Gentry Announces 2006 Financial and Operational Results & New Exploration Discoveries at Princess



    CALGARY, March 26 /CNW/ - Gentry Resources Ltd. ("Gentry" or the
"Company") is pleased to announce its financial and operating results for the
fourth quarter and year ended December 31, 2006.

    
    FINANCIAL HIGHLIGHTS

    - Gentry's gross revenue for 2006 was $69.8 million an increase of 8%
      from the previous year's number.

    - Funds flow was $30.4 million, or $0.79 on a per share basis.

    - Net earnings were $2.8 million, or $0.07 on a per share basis.

    - Gross capital expenditures totaled $43.3 million with 40% dedicated to
      facility construction and enhancement & equipping.

    - Year-end bank debt was $40.8 million.

    - Gentry holds 10.7 million common shares of Stratic Energy Corporation,
      an international exploration and production company, with a
      December 31, 2006 market value of approximately $13.9 million.

    OPERATIONAL HIGHLIGHTS

    - Average production increased by 27% year over year to 4,175 boe/d from
      3,280 boe/d in 2005. Gentry's fourth quarter production averaged
      4,335 boe/d compared to 3,936 boe/d in the third quarter, an increase
      of 10%.

    - Proved reserves at December 31, 2006 increased by 13% to 6.7 mmboe up
      from 6.0 mmboe recorded December 31, 2005. Proved reserves represent
      66% of the Company's total reserves.

    - Proved finding and development costs were $18.38 per boe.

    - Production replacement on a proved basis before dispositions was 162%
      of 2006 production.

    - Proved plus probable reserves, prior to dispositions of 0.4 mmboe, were
      essentially flat year over year. Year end proved plus probable reserves
      were 10.1 mmboe.

    - Gentry's 2006 year-end reserves were evaluated for the first time by
      Sproule Associates Limited.

    - Proved plus probable finding and development costs over the past three
      years averaged $21.05 per boe. Proved and probable finding and
      development costs for 2006 were $31.05 per boe.

    - Year-end net asset value per share discounted at 5% was $5.82, or $5.03
      discounted at 10%.

    - Gentry's net undeveloped Western Canada land holdings increased by 14%
      to 179,415 net acres from 157,504 net acres in 2005.

    - Gentry drilled a total of 51 wells (48.0 net) in 2006, yielding a 90%
      success rate (91% net) resulting in 22 gas wells (20.5 net), 19 oil
      wells (18.2 net) and five abandoned wells (4.5 net). Five wells
      (4.8 net) remain suspended awaiting further completion.

    - Gentry achieved a 100% (100% net) success rate in its fourth quarter
      drilling program. Of the seven wells drilled (6.5 net), three (3.0 net)
      were cased for gas, three (2.5 net) were cased for oil and one
      (1.0 net) is cased, and awaiting completion.

    - As at December 31, 2006, the Company has a drilling inventory on its
      Princess lands of over 150 locations for medium gravity oil and natural
      gas.

    - Gentry controls 486 square miles (1,200 square km) of 3D seismic data
      over its core Princess property.

    - Gentry controls 457 sections (403 net) in its Princess core area.


                             Three months ended              Year ended
                                   Dec 31                      Dec 31
                             2006          2005          2006          2005
    -------------------------------------------------------------------------
    Financial
      Revenue         $17,924,387   $22,164,572   $69,832,337   $64,665,175
      Funds flow        4,874,754    12,651,850    30,444,948    35,032,254
        Per share -
         basic               0.13          0.33          0.79          0.90
      Net income (loss)  (931,045)    2,737,123     2,757,210    10,202,438
        Per share -
         basic              (0.02)         0.07          0.07          0.26
      Net capital
       expenditures     3,603,423    19,742,561    36,248,701    53,854,150
      Net debt         47,311,997    39,174,429    47,311,997    39,174,429
      Weighted average
       of shares
       outstanding     38,718,143    38,860,267    38,652,164    38,755,860
    -------------------------------------------------------------------------
    Production
      Oil & liquids
       (bbls/d)             1,447         1,486         1,398         1,330
      Gas (mcf/d)          17,331        14,189        16,658        11,699
      Barrels of oil
       equivalent (boe/d)   4,335         3,851         4,175         3,280
    -------------------------------------------------------------------------
    Average Prices
      Oil & Liquids
       (bbls/d)       $     50.59   $     52.27   $     57.86   $     52.71
      Gas (mcf/d)            7.02         11.50          6.63          9.15
      Barrel of Oil
       Equivalent
       (boe/d)              44.94         62.56         45.83         54.01
    -------------------------------------------------------------------------
    Reserves
      Oil & Liquids
       (mbbls)                                          4,184         4,321
      Gas (mmcf)                                       35,542        38,064
      Barrel of oil
       equivalent
       (mboe)                                          10,109        10,665
    -------------------------------------------------------------------------
    Note: Natural gas is converted to boe on the basis of 6 mcf =
          1 boe. All reserves (and calculations thereon) are based on a
          proved plus probable basis unless otherwise stated.
    

