the Income Tax
Act (Canada), the Company, effective December 31, 2006, renounced to the flow-
through subscribers, for income tax purposes, CEE incurred and to be incurred
in the aggregate amount of $10,003,500. As a result, share capital will be
reduced and the future income tax liability will be increased by approximately
$2,900,000 in the first quarter of 2007 to reflect the tax benefits of the
expenditures renounced.
    On December 6, 2006, the Company issued 1,341,500 flow-through common
shares at $4.10 per share for gross proceeds of $5,500,150 less share issue
costs of $361,770. In February 2007, in accordance with the terms of its flow-
through offering described above and pursuant to certain provisions of the
Income Tax Act (Canada), the Company, effective December 31, 2006, renounced
to the flow-through subscribers, for income tax purposes, CEE incurred and to
be incurred in the aggregate amount of $5,500,150. As a result, share capital
will be reduced and the future income tax liability will be increased by
approximately $1,600,000 in the first quarter of 2007 to reflect the tax
benefits of the expenditures renounced.
    The estimated tax pool balances shown in the table below are before the
renunciation of $15.5 million in CEE pools related to the 2006 flow-through
financings. The renunciations occur in February 2007 and will be reflected in
the first quarter 2007 financial statements.

    
    ($ thousands)
    -------------------------------------------------------------------------
    As at December 31                                      2006         2005
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    Undepreciated capital costs                          13,572        8,865
    -------------------------------------------------------------------------
    Canadian oil and gas property expense                 7,147        6,320
    -------------------------------------------------------------------------
    Canadian exploration expense                         29,562        9,869
    -------------------------------------------------------------------------
    Canadian development expense                         17,449       13,143
    -------------------------------------------------------------------------
    Non-capital loss carry forward                        5,258        6,241
    -------------------------------------------------------------------------
    Successor pools                                       4,701        6,946
    -------------------------------------------------------------------------
    Other                                                     -        2,136
    -------------------------------------------------------------------------
    Total estimated income tax pools                     77,689       53,520
    -------------------------------------------------------------------------


    Funds and Earnings

    ($ thousand except as indicated)

                     Three     Three              Twelve    Twelve
                    months    months              months    months
                     ended     ended               ended     ended
                  December  December            December  December
                        31        31         %        31        31         %
    -------------------------------------------------------------------------
                      2006      2005    Change      2006      2005    Change
    -------------------------------------------------------------------------
    Net income
     (loss) for
     the period     (1,694)      884      (292)   (3,640)    1,544      (336)
    Net income
     (loss) per
     share
    Basic and
     diluted ($)     (0.06)     0.04      (250)    (0.14)     0.08      (175)
    Add (deduct)
     items not
     requiring
     cash:
    Interest on
     restricted
     cash                -         -         -         -        (6)     (100)
    Depletion and
     depreciation    3,830     2,327        65    12,734     7,863        62
    Stock-based
     compensation      158       198       (20)      523       376        39
    Accretion
     expense            72        39        85       200       150        33
    Future income
     tax (recovery)
     expense          (406)      703      (158)   (1,701)      535      (418)
    -------------------------------------------------------------------------
    Funds from
     operations(1)   1,960     4,151       (50)    8,323    10,940       (24)
    Funds from
     operations
     per share(1)
    Basic ($)         0.08      0.19       (58)     0.33      0.55       (40)
    -------------------------------------------------------------------------
    Diluted ($)       0.08      0.18       (56)     0.32      0.53       (40)
    -------------------------------------------------------------------------
    (1) See "Non-GAAP Measurements" in Advisories.
    

    Total funds from operations decreased during the three and twelve months
ended December 31, 2006 compared to the same periods of 2005 primarily due to
lower natural gas pricing received by the Company during 2006 compared to
2005. Increases in the number of shares outstanding as a result of equity
financings in December 2005, June 2006 and December 2006 also contributed to a
decrease in the funds from operations per share for the three and
twelve months ended December 31, 2006 compared to the same periods in 2005.
    The net loss for the twelve months ended December 31, 2006 was negatively
impacted by lower funds from operations related to lower natural gas prices
and higher DD&A costs and were partially offset by higher production volumes,
lower per BOE operating and G&A costs, and future income tax recoveries.

    Operating Netbacks

    The following tables set forth the Company's operating netbacks for the
twelve months ended December 31, 2006 and 2005.

    
                                Twelve months ended December 31, 2006
    -------------------------------------------------------------------------

                                         Crude   Natural
                                           oil       gas       NGL     Total
                                        ($/bbl)   ($/mcf)   ($/bbl)   ($/BOE)
    -------------------------------------------------------------------------
    Price                                68.71      6.59     64.29     44.29
    Royalties (net)                      (9.07)    (1.45)   (12.80)    (8.90)
    Production expense                   (9.62)    (1.94)    (8.98)   (11.32)
    Transportation                       (2.14)    (0.16)    (3.13)    (1.21)
    -------------------------------------------------------------------------

    Operating netback(1)                 47.88      3.04     39.38     22.86

    Net interest expense(2)                                            (1.67)
    General and administrative                                         (5.14)
    Current taxes                                                       0.02
    -------------------------------------------------------------------------

    Funds from operations netback(1)                                   16.07

    Stock-based compensation                                           (1.04)
    Depletion, depreciation & accretion                               (25.62)
    Future income tax recovery                                          3.37
    -------------------------------------------------------------------------

    Earnings (loss) netback(1)                                         (7.21)
    -------------------------------------------------------------------------
    Note:  Rounding has been applied to amounts within this table.

                                Twelve months ended December 31, 2006
    -------------------------------------------------------------------------

                                         Crude   Natural
                                           oil       gas       NGL     Total
                                        ($/bbl)   ($/mcf)   ($/bbl)   ($/BOE)
    -------------------------------------------------------------------------
    Price                                66.69      8.93     54.76     55.04
    Royalties (net)                      (7.89)    (1.19)   (16.10)    (7.46)
    Production expense                   (1.20)    (0.21)    (1.23)    (1.27)
    Transportation                      (14.40)    (1.92)   (14.74)   (11.89)
    -------------------------------------------------------------------------

    Operating netback(1)                 43.20      5.60     22.69     34.42

    Net Interest expense(2)                                            (0.80)
    General and administrative                                         (6.43)
    Current taxes                                                      (0.04)
    -------------------------------------------------------------------------

    Funds from operations netback(1)                                   27.15

    Stock-based compensation                                           (0.97)
    Depletion, depreciation & accretion                               (20.80)
    Future income tax (expense)                                        (1.39)
    -------------------------------------------------------------------------

    Earnings netback(1)                                                 4.00
    -------------------------------------------------------------------------
    Note:  Rounding has been applied to amounts within this table.

    (1) The terms "funds from operations" and "netbacks" are non-GAAP
        measures. The Company uses these measures to help evaluate its
        performance. These measurements should not be  considered an
        alternative to, or more meaningful than net earnings or funds
        provided by operations as determined in accordance with GAAP as an
        indicator of the Company's performance.
    (2) Net interest expense is interest expense less interest and other non-
        oil and gas income.


    Additions To Property and Equipment Expenditures

    ($ thousands)

                                         Three     Three    Twelve    Twelve
                                        months    months    months    months
                                         ended     ended     ended     ended
                                      December  December  December  December
                                            31        31        31        31
    -------------------------------------------------------------------------
                                          2006      2005      2006      2005
    -------------------------------------------------------------------------
    Undeveloped land                       113     1,222     2,126     1,518
    Geological and geophysical             (53)    3,816     6,495     5,493
    Exploration and development
     drilling and completions            4,077     5,330    23,798    11,449
    Production equipment and
     facilities                          1,779       337     6,822     2,073
    -------------------------------------------------------------------------
    Proceeds on the disposal of
     properties                         (1,400)        -    (1,780)        -
    -------------------------------------------------------------------------
    Total exploration and development
     expenditures (net of
     dispositions)                       4,516    10,705    37,461    20,533
    Other                                   46        23       191       185
    -------------------------------------------------------------------------
    Total expenditures before the
     following                           4,562    10,728    37,652    20,718
    Kinloch corporate acquisition            -       209         -    28,887
    904217 Alberta Ltd. corporate
     acquisition                             -        39         -       736
    Asset retirement costs                 754        50     2,697       433
    Capitalized stock-based
     compensation                           10        29        81        72
    -------------------------------------------------------------------------
    Total property and equipment
     expenditures                        5,326    11,055    40,430    50,846
    -------------------------------------------------------------------------
    

    During the twelve months ended December 31, 2006, the Company drilled
38 (25.2 net) wells with a 74 (71 net) percent success rate, resulting in 21
(13.9 net) gas wells and seven (4.8 net) oil wells. For the three months ended
December 31, 2006, the Company drilled four (3.3 net) wells with 100 percent
net success rate, resulting in two (2.0 net) gas wells and two (1.3 net) oil
wells. Drilling activities were primarily located in the Vulcan and Champion
areas of southern Alberta.
    Effective June 1, 2006 and closing July 13, 2006, the Company sold a
northeast Alberta producing well for net proceeds of $0.38 million. The
Company has recognized the revenues and expenses from this well until the
closing date. The average production from this well was seven BOE per day.
Effective July 1, 2006 and closing on October 26, 2006, the Company closed the
sale of two northeast Alberta wells producing approximately seven BOE/d, net
4,800 acres of undeveloped lands and a 0.95 percent royalty interest
generating approximately $4,000 per month for net proceeds of $1.4 million.
Other than the forgoing two sales, the Company sold no producing assets during
2006.
    On February 28, 2005, Stylus Exploration acquired all of the issued and
outstanding common shares  of Kinloch by way of a reverse takeover. Effective
March 1, 2005, Stylus Exploration and Kinloch were amalgamated to form a new
company called Stylus Energy Inc. Effective September 1, 2005, Stylus acquired
all of the issued and outstanding common shares of 904217 Alberta Ltd.