    PRESIDENT'S MESSAGE TO SHAREHOLDERS

    Production

    Total production for the year averaged 4,175 boe/d up 27% from
3,280 boe/d in 2005. Gentry's fourth quarter 2006 production averaged
4,335 boe/d up 10% from the previous quarter. Gentry reached a record average
monthly production rate of 4,740 boe/d in the month of October and surpassed
5,000 boe/d with some flush production volumes on new wells.
    Extremely cold early winter weather in late November disrupted our
operations in general and Princess in particular. Gentry's Nisku production
began to be negatively impacted with line freezes late in the fourth quarter
which were difficult to resolve due to our commitment to low impact operations
with the surface land owner of the two Nisku wells. These production issues
carried into the first quarter and to some degree have now been resolved.
Gentry has placed a very high priority on the drilling of two additional Nisku
wells (one well testing a new Nisku feature) and the construction of
additional production facilities outside the influence of the Nisku surface
landowner.
    In the first quarter Gentry had one significant gas well in Princess
experience higher than average declines and one significant gas well in Red
Willow shut in due to third party issues stemming from our non-operated, 25%
owned, sour gas plant. At the time of writing we believe the facility issue at
Red Willow has been resolved to our satisfaction.
    One significant oil well on the eastern edge of the Princess block, on
the periphery of our established Pekisko fairway, has experienced higher than
normal declines. This is an edge well that experienced high flush production
and is now producing at reduced rates.
    Due to these operational issues, first quarter 2007 production is being
impacted as follows:

    
    -------------------------------------------------------------------------
                              Net Effect
    Well                          (boe/d)   Operational Comments
    -------------------------------------------------------------------------
    Nisku, sour gas well            -150    Operational issues, surface land,
                                            weather
    -------------------------------------------------------------------------
    Princess Pekisko sour gas well  -300    Re-drill of well
    -------------------------------------------------------------------------
    Red Willow, sweet gas well      -125    Gas plant capacity issue's well
                                            will produce at lower rates
    -------------------------------------------------------------------------
    Pekisko oil well                -125    Edge Well, Flush production
    -------------------------------------------------------------------------
    Fourth Quarter 2006 asset sale  -100    Sale of production
    -------------------------------------------------------------------------
    Net effect                      -800
    -------------------------------------------------------------------------
    

    Although the production for these four wells has declined, the ultimate
recovery of the reserves has not been materially affected. We are continuing
to improve our production methods to extract the highest recovery from the
very large oil and gas in place in this Pekisko play.
    In addition to the above, Gentry's Pekisko production was also curtailed
by insufficient water disposal capacity. Three water disposal applications
have been before the Energy & Utilities Board for a number of months and we
expect approval shortly.
    Current production is approximately 3,700 boe/d and we anticipate
production at the end of March will be approximately 3,850 boe/d.
    The Company expects to drill up to nine wells (9.0 net) offsetting the
6-31-17-11W4M discovery well that Gentry drilled and reported in the fourth
quarter of 2006. A net pay interval of 12 meters was completed in the Pekisko
Formation within a gross pay column of 40 meters. The well flowed a total of
49 m(3) of oil in eight hours (925 bbls oil/d) at a flowing pressure of
1360 kPa (200psig). The well has been producing at its allowable rate of
125 boe/d since mid December.
    Other development projects will commence following spring breakup which
will expand recent discoveries in the exploration block (8-12-17-12W4M,
2-4-15-11W4M). In addition, continued infill drilling between Gentry's Pekisko
oil pools at Tilley and West Tide Lake and follow-up locations are planned
developing land around two of the best Pekisko gas wells the Company has
drilled in the Princess area.
    The last three months drilling in the Princess area has resulted in the
following discoveries and subsequent behind pipe capability:

    
    -------------------------------------------------------------------------
                    GPP Initial/
                      Allowable    Working    Test Rates of Wells
                     Production   Interest    (gas conversion @
    Well ID         Rate (boe/d)        (%)   6mcf:1bbls)
    -------------------------------------------------------------------------
    10-12-19-12W4           200        100    Gas well, tested at 7 mmcf/d
                                              (1,100 boe/d)
    -------------------------------------------------------------------------
    10-7-19-12W4            150        100    Gas well, tested at 3 mmcf/d
                                              (500boe/d)
    -------------------------------------------------------------------------
    16-35-18-11W4(*)        100        100    Oil well, tested at 500 boe/d
    -------------------------------------------------------------------------
    8-12-17-12W4(*)         125        100    Oil well, tested at 600 boe/d
    -------------------------------------------------------------------------
    2-4-15-11W4(*)          125        100    Oil well, tested at 200 boe/d
    -------------------------------------------------------------------------
    Total Production Add    700
    -------------------------------------------------------------------------
    (*) Denotes wells that will lead to multi-well development projects.

    

    All of these recently drilled wells will be on stream by the end of the
second quarter.
    As at December 31, 2006 the Company has assembled a drilling inventory of
150 locations (100% WI) on its operated lands in its main core property of
Princess. The sheer size of the Company land block (403 net sections) in
conjunction with the Company's 3D seismic covering 486 sections provides a
drilling inventory of approximately five years.

    Fiscal Results

    Production revenue for 2006 was $69.8 million, compared with
$64.6 million a year earlier. The gains in total production volume and in
crude oil and liquids prices were, to a large degree, offset by the drop in
natural gas prices.
    Funds flow from operations was $30.4 million, down from $35.0 million a
year earlier, due in large part to an increase in royalties as well as a
general increase in operating costs due to the tight oilfield services market
and inflationary pressures related to the overheated Alberta economy.
    Net income in 2006 was $2.8 million, down from $10.2 million a year
earlier. The reduced funds flow, coupled with an additional $5.9 million in
depletion, depreciation and accretion charges and $1.2 million in stock-based
compensation were more than enough to offset the $4.3 million reduction in
future income taxes.
    For the fourth quarter of 2006, production revenue was $17.9 million,
funds flow from operations was $4.9 million and the net loss was $0.9 million.
Lower commodity prices affected production revenue, and this, coupled with
increased royalty bookings and higher production expenses affected funds flow
from operations. The net loss arose as a result of the above in spite of
savings in future income taxes and depletion charges.

    Operations

    We are cognizant that exploration must go hand-in hand with facilities -
and both must be managed while controlling our costs. Our approach on the
Exploration lands is to select targets that not only complete our commitments,
but that are lower risk prospects to allow for the sizing of production
facilities, or easy tie-in to existing Gentry-owned or third party
infrastructure.
    Our per unit operating costs in 2006 were $10.44/boe, up from $9.93/boe
in 2005 due in part to rising field costs associated with the high level of
industry activity. Over the past two years, construction of Gentry-owned
facilities combined with production growth has helped control our cost
structure and we will continue to capitalize on economies of scale.
    Gentry drilled a total of 51 wells (48.0 net) in 2006, yielding a 90%
success rate (91% net) resulting in 22 gas wells (20.5 net), 19 oil wells
(18.2 net) and five abandoned wells (4.5 net), five wells (4.8 net) remain
suspended awaiting further completion.
    Gentry achieved a 100% success rate in its fourth quarter drilling
program. Of the seven wells (6.5 net) drilled, three (3.0 net) were cased for
gas, three (2.5 net) were cased for oil and one (1.0 net) is standing cased.
    Excluding acquisitions and divestitures, capital expenditures decreased
7% to $42.8 million from $46.2 million in 2005.
    On a net basis, capital expenditures were $36.2 million in 2006 versus
$53.9 million in 2005. In the fourth quarter of 2006, the Company disposed of
98 boe/d of non-operated production for gross proceeds of $7.2 million. This
was in contrast to the 2005 figures when the Company acquired 195 boe/d of
production for gross proceeds of $8.1 million.

    Outlook

    The Company is well positioned for another active and successful year.
Every Pekisko well we drill adds to our understanding of the Pekisko
depositional system and refines the drilling fairways we have targeted. Gentry
is in the enviable position of having numerous opportunities from low risk
infill locations to drilling higher risk features.
    Gentry has five significant development projects in the Princess area,
four of which are a direct result of exploration drilling on the farm-in lands
south of Gentry's established Pekisko fairway and the remainder infilling
between Gentry's existing developments in Tilley and West Tide Lake.
    We are committing to accelerate our 60-well drilling program by
contracting two rigs as soon as we are able to move equipment on the secondary
roads. We currently have 16 drilling locations surveyed and another 24
drilling locations that are in the process of being surveyed. We anticipate
significant reserve additions throughout the year with our aggressive drilling
program in 2007.