    Liquidity and Capital

    At December 31, 2006, the Company had a working capital deficiency of
$23.0 million, which included bank debt of $20.8 million.
    During the twelve months ended December 31, 2006, capital expenditures
were financed from funds from operations, bank debt, working capital and the
net proceeds of the June 30, 2006 and December 6, 2006 private placements.
During 2006 the Company sold two minor properties for net proceeds of
$1.78 million.
    The main investing activities of the Company in the twelve months ended
December 31, 2006 were in exploration and development drilling and completions
and seismic programs.
    The Company's future investing activities, which consist primarily of
capital expenditures on oil and gas activities, will be funded with funds from
operations, bank debt and equity.
    The Company has a $23.0 million extendable revolving credit facility with
a Canadian chartered bank. Under the terms of this facility, interest is paid
monthly in arrears at the bank's prime lending rate.  The extendable revolving
term credit facility is subject to review on or before May 31, 2007, and
specifies no repayment terms provided certain covenants related to the
facility are met. A first floating-charge debenture over all properties of the
Company has been provided as security. As of December 31, 2006, $20,796,260
(December 31, 2005 - $3,693,734) has been drawn against the facility with an
effective interest rate of 6.0 percent.
    The Company had no commodity hedges in place at December 31, 2006 or
2005.

    Subsequent Event

    On January 1, 2007, 904217 Alberta Ltd., a wholly owned subsidiary of
Stylus, was amalgamated with the Company and the combined entity continued
operations as a new company, also called Stylus Energy Inc.

    Selected Annual Information

    The following table sets forth certain annual information of the Company
and has been prepared in accordance with Canadian GAAP.

    
    ($ thousands except per share data)

                                                December  December  December
                                                      31        31        31
    Twelve Months Ended                             2006      2005      2004
    -------------------------------------------------------------------------
    Total production volumes (boe/d)               1,383     1,056       543
    Natural gas price ($/mcf)                       6.59      8.93      6.43
    Total production revenue(1)                   22,358    21,208     7,704
    Depletion, depreciation & accretion           12,933     8,013     3.529
    Net earnings (loss)                           (3,640)    1,544      (761)
    Per share - basic and diluted                  (0.14)     0.08     (0.07)
    Funds from operations(2)                       8,323    10,940     2,880
    Per share - basic                               0.33      0.55      0.27
              - diluted                             0.32      0.53      0.27
    Total Assets                                  97,103    67,648    23,811
    Working capital (deficiency)                 (23,024)   (7,090)    1,181
    (1) Shown after restatement for transportation expense adjustment and
        changes to capital structure, and before royalties.
    (2) See "Non-GAAP Measurements" in Advisories.
    

    Factors that caused variation over the years:

    On February 28, 2005, the Company closed its corporate acquisition of
Kinloch followed by an amalgamation on March 1, 2005 of Stylus Exploration and
Kinloch to form Stylus. This corporate acquisition contributed the largest
component to the increase in sales volumes, revenue, and total assets in 2005
as compared to 2004.
    During 2005, average gas prices increased 39% due to the impact of
hurricanes disrupting natural gas production in the Gulf of Mexico and the
onset of the winter heating season in the second half of the year. The
commodity price increase was a major contributor to the increase in both net
income and funds from operations in 2005.
    On December 6, 2005, the Company issued 2,510,000 common shares which
impacted the per share calculations.
    During 2006, volumes increased as a result of bringing on additional
production at the Vulcan area of southern Alberta but this was offset by the
fact that average gas selling prices fell by 26 percent as mild weather
resulted in a surplus of natural gas storage in mid-2006.  The result was a
moderate increase in production revenues.
    Depletion, depreciation, accretion increased relative to revenue in 2006
as the expenditures in the DD&A pool increased 52 percent during 2006, whereas
total proved reserves increased by 7 percent in the year. The total DD&A rate
is anticipated to drop as probable reserves move into proven reserves in 2007.
    Net earnings are influenced by future income taxes, which are impacted by
changes to the federal and provincial income tax rates for the oil and gas
industry.
    Working capital was reduced upon assumption of short-term bank debt
resulting from the corporate acquisition of Kinloch on March 1, 2005.  The
size of the working capital deficiency increased in 2006 as a result of
capital expenditures during the year.

    Quarterly Financial Information

    The following table sets forth certain quarterly information of the
Company and has been prepared in accordance with Canadian GAAP.

    
    ($ thousands except per share data)

                                  Dec 31      Sep 30      Jun 30      Mar 31
    Three Months Ended              2006        2006        2006        2006
    -------------------------------------------------------------------------
    Production volume
    Crude oil (bbl/d)                204         230         129         128
    NGL (bbl/d)                       76          52          42          27
    Natural gas (mmcf/d)             7.2         7.5         6.6         6.6
    Total (BOE/d)                  1,479       1,523       1,277       1,250
    Commodity price
    Crude oil ($/bbl)              54.80       76.45       73.91       71.87
    NGL ($/bbl)                    66.56       68.65       56.05       62.13
    Natural gas ($/mcf)             7.23        5.78        6.10        7.31
    Production revenue(1)          6,283       5,946       4,785       5,353
    Royalty expense               (1,282)     (1,425)       (960)       (825)
    Production expense(3)         (2,048)     (1,503)     (1,495)     (1,277)
    General & administrative
     expense (net)                  (731)       (589)       (615)       (661)
    Net interest expense(2)         (277)       (166)       (171)       (239)
    Current taxes                     14          (2)                     (1)
    Funds from operations(4)       1,960       2,261       1,544       2,351
    Per share - basic               0.08        0.09        0.06        0.10
              - diluted             0.08        0.08        0.06        0.10
    Stock-based compensation        (158)       (162)        (71)       (133)
    Depletion, depreciation
     & accretion                  (3,902)     (3,685)     (2,742)     (2,604)
    Future income tax (expense)
     recovery                        406         461         740          94
    Net earnings (loss)           (1,694)     (1,125)       (529)       (292)
    Per share - basic and diluted  (0.06)      (0.04)      (0.02)      (0.01)


                                  Dec 31      Sep 30      Jun 30      Mar 31
    Three Months Ended              2005        2005        2005        2005
    -------------------------------------------------------------------------
    Production volume
    Crude oil (bbl/d)                114         103         108          45
    NGL (bbl/d)                       40          38          30          17
    Natural gas (mmcf/d)             6.2         5.9         5.9         4.4
    Total (BOE/d)                  1,181       1,126       1,119         792
    Commodity price
    Crude oil ($/bbl)              68.24       70.47       61.03       67.45
    NGL ($/bbl)                    55.93       60.71       42.78       60.01
    Natural gas ($/mcf)             11.4        9.25        7.52        6.85
    Production revenue(1)          7,415       5,954       4,758       3,082
    Royalty expense               (1,117)     (1,017)       (343)       (399)
    Production expense(3)         (1,383)     (1,326)     (1,355)     (1,005)
    General & administrative
     expense (net)                  (646)       (639)       (718)       (470)
    Net interest expense(2)         (103)       (123)        (75)         (8)
    Current taxes                    (15)          -           -           -
    Funds from operations(4)       4,151       2,850       2,266       1,202
    Per share - basic               0.19        0.13        0.11        0.08
              - diluted             0.18        0.13        0.10        0.08
    Stock-based compensation        (198)        (98)        (67)        (13)
    Depletion, depreciation
     & accretion                  (2,366)     (2,099)     (2,096)     (1,452)
    Future income tax (expense)
     recovery                       (703)       (137)       (245)        549
    Net earnings (loss)              884         517        (142)        286
    Per share - basic and diluted   0.04        0.02       (0.01)       0.02

    (1) Shown after restatement for transportation expense adjustment and
        changes to capital structure, and before royalties.
    (2) Net interest expense is interest expense less interest and other non-
        oil and gas income.
    (3) Includes transportation expense.
    (4) See "Non-GAAP Measurements" in Advisories.
    

    Factors that caused variation over the quarters:

    At some of its properties, the Company conducts its maintenance and
workover operations only in the winter months. As such, production expenses
are usually higher in the first quarter of each year.
    On February 28, 2005, the Company closed its corporate acquisition of
Kinloch followed by an amalgamation on March 1, 2005 of Stylus Exploration and
Kinloch to form Stylus. This corporate acquisition contributed the largest
component in the sales volume increases in the second, third and fourth
quarters of 2005.
    During the third quarter of 2005, average gas prices increased
$1.73 per mcf due to the impact of hurricanes disrupting natural gas
production in the Gulf of Mexico. The commodity price increase was the major
contributor to the increase in both net income and funds from operations in
the third quarter of 2005.
    During the fourth quarter of 2005, gas prices increased into the winter
heating season and were $2.15 per mcf higher than in the third quarter of
2005. This contributed to the increase in net income and funds from operations
during the fourth quarter of 2005. On December 6, 2005, the Company issued
2,510,000 common shares which impacted the per share calculations.
    During the first quarter of 2006, average gas selling prices fell by
36 percent or $4.09 per mcf to $7.31 per mcf from the average gas selling
price of $11.40 per mcf in the fourth quarter of 2005. This contributed to a
net loss and decrease in funds from operations during the first quarter of
2006.
    During the second quarter of 2006, average gas selling prices fell by
17 percent or $1.21 per mcf to $6.10 per mcf from the average gas selling
price of $7.31 per mcf in the first quarter of 2006. Operating costs were
higher in the second quarter due to start-up costs at Vulcan.
    During the third quarter of 2006, natural gas prices decreased by an
additional five percent or $0.32 per mcf to $5.78 per mcf as compared to the
average second quarter natural gas price of $6.10 per mcf. Volumes increased
as a result of bringing on additional production at the Vulcan area of
southern Alberta.
    During the fourth quarter of 2006 production volumes decreased slightly
while natural gas selling prices increased by 25 percent or $1.45 per mcf.
Operating cost were higher on a per unit basis due to higher than expected
repairs and maintenance costs, increased gathering and processing costs that
resulted from a new contract on the certain of the Company's northeast Alberta
producing properties and higher interest expense charges resulting from the
increase in the bank loan.
    Net earnings are influenced by depletion, depreciation, accretion and
future income taxes. The Company estimates its reserves quarterly based on its
acquisition and drilling activities. The annual reserves are determined by
independent reservoir engineers annually. Future income taxes have been
impacted by changes to the federal and provincial income tax rates for the oil
and gas industry.

    Share Capital

    On June 30, 2006, the Company issued 2,106,000 flow-through common shares
for $4.75 per share for net proceeds of $9.4 million after deducting issuance
costs. On December 6, 2006, the Company issued 1,341,500 flow-through common
shares for $4.10 per share for aggregate net proceeds of $5.1 million after
deducting issuance costs. The 2006 flow-through share financings require the
Company to incur an aggregate total of $15.5 million of qualified CEE by
December 31, 2007. As at December 31, 2006, the Company had incurred
$9.5 million of qualified CEE expenditures, leaving a remaining qualified CEE
expenditure commitment of $6.0 million for 2007. Funds raised from these flow-
through offerings are being used to finance the Company's exploration program.
    At December 31, 2006, the number of issued and outstanding common shares
of the Company was 27,650,910. At March 14, 2007, the number of issued and
outstanding common shares of the Company was 27,670,910 and there were
outstanding options to purchase an aggregate of 2,261,472 common shares.
    During 2006, there were 133,553 options exercised, and 82,777 options
were cancelled. Options to purchase 2,281,472 common shares were outstanding
as at December 31, 2006.

    Contractual Obligations
    
    -------------------------------------------------------------------------
                                       2008 -     2010 -
    ($)                     2007       2009       2011       2012      Total
    -------------------------------------------------------------------------
    Operating leases     255,000    455,000    113,000          -    823,000
    -------------------------------------------------------------------------
    

    Operating leases include $54,500 per quarter for an office lease which
expires April 30, 2010. In addition, the Company has annual operating leases
for certain field equipment that are recorded as production expenses.

    Related Party Transactions

    There were no related party transactions during 2006.

    Critical Accounting Estimates

    The preparation of the financial statements in accordance with Canadian
GAAP requires management to make judgments and estimates that affect the
financial results of the Company. The Company's management reviews its
estimates regularly, but new information and changed circumstances may result
in actual results or changes to estimated amounts that differ materially from
current estimates. A summary of significant accounting policies are presented
in Note 2 to the financial statements. The critical estimates are discussed
below:

    Petroleum and Natural Gas Reserves

    All of The Company's petroleum and natural gas reserves are evaluated and
reported on by independent petroleum engineering consultants in accordance
with National Instrument 51-101. The evaluation of reserves is a subjective
process. Forecasts are based on engineering data, projected future rates of
production, commodity prices and the timing of future expenditures, all of
which are subject to numerous uncertainties and various interpretations. The
Company expects that its estimates of reserves will change to reflect updated
information. Reserve estimates can be revised upward or downward based on the
results of future drilling, testing, production levels and changes in costs
and commodity prices.

    Depletion Expense

    The Company uses the full cost method of accounting for exploration and
development activities whereby all costs associated with these activities are
capitalized, whether successful or not. The aggregate of capitalized costs,
net of certain costs related to unproved properties, and estimated future
development capital is amortized using the unit-of-production method based on
estimated total proved reserves. Changes in estimated total proved reserves or
future development capital have a direct impact on depletion expense.
    Certain costs related to unproved properties and seismic are excluded
from costs subject to depletion until the unproved property is drilled or
expired or their value is impaired. These properties are reviewed quarterly to
determine if the unproved properties or seismic should be included in the
depletion calculation, or for impairment, for which any write-down would be
charged to depletion and depreciation expense.

    Full Cost Accounting Ceiling Test

    The carrying value of property, plant and equipment is reviewed quarterly
for impairment. Impairment occurs when the carrying value of the assets is not
recoverable by the future undiscounted cash flows. The cost recovery ceiling
test is based on estimates of proved reserves, production rates, petroleum and
natural gas prices, future costs and other relevant assumptions. By their
nature, these estimates are subject to measurement uncertainty and the impact
on the financial statements could be material. Any ceiling test impairment
would be charged as additional depletion expense.

    Asset Retirement Obligations

    The asset retirement obligation is estimated based on existing laws,
contracts or other policies. The fair value of the obligation is based on
estimated future costs for abandonments and reclamations discounted at a
credit adjusted risk free rate. The liability is adjusted each reporting
period to reflect the passage of time, with the accretion charged to earnings
and for revisions to the estimated future cash flows. By their nature, these
estimates are subject to measurement uncertainty and the impact on the
financial statements could be material.

    Income Taxes

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

    Change in Accounting Policies and Recent Accounting Pronouncements

    There were no accounting policy changes during the current reporting
period.

    Financial Instruments

    The following standards regarding financial instruments are effective for
January 1, 2007; 3855 - "Financial Instruments - Recognition and Measurement",
3861 Financial Instruments - Disclosure and Presentation, 1530 -
"Comprehensive Income", and 3865 - "Hedges". The standards require all
financial instruments other than held-to-maturity investments, loans and
receivables, to be included on a company's balance sheet at their fair value.
Held-to-maturity investments, loans and receivables would be measured at their
amortized cost. The standards create a new statement for comprehensive income
that will include changes in the fair value of certain derivative financial
instruments. The Company has no hedges and therefore has not yet determined
the impact, if any, of adopting these standards on its results of operations
or financial position.

    Internal Control Reporting

    In March 2006 Canadian Securities Administrators decided to not proceed
with proposed National Instrument 52-111 Reporting on Internal Control over
Financial Reporting and instead proposed to expand National Instrument 52-109
Certification of Disclosure in Issuers' Annual and Interim Filings. The major
changes resulting from this is the CEO and CFO 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 a suitable control framework. This proposed
amendment is expected to apply for the year ended December 31, 2008. The
Company is continuing with its evaluation of ICOFR to ensure it meets the
criteria for the proposed certification for December 31, 2008.

    Disclosure Controls and Procedures

    Stylus has implemented a system of internal controls that it believes 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 CEO and CFO have concluded, based
on their evaluation that Stylus' 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 during
2006. It should be noted that while the Company's CEO and CFO believe that
Stylus' disclosure controls and procedures provide a reasonable level of
assurance that the system of internal controls is 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 52-109, the Company has, under the
supervision of its CEO and CFO, designed a process of internal controls over
financial reporting, which has been implemented by the Company. The process
was designed to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of consolidated financial statements
for external purposes in accordance with Canadian generally accepted
accounting principles ("GAAP") and includes those policies and procedures
that:

    

    -   Pertain to the maintenance of records that in reasonable
        detail accurately and fairly reflect the transactions and
        dispositions of Stylus' assets;

    -   Provide reasonable assurance that transactions are recorded as
        necessary to permit preparation of consolidated financial
        statements in accordance with GAAP, and that receipts and
        expenditures of the Company are being recorded only in
        accordance with authorizations of management and the board of
        directors; and

    -   Provide reasonable assurance regarding prevention or timely
        detection of unauthorized acquisition, use or disposition of
        Stylus' assets that could have a material effect on the annual
        or interim consolidated financial statements.
    