    Summary

    It was a volatile year for our industry. At the beginning of 2006, gas
prices began to trend down reaching a low in the third quarter. This reduced
funds flow for producers and, in some cases, resulting in capital spending
cutbacks. A more critical event occurred on October 31st when the federal
government announced its intent to impose tax on income trusts. Both these
developments have shifted a number of elements in the oil and gas sector.
    A fall in equity markets for the oil and gas sector has reduced the
ability of some companies to access capital, while gas price weakness has
reduced funds flow across the sector. As with any shift in the industry, new
windows of opportunity open up, we expect to see increasing rationalization
and asset sales, and lower acquisition prices which had been very high for
several years. At Gentry, we are closely watching the evolution in acquisition
markets, and opportunities for further expansion.
    We are excited about Gentry's prospects over the next few years. We have
a large inventory of prospects, and a dominant land position where we are
recognized as drilling experts. Our competitive advantage also rests on the
strength of our balance sheet which will enable Gentry to pursue new
opportunities.
    As at the end of February George Magarian, VP Exploration, is no longer
with the Company. His contributions were valued and we wish him the very best
in his future endeavors. We are pleased to announce that Bruce Penny joined
Gentry as a Senior Geologist in February. In 2007, we are as committed as ever
to delivering sustainable growth in our oil and natural gas reserves.

    Respectfully submitted,

    Hugh Ross
    President and Chief Executive Officer



    The following Management's Discussion and Analysis (MD&A) should be read
in conjunction with the Consolidated Financial Statements of the Company.
    Reported production represents Gentry's ownership share before the
deduction of royalties. Where amounts are expressed on a barrel of oil
equivalent (boe) basis, natural gas has been converted at a ratio of six
thousand cubic feet to one boe. Boe's may be misleading, particularly if used
in isolation. A boe conversion ratio of six thousand cubic feet to one barrel
is based on an energy equivalent conversion method primarily applicable at the
burner tip and does not represent a value equivalency at the wellhead.
    Included in the MD&A are references to financial measures commonly used
in the oil and gas industry such as funds flow from operations and operating
netbacks. These measures have no standardized meaning, are not defined by
Canadian generally accepted accounting principles (GAAP), and accordingly are
referred to as non-GAAP measures. Gentry calculates funds flow from operations
as cash provided by operating activities prior to changes in working capital,
and operating netbacks as production revenue less royalties and production
expenses. These terms are used by the Company to assess operating results
between years and between peer companies. Gentry's reported amounts may not be
comparable to similarly titled measures reported by other companies. These
terms should not be considered an alternative to, or more meaningful than,
cash provided by operating, investing, and financing activities or net income
as determined by Canadian GAAP as an indicator of the Company's performance or
liquidity.
    Certain figures in the comparative financial statements and MD&A have
been reclassified to conform with the current year's presentation.
    Certain disclosure in this MD&A contains forward-looking statements that
involve risks and uncertainties. Such information, although considered
reasonable by Gentry at the time of preparation, may prove to be incorrect and
actual results may differ materially from those anticipated in the statements
made. For this purpose, any statements contained herein that are not
statements of historical fact may be deemed to be forward-looking statements.
Such risks and uncertainties include, but are not limited to, risks associated
with operations, loss of market, regulatory matters, commodity prices, reserve
estimates, reservoir performance, environmental concerns, industry
competition, and the ability to access sufficient capital from internal and
external sources.
    Additional information relating to the Company, including the Company's
Annual Information Form, can be found at www.sedar.com.
    This MD&A has been prepared as of March 20, 2007.

    
    Selected Annual Information

    ($thousands, except per share amounts)

                                               2006        2005        2004
                                           ----------------------------------
    Production revenue                       69,832      64,665      31,717
    Funds flow from operations               30,445      35,032      13,274
       per share - basic                       0.79        0.90        0.42
       per share - diluted                     0.77        0.86        0.40
    Net income                                2,757      10,202       3,402
       per share - basic                       0.07        0.26        0.11
       per share - diluted                     0.07        0.25        0.10
    Total assets                            141,826     132,067      95,514
    Long-term financial liabilities          17,498      15,370       9,772


    Production and Pricing

    The majority of Gentry's operations in 2006 were focused in Alberta.
Activities were primarily directed in the Greater Princess area (Princess) of
southern Alberta where the Company was able to pursue both medium gravity
crude as well as natural gas production. Sedalia, another core area in
southeastern Alberta, provided additional growth in gas production.
    As a result of the growth in Alberta, the Company's production in
Saskatchewan, which contributed 12% of volumes in 2005, accounted for only 9%
in 2006. Generally speaking, the Company's non-operated, long-life unitized
interests in Saskatchewan are steady producers which have the focused
attention of the operators managing their performance.
    As the Company moves through 2007, gains in gas production are slated to
come from Princess and Sedalia, while the driving force behind increased oil
production will be Princess.