    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 Company'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 exist. As such, the CEO, CFO and Disclosure Committee continually
monitor the financial activities of the Company. It is important to note that,
in order to eliminate the potential risk associated with this issue, the
Company would be required to hire additional staff in order to provide greater
segregation of duties. Since the increased funding costs of such hiring would
be financially constrictive to Stylus, the Company 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.
    During the fourth quarter of 2006, Stylus amended its control environment
to enhance the internal controls over segregation of duties and improve
information technology application controls to enhance security and integrity
over the Company's financial data. These enhancements did not result in any
adjustments to Stylus's disclosures or its consolidated financial statements.

    Risks and Uncertainty

    The oil and gas industry is intensely competitive and is subject to
numerous risks that can affect the growth and profitability of the Company.
Corporate success is dependant on the ability of the Company to select and
acquire or find and develop oil and gas reserves in economic quantities.
Economic reserves must be marketed in an environment that is affected by many
factors which cannot be accurately predicted or controlled. These factors
include oil and gas price fluctuations, the supply and demand for oil and gas,
the ability to access financing, the ability to process and deliver the
commodities to the marketplace and extensive government regulation of taxation
and the environment.
    All phases of the oil and natural gas business present environmental
risks and hazards and are subject to environmental regulation pursuant to a
variety of federal, provincial and local laws and regulations. Compliance with
such legislation can require significant expenditures and a breach may result
in the imposition of fines and penalties, some of which may be material.
Environmental legislation is evolving in a manner expected to result in
stricter standards and enforcement, larger fines and liability and potentially
increased capital expenditures and operating costs. In 2002, the Government of
Canada ratified the Kyoto Protocol (the "Protocol"), which calls for Canada to
reduce its greenhouse gas emissions to specified levels. There has been much
public debate with respect to Canada's ability to meet these targets and the
Government's strategy or alternative strategies with respect to climate change
and the control of greenhouse gases. Implementation of strategies for reducing
greenhouse gases whether to meet the limits required by the Protocol or as
otherwise determined, could have a material impact on the nature of oil and
natural gas operations, including those of the Company. Given the evolving
nature of the debate related to climate change and the control of greenhouse
gases and resulting requirements, it is not possible to predict either the
nature of those requirements or the impact on the Company and its operations
and financial condition.
    Refer to the Annual Information Form of the Company for a more complete
list of factors that might affect the Company.
    The Company has a senior management team whose extensive industry
experience has been utilized to put together a defined plan to find, acquire
and develop reserves in areas with access to markets. The Company has reduced
the exploratory risk of finding and acquiring oil and gas by the use of
technology, including seismic and computer modeling.
    The Company carries appropriate levels of insurance to reduce the impact
of unpredictable operational and environmental occurrences.

    
    Stylus Energy Inc.

    CONSOLIDATED BALANCE SHEETS

    -------------------------------------------------------------------------
    As at December 31                                      2006         2005
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    ASSETS (note 7)
    Current
    Cash (note 5)                                   $   138,182  $   252,257
    Accounts receivable                               8,461,400    6,839,913
    Inventory                                         1,005,614      804,469
    Prepaid expenses and deposits                       435,400      385,077
    -------------------------------------------------------------------------
                                                     10,040,596    8,281,716
    Property and equipment (note 6)                  86,996,721   59,300,772
    Goodwill (note 3)                                    65,795       65,795
    -------------------------------------------------------------------------
                                                    $97,103,112  $67,648,283
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    LIABILITIES AND SHAREHOLDERS' EQUITY
    Current
    Accounts payable and accrued liabilities        $12,268,297  $11,678,459
    Bank loan (note 7)                               20,796,260    3,693,734
    -------------------------------------------------------------------------
                                                     33,064,557   15,372,193

    Asset retirement obligations (note 4)             5,164,747    3,338,000

    Future income taxes (note 9)                        658,980      966,550

    Commitments and contingencies (note 11)

    Shareholders' equity
    Share capital (note 8)                           57,761,502   44,427,145
    Contributed surplus (note 8)                      1,053,894      504,508
    Retained (deficit) earnings (note 8(d))            (600,568)   3,039,887
    -------------------------------------------------------------------------
                                                     58,214,828   47,971,540
    -------------------------------------------------------------------------
                                                    $97,103,112  $67,648,283
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    See accompanying notes


    On behalf of the Board:

    "Signed"                       "Signed"

    --------------------------     --------------------------
    Richard A. Walls, Director     Paul D. Evans, Director


    Stylus Energy Inc.
    CONSOLIDATED STATEMENTS OF INCOME (LOSS) AND RETAINED EARNINGS

    -------------------------------------------------------------------------
    Year ended December 31                                 2006         2005
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    REVENUE

    Production revenue                              $22,357,569  $21,208,165
    Royalties, net of Alberta Royalty Tax Credit     (4,492,686)  (2,874,675)
    Interest and other income                            44,829       24,759
    -------------------------------------------------------------------------
                                                     17,909,712   18,358,249
    -------------------------------------------------------------------------
    EXPENSES
    Production                                        5,712,711    4,581,815
    Transportation expense                              610,606      488,418
    General and administration (note 6)               2,595,939    2,473,709
    Stock-based compensation (note 8)                   523,097      375,628
    Interest expense (note 13)                          886,973      330,643
    Depletion, depreciation and accretion (notes 4
     and 6)                                          12,934,375    8,013,484
    -------------------------------------------------------------------------
                                                     23,263,701   16,263,697
    -------------------------------------------------------------------------
    Income (loss) before income taxes                (5,353,989)   2,094,552

    Income tax expense (Note 8 and 9)

    Large corporations tax                              (12,579)      15,000
    Future income tax expense (recovery) (note 9)    (1,700,956)     535,387
    -------------------------------------------------------------------------
                                                     (1,713,535)     550,387
    -------------------------------------------------------------------------
    Net income (loss) for the year                   (3,640,454)   1,544,165
    Retained earnings, beginning of year              3,039,887    1,495,722
    -------------------------------------------------------------------------
    Retained (deficit) earnings, end of year        $  (600,568) $ 3,039,887
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Net income (loss) per common share - basic
     and diluted (note 8)                           $     (0.14) $      0.08
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Weighted average number of shares
      - basic (note 8)                               25,277,172   20,051,406
      - diluted (note 8)                             25,277,172   20,627,090
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    See accompanying notes


    Stylus Energy Inc.
    CONSOLIDATED STATEMENTS OF CASH FLOWS

    -------------------------------------------------------------------------
    Year ended December 31                                 2006         2005
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    OPERATING ACTIVITIES
    Net income (loss) for the year                  $(3,640,454) $ 1,544,165
    Add (deduct) items not requiring cash:
      Depletion and depreciation                     12,734,667    7,863,267
      Interest on restricted cash                             -       (5,593)
      Stock-based compensation (note 8)                 523,097      375,628
      Accretion expense (note 4)                        199,708      150,217
      Future income tax expense (recovery)           (1,700,956)     535,387
    Asset retirement expenditures (note 4)           (1,070,316)     (91,142)
    Net change in non-cash working
     capital (note 12)                                  596,800     (541,748)
    -------------------------------------------------------------------------
                                                      7,642,546   10,306,675
    -------------------------------------------------------------------------

    FINANCING ACTIVITIES
    Proceeds from issuance of common
     shares (note 8)                                 15,503,650   10,044,000
    Share issue costs (note 8)                       (1,038,049)  (1,156,195)
    Proceeds from options exercised for
     cash (note 8)                                      207,352      476,494
    Increase (decrease) in bank loan                 17,102,526   (3,324,693)
    -------------------------------------------------------------------------
                                                     31,775,479    5,563,112
    -------------------------------------------------------------------------

    INVESTING ACTIVITIES
    Expenditures on property and equipment          (39,432,183) (20,718,701)
    Proceeds on disposal of properties                1,780,000            -
    Restricted cash                                           -      510,975
    Cash paid upon acquisition, net of
     cash acquired (note 3)                                   -      (90,257)
    Business acquisition transaction costs (note 3)           -     (149,283)
    Net change in non-cash working capital
     (note 12)                                       (1,879,917)   2,090,139
    -------------------------------------------------------------------------
                                                    (39,532,100) (18,357,127)
    -------------------------------------------------------------------------

    Decrease in cash                                   (114,075)  (2,487,340)
    Cash, beginning of year                             252,257    2,739,597
    -------------------------------------------------------------------------
    Cash, end of year                               $   138,182  $   252,257
    -------------------------------------------------------------------------

    Cash interest paid                              $   886,973  $   330,643
    Cash income taxes (recovered) paid              $   (12,579) $    15,000


    See accompanying notes


    Stylus Energy Inc.
    Notes to Consolidated Financial Statements
    Year ended December 31, 2006

    1.  DESCRIPTION OF BUSINESS

        Stylus Energy Inc. (the "Company" or "Stylus") was formed by the
        amalgamation on March 1, 2005 of Stylus Exploration Inc. and Kinloch
        Resources Inc. ("Kinloch"). Stylus is involved in the exploration,
        development and production of natural gas, natural gas liquids and
        crude oil in Alberta. The primary operating areas of Stylus include
        the northeast Alberta shallow gas region and the southern Alberta
        plains and deep basin region. Common shares of Stylus trade on the
        Toronto Stock Exchange ("TSX") under the symbol 'STY'.