                                            Revenue      Volume       Price
    Oil & liquids                      ($ thousands)    (bbls/d)     ($/bbl)
    -------------------------------------------------------------------------
    2006                                     29,532        1,398      57.86
    2005                                     25,589        1,330      52.71
    2004                                     13,525          862      42.88

                                            Revenue      Volume       Price
    Natural Gas                        ($ thousands)     (mcf/d)     ($/mcf)
    -------------------------------------------------------------------------
    2006                                     40,301      16,658        6.63
    2005                                     39,076      11,699        9.15
    2004                                     18,192       7,555        6.58

                                            Revenue      Volume       Price
    Boe                                ($ thousands)     (boe/d)     ($/boe)
    -------------------------------------------------------------------------
    2006                                     69,832       4,175       45.83
    2005                                     64,665       3,280       54.01
    2004                                     31,717       2,121       40.86


    Gross production revenue increased 8% in 2006 to $69.83 million from
$64.67 million a year ago. The change in revenue was attributable to an
additional $17.87 million from increased sales volumes, partially offset by a
loss of $12.71 million from reduced commodity prices.
    Gentry's natural gas sales rose 42% to 16,658 mcf/d from 11,699 mcf/d in
2005. This increase contributed $16.56 million to the change in revenue, while
the 5% increase in crude oil and liquid sales to 1,398 bbls/d increased
revenue by $1.31 million.
    The change in gas pricing to $6.63/mcf from $9.15/mcf had the opposite
effect on revenue, reducing it by $15.34 million. This was only partially
offset by the additional $2.63 million realized from the increase in oil and
liquids pricing to $57.86/bbl from $52.71/bbl a year ago.
    Gentry has not entered into any forward contracts for the sale of
commodities since 2001 and none are in place for 2007.

    Royalties

    Gentry's royalties, net of Alberta Royalty Tax Credit (ARTC), increased to
$17.13 million from $11.87 million in 2005. Royalties were 24.5% of production
on an oil, gas and boe basis in 2006. In 2005, royalties were 18.4% on a boe
basis. Increased royalties and mineral taxes on certain lands in Princess are
the primary reasons for the overall increase in royalties. While royalty rates
fluctuate depending on lease terms, royalty holidays, capital cost allowances,
and custom processing deductions, Gentry anticipates the royalty rates to
decrease marginally in 2007.

    -------------------------------------------------------------------------
    ($thousands)                               2006        2005        2004
    -------------------------------------------------------------------------
    Crown royalties                           7,221       6,295       3,690
    -------------------------------------------------------------------------
    Freehold royalties                        7,095       4,015       2,129
    -------------------------------------------------------------------------
    Overriding royalties                      3,187       2,061         886
    -------------------------------------------------------------------------
    Gross royalties                          17,503      12,371       6,705
    -------------------------------------------------------------------------
    ARTC                                       (370)       (500)       (440)
    -------------------------------------------------------------------------
    Net royalties                            17,133      11,871       6,265
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    As a % of revenue                         24.5%       18.4%       19.8%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

    Production Expenses

    Production expenses increased to $15.91 million from $11.89 million in
2005. On a barrel of equivalent basis, costs increased 5% to $10.44/boe from
$9.93/boe in 2005. The high level of industry activity and tight oilfield
services markets resulted in a general increase in field operating costs. Also
contributing to the rise in expenses were increased gas gathering and
processing fees at third party facilities, and a significant workover program
at the Company's non-operated Provost property. These factors offset the
savings realized from the electrification of certain facilities at Princess
and the ownership of fluid handling batteries, also in the Princess area.

    General and Administrative Expenses

    Gentry's general and administrative expenses remained relatively flat at
$3.81 million in 2006, when compared to the $3.76 million in 2005. Staffing
and compensation costs made up almost half of the 2006 expenses versus 43% in
2005. As expected, on a barrel of oil equivalent basis, general and
administrative expenses decreased, falling 20% to $2.50/boe from $3.14/boe in
2005. Looking forward to 2007, moderate increases to gross administrative
costs are expected, however, as production increases, it is anticipated that
per unit costs will decline.