    2.  SIGNIFICANT ACCOUNTING POLICIES

        These consolidated financial statements, which have been prepared in
        accordance with Canadian generally accepted accounting principles
        ("GAAP"), have been, in management's opinion, properly prepared
        within reasonable limits of materiality and within the framework of
        the accounting policies summarized below.

        Principles of Consolidation

        The consolidated financial statements include the accounts of the
        Company and its wholly-owned subsidiary. All intercompany
        transactions and balances have been eliminated.

        Inventory

        Inventory of materials and equipment is carried at the lower of
        actual cost and net realizable value.

        Property and Equipment

        Petroleum and Natural Gas Properties and Production Equipment
        The Company follows the full cost method of accounting for its oil
        and gas operations in accordance with the guideline issued by the
        Canadian Institute of Chartered Accountants whereby all costs
        associated with the exploration for and development of petroleum and
        natural gas reserves, whether productive or unproductive, are
        capitalized in a single Canadian cost center and charged to income as
        set out below. Such costs can include lease acquisition, drilling,
        geological and geophysical, equipment costs, and general and
        administrative costs directly related to exploration and development
        activities.

        Proceeds from disposal of properties will normally be applied as a
        reduction of the cost of the remaining assets, except when such a
        disposal would alter the depletion and depreciation rate by more than
        20 percent, in which case a gain or loss will be recorded.

        Depletion and Depreciation

        Depletion of petroleum and natural gas properties and depreciation of
        production equipment is provided on accumulated costs using the unit
        of production method based on estimated gross proven petroleum and
        natural gas reserves as determined by independent engineers. For
        purposes of the depletion calculation, proven petroleum and natural
        gas reserves are converted to a common unit of measure on the basis
        that six thousand cubic feet of natural gas is equivalent to one
        barrel of oil and liquids.

        The depletion and depreciation cost base includes total capitalized
        costs, less costs of unproved properties and seismic, plus a
        provision for future development costs of proven undeveloped
        reserves. Costs of acquiring and evaluating unproved properties are
        not depleted until either the property is proved or it expires.
        Seismic costs in excess of the realizable value are added to the
        depletion base.

        Ceiling Test

        The Company tests impairment against undiscounted future net revenues
        from proven reserves using expected future prices and costs and the
        Income Tax legislation in effect at year-end. Impairment is
        recognized when the carrying amount is greater than the undiscounted
        future net revenues, at which time the assets are written down to the
        estimated fair value of proved and probable reserves plus the cost of
        unproved properties and seismic, net of impairment allowances. Fair
        value is determined using discounted future cash flows based on
        expected future prices and costs and the Income Tax legislation in
        effect at year end, and amounts are discounted using a risk-free
        interest rate. For undeveloped land and seismic, an independent
        evaluation is compared to the Company's net book value. The excess of
        net book value of undeveloped land or seismic over its fair value is
        added to the depletion cost base.

        Other Assets

        The Company carries its other assets at cost, which is depreciated
        over their estimated useful lives as follows:

           Leasehold improvements         -   20 percent straight line
           Computer hardware and software -   33 1/3 percent straight line
           Furniture and equipment        -   20 percent straight line

        Asset Retirement Obligations

        The Company records the fair value of an asset retirement obligation
        as a liability in the period in which it incurs a legal obligation
        associated with the retirement of tangible long-lived assets that
        result from the acquisition, construction, development and/or normal
        use 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 gross proved reserves. Subsequent to the initial
        measurement of the asset retirement obligations, the obligations are
        adjusted at the end of each period to reflect the passage of time
        (accretion) and changes in the estimated future cash flows underlying
        the obligation. Any difference between the actual costs incurred and
        the recorded liability is recorded as an adjustment to the full cost
        pool in the period in which the settlement occurs.

        Measurement Uncertainty

        The amounts recorded for depletion and depreciation of property and
        equipment, and asset retirement obligations and the ceiling test
        calculation are based on estimates of proven reserves, production
        rates, petroleum and natural gas prices, future costs and other
        relevant assumptions. By their nature, these estimates are subject to
        measurement uncertainty, and the effect on the consolidated financial
        statements of changes in such estimates in future years could be
        significant.

        Joint Operations

        Substantially all of the Company's exploration and development
        activities are conducted jointly with others and, accordingly, the
        consolidated financial statements reflect only the Company's
        proportionate interest in such activities.

        Income Taxes

        The Company follows the liability method of accounting for income
        taxes. Under this method, future income tax assets and liabilities
        are determined based on differences between the financial statement
        reporting and tax basis of assets and liabilities, and measured using
        the substantively enacted tax rates and laws that will be in effect
        when the differences are expected to reverse. The effect on future
        tax assets and liabilities of a change in tax rates is recognized in
        income in the period in which the change is substantively enacted.

        Per Share Amounts

        The Company utilizes the treasury stock method in the determination
        of diluted per share amounts. Under this method, the diluted weighted
        average number of shares is calculated assuming the proceeds that
        arise from the exercise of outstanding in-the-money options and
        unrecognized stock-based compensation expense are used to purchase
        common shares of the Company at their estimated average market price
        for the period.

        Stock-based Compensation

        The Company has a stock-based compensation plan, which is described
        in Note 8. The Company uses the fair value based method for measuring
        compensation costs and, therefore, all awards to employees and non-
        employees are recorded at fair value on the date of the grant. Under
        this method, compensation expense for stock options granted since
        January 1, 2003 that are direct awards of stock is measured at the
        fair value at the grant date using a Black-Scholes option-pricing
        model and is recognized over the vesting period of the options
        granted. The compensation expense is recorded in the statement of
        income with the corresponding increase recorded as contributed
        surplus. The accrued compensation for an option that is forfeited or
        cancelled is adjusted by decreasing compensation cost in the period
        of forfeiture. Any consideration paid by the option holders to
        purchase shares is credited to share capital at the time the option
        is exercised.

        Revenue Recognition

        Revenues from sale of petroleum and natural gas are recorded when
        title passes to customers.

        Flow-through Shares

        From time to time, a portion of the Company's exploration and
        development activities is financed through proceeds received from the
        issue of flow-through shares or warrants. Under the terms of the
        flow-through issues, the tax attributes of the resource expenditures
        related to exploratory and development activities are renounced to
        the subscribers. To recognize the foregone tax benefits to the
        Company, the carrying value of the shares or warrants issued is
        reduced and the future income tax liability increased by the tax
        effect of the tax benefits renounced to subscribers. The foregone tax
        benefit is recognized at the time of the renouncement, provided there
        is reasonable assurance that the expenditures will be incurred.

        Goodwill

        Goodwill represents the excess of the purchase price over the fair
        value of identifiable net assets acquired in business combinations.
        Goodwill is assessed for impairment at least annually. The fair value
        of each reporting unit is determined and compared to the book value
        of the reporting unit. If the fair value of the reporting unit is
        less than the book value, a second test is performed to determine the
        amount of the impairment. The amount of the impairment is determined
        by deducting the fair value of the reporting unit's individual assets
        and liabilities from the fair value of the reporting unit to
        determine the implied fair value of goodwill and comparing that
        amount to the book value of goodwill. Any excess of the book value of
        goodwill over the implied fair value is the impairment amount and
        will be charged to income in the period of the impairment.

    3.  BUSINESS ACQUISITION AND AMALGAMATION

        On March 1, 2005, the amalgamation transaction of Stylus Exploration
        Inc. and Kinloch resulted in Kinloch shareholders receiving one
        Stylus common share for every three common shares of Kinloch, and
        Stylus Exploration Inc. shareholders receiving 1.0833 Stylus common
        shares for every one common share or special warrant of Stylus
        Exploration Inc. At March 1, 2005, after giving effect to the
        transaction, Stylus had approximately 21.1 million common shares
        outstanding, of which former Stylus Exploration Inc. security holders
        held approximately 56.2 percent and former Kinloch shareholders held
        approximately 43.8 percent. The business combination has been
        accounted for as a reverse takeover of Kinloch by Stylus Exploration
        Inc. Accordingly, these consolidated financial statements are a
        continuation of Stylus Exploration Inc. with the results of
        operations of Kinloch recognized from the date of amalgamation.

        The acquisition of Kinloch has been recorded using the purchase
        method of accounting. The fair value of the purchase price share
        consideration was determined by an independent fair valuation report
        prepared by an independent business valuations group as follows.


        ---------------------------------------------------------------------
        Non-cash working capital acquired                     $     (161,155)
        ---------------------------------------------------------------------
        Property and equipment                                    27,196,391
        ---------------------------------------------------------------------
        Undeveloped land                                           1,690,406
        ---------------------------------------------------------------------
        Bank debt                                                 (7,018,428)
        ---------------------------------------------------------------------
        Asset retirement obligations                              (1,671,566)
        ---------------------------------------------------------------------
        Total purchase price                                  $   20,035,648
        ---------------------------------------------------------------------
        Consideration:
        ---------------------------------------------------------------------
        Issuance of common shares                                 19,900,000
        ---------------------------------------------------------------------
        Transaction costs                                            135,648
        ---------------------------------------------------------------------
        Total consideration                                   $   20,035,648
        ---------------------------------------------------------------------

        904217 Alberta Ltd. (note 15)

        On June 1, 2005, the Company consolidated additional working
        interests in northeastern Alberta by acquiring 100 percent of the
        issued and outstanding shares of 904217 Alberta Ltd. ("904217") for
        consideration comprising $335,501 in cash and the issuance of
        300,002 Stylus shares. The transaction was accounted for using the
        purchase method of accounting with the results of 904217 being
        included in Stylus' operations from date of acquisition. This
        purchase was valued based on the discounted proved plus probable
        reserves acquired. Both the reserve values and the fair values of the
        purchase price consideration were determined by management as
        follows.

        ---------------------------------------------------------------------
        Cash acquired                                         $      245,244
        ---------------------------------------------------------------------
        Non-cash working capital acquired                            124,521
        ---------------------------------------------------------------------
        Property and equipment                                       646,040
        ---------------------------------------------------------------------
        Undeveloped land                                              89,885
        ---------------------------------------------------------------------
        Goodwill                                                      65,795
        ---------------------------------------------------------------------
        Future income tax liability                                 (159,014)
        ---------------------------------------------------------------------
        Asset retirement obligations                                 (39,335)
        ---------------------------------------------------------------------
        Total purchase price                                  $      973,136
        ---------------------------------------------------------------------
        Consideration:
        ---------------------------------------------------------------------
        Issuance of common shares                                    624,000
        ---------------------------------------------------------------------
        Cash                                                         335,501
        ---------------------------------------------------------------------
        Transaction costs                                             13,635
        ---------------------------------------------------------------------
        Total consideration                                   $      973,136
        ---------------------------------------------------------------------


    4.  Asset retirement obligations

        A reconciliation of the Company's asset retirement obligation ("ARO")
        estimate is provided below.

        Year ended December 31                          2006            2005
        ---------------------------------------------------------------------
        ARO, beginning of year                $    3,338,000  $    1,135,187
        Liabilities assumed on acquisitions
         (Note 3)                                          -       1,710,901
        Change in estimate                           682,956               -
        Liabilities incurred in the year           1,113,430         432,837
        ARO expenditures                            (169,347)        (91,142)
        Accretion expense                            199,708         150,217
        ---------------------------------------------------------------------
        ARO, end of year                      $    5,164,747  $    3,338,000
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        The total ARO was estimated based on the Company's net ownership
        interest in all wells and facilities, the estimated costs to abandon
        and reclaim the wells and facilities and the estimated timing of the
        costs to be incurred in future periods. During the year ended
        December 31, 2006, the Company spent $1,070,316 (2005 - $91,142) on
        abandonments, of which $169,347 (2005 - $91,142) was applied against
        the ARO obligation and $900,968 (2005 - $Nil) was recorded as an
        increase to fixed assets, as this was the amount of the actual
        abandonment costs incurred in excess of the accrued ARO obligation.
        Due to the rising cost of oilfield services, during 2006 the Company
        reviewed the individual property estimates for abandonments and
        provided for an increase in these estimated abandonment costs. The
        Company estimates the total undiscounted ARO to be approximately
        $9.3 million, which will be incurred between 2007 and 2019. The
        majority of the costs will be incurred between 2011 and 2019. The
        credit-adjusted risk-free rate used in the calculation of the fair
        value of the ARO was 5.0 percent for obligations assumed up to
        February 28, 2005 and 6.5 percent for obligations assumed after that
        date. The inflation rate used was 2.0 percent.

    5.  CASH

        Cash of $138,182 (2005 - $252,257) was invested in a non-interest
        bearing chequing account as at December 31, 2006 (2005 - 1.25
        percent).

    6.  PROPERTY AND EQUIPMENT

        As at December 31, 2006
        ---------------------------------------------------------------------
                                                 Accumulated
                                               depletion and             Net
                                        Cost    depreciation      book value
        ---------------------------------------------------------------------
                                           $               $               $
        ---------------------------------------------------------------------
        Petroleum and natural
         gas properties and
         production equipment    125,549,709      38,738,556      86,811,153
        Other assets               1,116,126         930,558         185,568
        ---------------------------------------------------------------------
                                 126,665,835      39,669,114      86,996,721
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        As at December 31, 2005
        ---------------------------------------------------------------------
                                                 Accumulated
                                               depletion and             Net
                                        Cost    depreciation      book value
        ---------------------------------------------------------------------
                                           $               $               $
        ---------------------------------------------------------------------
        Petroleum and natural
         gas properties and
         production equipment     85,310,737      26,265,951      59,044,786
        Other assets                 924,482         668,496         255,986
        ---------------------------------------------------------------------
                                  86,235,219      26,934,447      59,300,772
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        The Company capitalizes the salaries of those employees directly
        involved in exploration activities. For the year ended December 31,
        2006, the Company capitalized $349,583 (2005 - $364,167) of salaries
        and $81,079 (2005 - $70,987) of stock-based compensation related to
        exploration staff.

        At December 31, 2006, petroleum and natural gas properties and
        production equipment costs include $22,943,782 (2005 - $14,322,654)
        relating to undeveloped land and seismic expenditures that have been
        excluded from the depletion calculation. Included in the depletion
        calculation are future development costs of $7,234,300
        (2005 - $6,907,400).

        The Company has performed an impairment test as of December 31, 2006
        using the estimated average sales price for each of the next five
        years as determined by the Company's independent reserve engineers,
        as follows.

                                             Edmonton               Exchange
                              WTI Oil      Light Oil          AECO      Rate
                 Year        (USD/bbl)      (CAD/bbl)     (CAD/mcf) (USD/CAD)
        ---------------------------------------------------------------------
        2007                    62.50          70.80           6.85     0.87
        2008                    61.20          69.30           7.05     0.87
        2009                    59.80          67.70           7.40     0.87
        2010 - 2017 Avg.        62.49          70.65           8.51     0.87
        Thereafter     2.0% escalated 2.0% escalated 2.0% escalated     0.87

        There is no impairment as at December 31, 2006 and 2005.

    7.  BANK LOAN

        The Company has a $23.0 million extendable revolving credit facility
        with a Canadian chartered bank. Under the terms of this facility,
        interest is paid monthly in arrears at the bank's prime lending rate.
        The extendable revolving term credit facility is subject to review on
        or before May 31, 2007 and specifies no specific repayment terms. A
        first floating-charge debenture over all properties of the Company
        has been provided as security. As of December 31, 2006, $20,796,260
        (2005 - $3,693,734) has been drawn against the facility with an
        effective interest rate of 6.0 percent (2005 - 5.0 percent).


    8.  SHARE CAPITAL

        Authorized

        Unlimited number of voting common shares, with no par value

        Unlimited number of non-voting preferred shares

        Common Shares                                                   2006
        ---------------------------------------------------------------------
        Issued                                        Number          Amount
        ---------------------------------------------------------------------
        Balance, January 1                        24,069,857  $   44,427,145
        Warrants exercised for cash (see
         (a) below)                                        -               -
        Shares issued on reverse takeover and
         amalgamation (see (a) below)                      -               -
        Cash proceeds from options exercised         133,553         207,352
        Tax effect of flow through share
         renunciation (see (e) and (b)
         below)                                                   (1,694,448)
        Non-cash transfer from contributed
         surplus                                           -          54,790
        Private Placement (see (e), (f) and
         (g) below)                                3,447,500      15,503,650
        Shares issued on corporate acquisition
         (see (c) below)                                   -               -
        Share issue costs                                         (1,038,049)
        Tax effect of share issue costs                              301,062
        ---------------------------------------------------------------------
        Balance, December 31                      27,650,910  $   57,761,502
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        Special Warrants                                                2006
                                               ------------------------------
        Issued                                        Number          Amount
        ---------------------------------------------------------------------
        Balance, January 1                                 -               -
        Warrant issue costs                                -
        Warrants exercised (see (a) below)                 -               -
        ---------------------------------------------------------------------
        Balance, December 31                               -               -
        ---------------------------------------------------------------------

        Total Share Capital                                -               -
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------