    
    -------------------------------------------------------------------------
    ($thousands)                               2006        2005        2004
    -------------------------------------------------------------------------
    Gross Expenses                            5,767       5,616       4,715
    -------------------------------------------------------------------------
    Recoveries                                 (490)       (372)       (376)
    -------------------------------------------------------------------------
    Capitalized                              (1,469)     (1,489)     (1,165)
    -------------------------------------------------------------------------
    Net Expenses                              3,808       3,755       3,174
    -------------------------------------------------------------------------
    Net Expenses ($/boe)                       2.50        3.14        4.09
    -------------------------------------------------------------------------
    

    Stock Based Compensation

    In 2006, Gentry's stock based compensation expense was $1.84 million
versus $644 thousand a year ago. In the most recent year, $1.73 million
related to the value of vested stock options while the remaining $108 thousand
was the value of Gentry's portion of the shares issued under the Company's
Employee Share Ownership Plan (ESOP). This compares to the prior year figures
of $557 thousand from stock options and $87 thousand from the ESOP. A greater
number of higher valued options vesting in 2006 resulted in the higher charge.

    Interest Expense

    Gentry's interest expense increased to $2.09 million in 2006 from
$1.43 million in 2005. The primary reason for the higher cost was the increase
in interest rates to an average of 5.8% in 2006 from 4.4% in 2005. In
addition, whereas Gentry began and ended 2005 with $17.22 million and
$34.15 million in bank debt respectively, it ended 2006 with $40.75 million in
bank debt as the Company had a higher utilization factor on its line of credit
to fund its capital expenditure programs.

    Depletion, Depreciation and Accretion

    These charges for 2006 were $25.48 million compared with $19.55 million
in the previous year. This trend is expected to continue as the Company
increases its asset base through its capital programs. On a barrel of oil
equivalent basis, costs increased to $16.72/boe versus $16.33/boe in 2005.
    Included in the above amounts is accretion expense, which is the
amortization of the Company's asset retirement obligations. For 2006, this
expense amounted to $204 thousand, or $0.13/boe, compared to $147 thousand, or
$0.12/boe, a year ago.
    The Company's depletion rate increased to 18.52% in 2006 from 16.59% in
2005 and is based on the ratio of annual production to proved reserves
estimates. While production increased 27%, reserves used for the depletion
calculation increased 14%, which accounted for the higher rate.

    Income Taxes

    Gentry was liable for $319 thousand in current taxes in 2006, which was a
40% decrease from the $535 thousand recorded in 2005. The biggest reason for
the decrease was the elimination of the Large Corporations Tax in 2006. On a
unit of production basis, current taxes were $0.21/boe versus $0.45/boe a year
ago.
    Future taxes decreased substantially to $496 thousand in 2006 from
$4.80 million in 2005. On a unit of production basis, they equated to
$0.33/boe in 2006 versus $4.00/boe in 2005. Future taxes were lower than
anticipated due to a decline in the statutory tax rates and the greater
increase in depletion charges as compared with the utilization of tax pools.
    At the end of 2006, Gentry had approximately $82.14 million of
accumulated tax pools available for deduction against income in future years.

    
    -------------------------------------------------------------------------
                                                                    Maximum
                                                    Available        Annual
    ($thousands)                                      balance  deduction (%)
    -------------------------------------------------------------------------
    Canadian oil and gas property expense             $25,701            10
    -------------------------------------------------------------------------
    Canadian development expense                       16,576            30
    -------------------------------------------------------------------------
    Canadian exploration expense                        6,908           100
    -------------------------------------------------------------------------
    Foreign exploration and development expense           193            10
    -------------------------------------------------------------------------
    Undepreciated capital cost                         31,956        20-100
    -------------------------------------------------------------------------
    Cumulative eligible capital                            55             7
    -------------------------------------------------------------------------
    Financing costs                                       752            20
    -------------------------------------------------------------------------
    Total                                             $82,141
    -------------------------------------------------------------------------


    Funds Flow and Net Income

    In 2006, funds flow from operations was $30.44 million versus
$35.03 million in 2005. The increase in gross production revenue was more than
offset by the increased royalties and production expenses, resulting in the
lower figure.
    Net income fell to $2.76 million from $10.20 million in 2005. In assessing
the change, reduced funds flow of $4.59 million, coupled with an additional
$5.93 million in depletion, depreciation, and accretion charges and $1.19
million in stock-based compensation expenses, were more than enough to offset
the $4.30 million reduction in future taxes.
    On a per share basis, funds flow was $0.79 per share ($0.77 diluted) in
2006 compared to $0.90 ($0.86 diluted) in 2005. Net income was $0.07 per share
($0.07 diluted) versus $0.26 per share ($0.25 diluted) a year ago.

    Operating Netbacks

    ($/boe)                                    2006        2005        2004
                                           ----------------------------------
    Selling price                             45.83       54.01       40.86
    Royalties (net of ARTC)                  (11.24)      (9.91)      (8.07)
    Production expenses                      (10.44)      (9.93)      (9.37)
                                           ----------------------------------
    Operating netbacks                        24.15       34.17       23.42
    


    Capital Expenditures

    Excluding acquisitions and divestitures, capital expenditures decreased
7% to $42.85 million from $46.25 million in 2005. In 2006, the Company drilled
or participated in 51 wells (48.0 net) with a success rate of 90% (91% net),
compared to 88 gross wells (57.9 net) and a success rate of 94% (92% net) in
2005. The Company expended additional funds on facilities, equipping and
tie-ins, primarily at Princess, which, going forward, should mean greater
production and operating efficiencies.
    On a net basis, capital expenditures were $36.25 million in 2006 versus
$53.85 million a year ago. In the fourth quarter of 2006, the Company disposed
of approximately 98 boe/d of non-operated production for gross proceeds of
$7.21 million. This was in contrast to the 2005 net acquisition figures when
the Company acquired approximately 195 boe/d of production for gross proceeds
of $8.08 million.

    
    -------------------------------------------------------------------------
    ($thousands)                               2006        2005        2004
    -------------------------------------------------------------------------
    Drilling and completions                 18,131      26,050      11,773
    -------------------------------------------------------------------------
    Facilities and equipping                 17,414      13,171       6,403
    -------------------------------------------------------------------------
    Land and seismic                          5,767       5,509       7,360
    -------------------------------------------------------------------------
    Capitalized expenses                      1,469       1,489       1,165
    -------------------------------------------------------------------------
    Other                                        65          28         129
    -------------------------------------------------------------------------
    Gross expenditures                       42,846      46,247      26,830
    -------------------------------------------------------------------------
    Acquisitions, net                        (6,597)      7,607      16,571
    -------------------------------------------------------------------------
    Net expenditures                         36,249      53,854      43,401
    -------------------------------------------------------------------------

    Net Asset Value

    At December 31, 2006, the Company's net asset value, based on a 10%
discount factor, equated to $5.03 per share compared with $6.20 per share in
2005. While the value of undeveloped land and seismic increased by 62%, it
could not compensate for the reduction in value of the year end reserves. The
following is a summary of the Net Asset Value calculation, discounted at 10%:

    -------------------------------------------------------------------------
    ($thousands, except per share amounts)     2006        2005        2004
    -------------------------------------------------------------------------
    Reserves                                170,463     235,376     129,322
    -------------------------------------------------------------------------
    Undeveloped land and seismic(1)          58,286      35,945      37,101
    -------------------------------------------------------------------------
    Investments(2)                           13,896       8,488       8,698
    -------------------------------------------------------------------------
    Net debt                                (47,312)    (39,174)    (19,729)
    -------------------------------------------------------------------------
    Net Asset Value                         195,333     240,635     155,392
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    Common shares outstanding                38,811      38,831      38,471
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    Net asset value per common share           5.03        6.20        4.04
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) internal estimate
    (2) market value as at December 31
    


    Liquidity and Capital Resources

    As was the case in 2005, Gentry did not access the equity markets in 2006
as its capital programs were financed from funds flow and its credit facility.
    Gentry began the year with 38,830,799 common shares issued and
outstanding. During 2006, the Company issued 551,102 shares on the exercise of
incentive stock options ($1.55 per share); 41,529 shares pursuant to the
Company's employee share purchase plan ($5.21 per share); and 612,300 shares
were repurchased and cancelled pursuant to the Company's Normal Course Issuer
Bid ($5.22 per share). As a result of these changes, Gentry ended the year
with 38,811,130 common shares issued and outstanding. As of the date of this
MD&A, 38,849,110 common shares were outstanding and a further 3,129,167 shares
were reserved for issuance pursuant to the exercise of outstanding incentive
stock options (at an average price of $3.30 per share).
    Gentry's year-end net debt was $47.31 million compared with
$39.17 million at the end of 2005. Gentry's credit limit stands at $50 million
and is reviewed semi-annually. The limit is currently being reviewed based
upon the Company's December 31, 2006 Reserves Report.
    Gentry owns 10.68 million common shares of Stratic Energy Corporation, a
junior international exploration company. Gentry monitors its investments on a
regular basis and as at December 31, 2006, the market value of its Stratic
holdings was $13.89 million.