        Common Shares                                                   2005
        ---------------------------------------------------------------------
        Issued                                       Number           Amount
        ---------------------------------------------------------------------
        Balance, January 1                        6,568,211   $   10,392,176
        Warrants exercised for cash (see
         (a) below)                               4,400,001        4,417,318
        Shares issued on reverse takeover and
         amalgamation (see (a) below)            10,131,979       19,900,000
        Cash proceeds from options exercised        159,664          476,494
        Tax effect of flow through share
         renunciation (see (e) and (b)
         below)                                           -         (504,300)
        Non-cash transfer from contributed
         surplus                                          -                -
        Private Placement (see (e), (f) and
         (g) below)                               2,510,000       10,044,000
        Shares issued on corporate acquisition
         (see (c) below)                            300,002          624,000
        Share issue costs                                         (1,154,695)
        Tax effect of share issue costs                              232,152
        ---------------------------------------------------------------------
        Balance, December 31                     24,069,857   $   44,427,145
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        Special Warrants                                                2006
                                               ------------------------------
        Issued                                       Number           Amount
        ---------------------------------------------------------------------
        Balance, January 1                        4,400,001        4,418,818
        Warrant issue costs                               -           (1,500)
        Warrants exercised (see (a) below)       (4,400,001)      (4,417,318)
        ---------------------------------------------------------------------
        Balance, December 31                              -                -
        ---------------------------------------------------------------------

        Total Share Capital                      24,069,857       44,427,145
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        (a) On February 28, 2005, the security holders of Stylus Exploration
            Inc. and Kinloch voted to support the previously announced merger
            of the two companies (see Note 3). Upon the completion of the
            transaction (i) each of the Stylus Exploration Inc. Special
            Warrants was deemed to have been exercised, (ii) Stylus
            Exploration Inc. common shares were converted into Stylus common
            shares on the basis of 1.0833 Stylus common shares for each
            Stylus Exploration Inc. common share and (iii) Kinloch common
            shares were converted into Stylus common shares on the basis of
            three Kinloch common shares for each Stylus common share.
            Pursuant to the reverse takeover and amalgamation, a total of
            21,100,191 common shares of Stylus Energy Inc. were issued.

        (b) In February 2005, in accordance with the terms of a flow-through
            share offering issued during the fourth quarter of 2004, and
            pursuant to certain provisions of the Income Tax Act (Canada),
            the Company renounced to the holders, for income tax purposes,
            exploration and development expenditures to be incurred in the
            aggregate amount of $1,500,000. As a result, share capital was
            reduced and the future income tax recovery increased by
            approximately $504,300 in the first quarter of 2005 to reflect
            the effect of the expenditures renounced.

        (c) Effective June 1, 2005, Stylus acquired 904217, a private oil and
            gas company with a five percent working interest in certain
            Stylus natural gas properties in Northeast Alberta, for total
            consideration of $973,136 consisting of 300,002 Stylus common
            shares and $335,501 in cash (see note 3).

        (d) At a Stylus Exploration Inc. Special Shareholders Meeting on
            December 8, 2003, a special resolution was passed authorizing a
            distribution to shareholders of stated capital in the amount of
            $11,684,687, which amount was disbursed prior to December 31,
            2003. At this Meeting, the shareholders also passed a resolution
            authorizing the write-down of the deficit at December 31, 2003 of
            $15,170,634 to $nil by a transfer to share capital.

        (e) On December 6, 2005, the Company issued 1,390,000 common shares
            at $3.60 per share for gross proceeds of $5,004,000 and
            1,120,000 flow-through common shares at $4.50 per share for gross
            proceeds of $5,040,000 less share issue costs of $601,000. In
            February 2006, in accordance with the terms of its flow-through
            offering described above and pursuant to certain provisions of
            the Income Tax Act (Canada), the Company renounced to the
            holders, for income tax purposes, exploration expenditures to be
            incurred in the aggregate amount of $5,040,000. As a result,
            share capital was reduced and the future income tax liability
            increased by $1,694,448 in the first quarter of 2006 to reflect
            the effect of the expenditures renounced.

        (f) On June 30, 2006, the Company issued 2,106,000 flow-through
            common shares at $4.75 per share for gross proceeds of
            $10,003,500 less share issue costs of $648,763. In February 2007,
            in accordance with the terms of its flow-through offering
            described above and pursuant to certain provisions of the Income
            Tax Act (Canada), the Company, effective as of December 31, 2006,
            renounced to the holders, for income tax purposes, exploration
            expenditures to be incurred in the aggregate amount of
            $10,003,500. As a result, share capital will be reduced and the
            future income tax liability will be increased by approximately
            $2,900,000 in the first quarter of 2007 to reflect the tax
            benefits of the expenditures renounced. Funds raised from this
            flow-through offering have been and will be used to help finance
            the Company's exploration program.

        (g) On December 6, 2006, the Company issued 1,341,500 flow-through
            common shares at $4.10 per share for gross proceeds of $5,500,150
            less share issue costs of $361,770. In February 2007, in
            accordance with the terms of its flow-through offering described
            above and pursuant to certain provisions of the Income Tax Act
            (Canada), the Company, effective as of December 31, 2006,
            renounced to the holders, for income tax purposes, exploration
            expenditures to be incurred in the aggregate amount of
            $5,500,150. As a result, share capital will be reduced and the
            future income tax liability will be increased by approximately
            $1,594,500 in the first quarter of 2007 to reflect the effect of
            the expenditures renounced. Funds raised from this flow-through
            offering have been and will be used to help finance the Company's
            exploration program.

        Stock Options

        The Company has a stock option plan pursuant to which options may be
        granted to the Company's directors, officers and employees for up to
        10 percent of the issued and outstanding common shares of the
        Company. As at December 31, 2006, the Company could grant up to
        2,765,091 options. The exercise price of each option is set by the
        directors at the date of grant, but must be no lower than the closing
        trading price per common share on the Toronto Stock Exchange on the
        date before the day of the grant. An option's maximum term is 10
        years, but is typically granted for five years, vesting equally over
        three years beginning on the first anniversary of the date of grant.

        The following is a reconciliation of the stock option plan activity
        for the twelve months ended December 31, 2006.

                                                                    Weighted
                                                                     Average
        Options Outstanding                          Number   Exercise Price
        ---------------------------------------------------------------------
        Balance, January 1, 2006                  1,919,802           $ 1.88
        Exercised                                  (133,553)            1.55
        Granted                                     578,000             4.13
        Cancelled                                   (82,777)            2.15
        ---------------------------------------------------------------------
        Balance, December 31, 2006                2,281,472           $ 2.46
         ---------------------------------------------------------------------

        The following table summarizes the stock options outstanding and
        exercisable under the plan at December 31, 2006.

    As at December 31, 2006        Options Outstanding   Options Exercisable
    -------------------------------------------------------------------------
                        Weighted   Weighted   Weighted              Weighted
    Range of   Number    Average    Average    Average     Number    Average
    Exercise      Out-  Years to   Exercise       Fair    Exercis-  Exercise
       Price standing     Expiry      Price      Value       able      Price
    -------------------------------------------------------------------------

    $1.15     715,808       0.95   $   1.15   $   0.10    708,586   $   1.15
    $2.06 to
     $2.40    889,665       3.31   $   2.35   $   1.04    271,222   $   2.37
    $3.00 to
     $3.75    110,999       2.93   $   3.25   $   0.68     67,666   $   3.10
    $3.90 to
     $4.15    565,000       4.56   $   4.14   $   1.32          -        n/a
            -----------------------------------------------------------------
            -----------------------------------------------------------------
            2,281,472       2.86   $   2.46   $   0.80  1,047,474   $   1.59
            -----------------------------------------------------------------
            -----------------------------------------------------------------

        Stock-based Compensation

        The Company accounts for its stock-based compensation plan using the
        fair value method and a Black-Scholes option-pricing model. Under
        this method, compensation costs are charged over the vesting period
        for the stock options with a corresponding increase to contributed
        surplus.

        The Company issued 578,000 new stock options during 2006. For the new
        stock options granted in 2006 and 2005, the following assumptions
        were used in the calculation of the fair value of these options.

                                                       2006             2005
        ---------------------------------------------------------------------
        Expected volatility                        38 - 46%         48 - 65%
        Risk-free interest rate                  3.9 - 4.3%     3.40 - 3.90%
        Dividend yield                                  Nil              Nil
        Expected hold period to exercise            3 years          3 years

        The remaining stock-based compensation expense related to the options
        outstanding to be recorded in future periods totals $697,011.


        Contributed Surplus

        The following table reconciles the Company's contributed surplus.

                                                 Year ended       Year ended
                                                December 31      December 31
        ---------------------------------------------------------------------
                                                       2006             2005
        ---------------------------------------------------------------------

        Opening                                     504,508           56,535
        Stock-based compensation - expensed         523,097          375,628
        Stock-based compensation - capitalized
         to property and equipment                   81,079           72,345
        Non-cash transfer to share capital          (54,790)               -
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        Closing                                   1,053,894          504,508
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        Per Share Amounts

        The treasury stock method is used to determine the weighted average
        number of basic and diluted shares outstanding used in calculating
        per share amounts. The effect of any potential exercise of stock
        options outstanding during the periods shown was included in the
        calculation of diluted net income (loss) per share. During the three
        and twelve month periods ended December 31, 2006 no dilution occurred
        because the Company recorded a net loss. 736,481 and 812,274
        potentially dilutive shares related to options respectively, were
        excluded from the per share calculations.


    9.  Income Taxes

        Income tax recovery differs from the amount that would be computed by
        applying the Federal and Provincial statutory income tax rates to
        income (loss) before income taxes.  The reasons for the differences
        are as follows.

                                                       2006             2005
        ---------------------------------------------------------------------
        Income (loss) before income taxes       ($5,353,989)      $2,094,552

        Statutory income tax rate (percent)           32.49            33.62

        Anticipated tax expense (recovery)       (1,739,511)         704,188
        Increase (decrease) resulting from:

        Non-deductible Crown charges, net of
         Alberta Royalty Tax Credit                 289,348          765,285
        Resource allowance                         (274,723)        (618,688)
        Rate adjustment                            (378,071)               -
        Non-deductible items                        173,438          128,816
        Flow through adjustment                           -         (504,300)
        Large corporation tax                             -           15,000
        Other                                       215,984           60,086
        ---------------------------------------------------------------------
                                                ($1,713,535)        $550,387
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------


        The components of the future income tax liability are as follows.

                                                       2006             2005
                                               ------------------------------

        Net book value of property and
         equipment in excess of tax pools       ($4,223,645)    $ (4,764,378)
        Net book value of future tax benefits
         not recognized                                                    -
        Share issue costs                           641,369          688,049
        Non-capital loss carry-forward            1,525,097        2,100,000
        ARO                                       1,497,777        1,122,236
        Other                                      (534,846)        (529,409)
        Attributed Canadian royalty income
         carry-forward                              435,268          416,952
                                               ------------------------------
                                                  ($658,980)       ($966,550)
                                               ------------------------------
                                               ------------------------------

        The Company has non-capital loss carry-forward of approximately
        $5,258,000 to be used against future taxable income. These losses
        expire as follows:

                             2007         $852,000
                             2008           12,000
                             2013          765,000
                             2014        3,629,000
                            -----------------------
                                        $5,258,000
                            -----------------------

    10. financial instruments

        Fair Value

        Financial instruments recognized on the balance sheet consist of
        cash, accounts receivable, deposits, accounts payable and bank loan.
        As at December 31, 2006 and 2005, there are no significant
        differences between the carrying amounts of these instruments and
        their estimated fair values.

        Credit Risk

        A substantial portion of the Company's accounts receivable is with
        oil and gas marketing entities. The Company generally extends
        unsecured credit to these companies, and the collection of accounts
        receivable may be affected by changes in economic or other conditions
        and may accordingly impact the Company's overall credit risk.
        Management believes the risk is mitigated by the size, reputation and
        diversified nature of the companies to which they extend credit. The
        Company has not previously experienced any credit losses on the
        collection of receivables.

    11. COMMITMENTS

        ---------------------------------------------------------------------
                                          2008 -    2010 -
                                2007      2009      2011      2012     Total
        ---------------------------------------------------------------------
        Operating leases     255,000   455,000   113,000         -   823,000
        ---------------------------------------------------------------------

    12. NET CHANGE IN NON-CASH WORKING Capital

        ---------------------------------------------------------------------
        Year ended December 31                         2006             2005
        ---------------------------------------------------------------------
        Accounts receivable                    $ (1,621,487)    $ (3,089,337)
        Inventory                                  (201,145)        (565,483)
        Prepaid expenses and deposits               (50,323)        (126,032)
        Accounts payable and accrued
         liabilities                                589,838        5,365,877
        ---------------------------------------------------------------------
                                                 (1,283,117)       1,585,025
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        Less: Non-cash working capital
         acquired (Note 3)                                -          (36,634)
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        Change in non-cash working capital     $ (1,283,117)    $  1,548,391
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        Relating to:
        Operating                              $    596,800     $   (541,748)
        Investing                                (1,879,917)       2,090,139
        ---------------------------------------------------------------------
                                               $ (1,283,117)    $  1,548,391
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    13. Interest expense

        The Canada Revenue Agency ("CRA") has completed audits of Kinloch and
        of a predecessor company acquired by Kinloch for the 2002 and 2003
        taxation years. As a result of the audits, tax deductions related to
        certain wells classified as Canadian Exploration Expense and
        renounced to subscribers pursuant to flow-through share issues were
        reclassified by the CRA as Canadian Development Expense. As a result
        of the reclassification, Stylus has estimated Part 12.6 interest and
        penalties totaling $158,273, which was paid to the CRA and is
        included in interest expense for the twelve months ended December 31,
        2006.

    14. COMPARATIVE FIGURES

        Certain comparative figures have been reclassified to conform to
        current period presentation.

    15. SUBSEQUENT EVENT

        On January 1, 2007, 904217 Alberta Ltd., a wholly owned subsidiary of
        Stylus, was amalgamated with the Company and the combined entity
        continued operations as a new company, also called Stylus Energy Inc.

        On January 23, 2007, 78,000 stock options were granted at $2.81 per
        share.
    

    Forward Looking Information

    Certain of the statements contained herein including, without limitation,
financial and business prospects and financial outlook, management's
assessment of future plans and operations, timing of regulatory applications
and anticipated approvals, anticipated production expenses, transportation
expenses, royalty rates, operating costs, general and administrative expenses,
depletion, depreciation and accretion expense and capital expenditures and the
timing and the method of funding thereof may be forward-looking statements.
Words such as "may", "will", "should", "could", "anticipate", "believe",
"expect", "intend", "plan", "potential", "continue" and similar expressions
may be used to identify these forward-looking statements. These statements
reflect management's current beliefs and are based on information currently
available to management. Forward-looking statements involve significant risk
and uncertainties. A number of factors could cause actual results to differ
materially from the results discussed in the forward-looking statements
including, but not limited to, risks associated with oil and gas exploration,
development, exploitation, production, marketing and transportation, loss of
markets, volatility of commodity prices, currency fluctuations, imprecision of
reserve estimates, environmental risks, competition from other producers,
inability to retain drilling rigs and other services, incorrect assessment of
the value of acquisitions, failure to realize the anticipated benefits of
acquisitions, delays resulting from or inability to obtain or delay in
obtaining required regulatory approvals and ability to access sufficient
capital from internal and external sources and the risk factors outlined under
"Risks and Uncertainty" in the attached MD&A and elsewhere herein. The
recovery and reserve estimates of Stylus' reserves are estimates only and
there is no guarantee that the estimated reserves will be recovered. As a
consequence, actual results may differ materially from those anticipated in
the forward-looking statements. Readers are cautioned that the foregoing list
of factors is not exhaustive. Additional information on these and other
factors that could effect Stylus' operations and financial results are
included in reports on file with Canadian securities regulatory authorities
and may be accessed through the SEDAR website (www.sedar.com) and at Stylus'
website (www.stylusenergy.com). Although the forward-looking statements
contained herein are based upon what management believes to be reasonable
assumptions, management cannot assure that actual results will be consistent
with these forward-looking statements. Investors should not place undue
reliance on forward-looking statements. These forward-looking statements are
made as of the date hereof and Stylus assumes no obligation to update or
review them to reflect new events or circumstances except as required by
applicable securities laws.
    Forward-looking statements and other information contained herein
concerning the oil and gas industry and Stylus' general expectations
concerning this industry are based on estimates prepared by management using
data from publicly available industry sources as well as from reserve reports,
market research and industry analysis and on assumptions based on data and
knowledge of this industry which Stylus believes to be reasonable. However,
this data is inherently imprecise, although generally indicative of relative
market positions, market shares and performance characteristics. While Stylus
is not aware of any misstatements regarding any industry data presented
herein, the industry involves risks and uncertainties and is subject to change
based on various factors.

    BOE Disclosure

    BOE Presentation: The calculations of barrels of oil equivalent ("BOE")
are based on a conversion rate of six thousand cubic feet ("mcf") of natural
gas to one barrel ("bbl") of crude oil. BOE's may be misleading, particularly
if used in isolation. A BOE conversion ratio of 6 mcf: 1 bbl is based on an
energy equivalency conversion method primarily applicable at the burner tip
and does not represent a value equivalency at the wellhead.


    %SEDAR: 00021888E




For further information:

For further information: Paul Evans, President and Chief Executive
Officer, Tel: (403) 517-8791, E-mail: pevans@stylusenergy.com; William Dyer,
Vice-President, Finance and Chief Financial Officer, Tel: (403) 517-8790,
E-mail: bdyer@stylusenergy.com

Organization Profile

STYLUS ENERGY INC.

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