    Contractual Obligations

    In the normal course of business, Gentry has entered into the following
contractual obligations and commitments:

    
    -------------------------------------------------------------------------
    ($thousands)     2007      2008      2009      2010      2011     Total
    -------------------------------------------------------------------------
    Office lease      174       159         -         -         -       333
    -------------------------------------------------------------------------
    Firm service
     transportation    40        12        69        69        12       202
    -------------------------------------------------------------------------
                      214       171        69        69        12       535
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


    Fourth Quarter Results

    Gentry's financial and operating highlights from the fourth quarter of
2006, as compared with the fourth quarter of 2005, are summarized below:


    Three months ended December 31             2006        2005    % change
    -------------------------------------------------------------------------
    Financial ($thousands)
      Production revenue                     17,924      22,165         (19)
      Royalties, net of ARTC                  5,380       3,948          36
      Production expenses                     5,552       3,474          60
      General & administrative                1,413       1,537          (8)
      Interest                                  607         379          60
      Current taxes                              63         102         (38)
      Asset retirement expenditures              34          74         (54)
      Funds flow from operations              4,875      12,652         (61)
      Depletion, depreciation and accretion   6,659       8,716         (24)
      Future taxes (recovery)                (1,487)      1,170        (227)
      Stock-based compensation                  668         103         550
      Net income (loss)                        (931)      2,737        (134)
      Capital expenditures, net               3,603      19,743         (82)
    -------------------------------------------------------------------------
    Production
      Oil & Liquids (bbls/d)                  1,447       1,486          (3)
      Gas (mcf/d)                            17,331      14,189          22
      Barrels of oil equivalent               4,335       3,851          13
    -------------------------------------------------------------------------
    Pricing
      Oil & Liquids ($/bbl)                   50.59       52.27          (3)
      Natural gas ($/mcf)                      7.02       11.50         (39)
      Barrel of oil equivalent ($/boe)        44.94       62.56         (28)
    -------------------------------------------------------------------------
    

    In spite of the increased production volumes in the fourth quarter of
2006, production revenue was down due to the lower commodity pricing
environment. Royalties increased as a result of higher rates and the recording
of adjustments to prior quarter's calculation and accruals. A portion of the
rise in production expenses was attributable to the increased production, but
increased costs associated with third party facilities was also a contributing
factor as was a general increase due to the tight oilfield services market.
Based largely on the above reasons, funds flow from operations was down 61%
over the comparative fourth quarter.
    Depletion, depreciation and accretion decreased 24% in the fourth quarter
of 2006. The relatively larger additions to proved reserves in the fourth
quarter helped reduce the depletion rate, resulting in the lower figure.
Stock-based compensation increased as the result of certain stock options
becoming vested in the most recent quarter, while future income taxes fell
significantly due to the reduced profitability of the Company as measured
against the comparative quarter.
    Deducting the depletion and stock-based compensation expenses from funds
flow, and adding back the asset retirement expenditures and future income tax
recovery, gives a net loss of $931 thousand in the fourth quarter of 2006. The
largest contributing factor to this loss is the reduced funds flow from
operations.
    Net capital expenditures decreased significantly to $3.60 million from
$19.74 million a year ago, as the Company disposed of 98 boe/d for gross
proceeds of $7.21 million. Gentry also scaled back its capital programs in the
most recent quarter as drilling and completions were $4.58 million versus
$11.92 million the comparative quarter. The Company participated in the
drilling of seven wells (6.5 net) in the fourth quarter of 2006 versus 29
wells (19.6 net) in the fourth quarter of 2005. Expenditures on facilities and
equipping remained relatively flat at $5.34 million, with the bulk of that
dedicated to pipelines, tie-ins and facilities at Princess.

    
    Selected Quarterly Information

    -------------------------------------------------------------------------
                                                                       2006
    -------------------------------------------------------------------------
    Three months ended     Dec 31        Sep 30        Jun 30        Mar 31
    -------------------------------------------------------------------------
    Production
    -------------------------------------------------------------------------
      bbls/d                1,447         1,538         1,289         1,317
    -------------------------------------------------------------------------
      mcf/d                17,331        14,388        18,139        16,792
    -------------------------------------------------------------------------
      boe/d                 4,335         3,936         4,312         4,116
    -------------------------------------------------------------------------
    Financial
    -------------------------------------------------------------------------
      Production revenue   17,924        16,147        18,105        17,656
    -------------------------------------------------------------------------
      Funds flow from
       operations           4,875         7,085         9,481         9,004
    -------------------------------------------------------------------------
         per share
         - basic             0.13          0.18          0.25          0.23
    -------------------------------------------------------------------------
         per share
         - diluted           0.12          0.18          0.23          0.22
    -------------------------------------------------------------------------
      Net income (loss)      (931)          104         1,639         1,945
    -------------------------------------------------------------------------
        per share
         - basic            (0.02)            -          0.04          0.05
    -------------------------------------------------------------------------
        per share
         - diluted          (0.02)            -          0.04          0.05
    -------------------------------------------------------------------------



    -------------------------------------------------------------------------
                                                                       2005
    -------------------------------------------------------------------------
    Three months ended     Dec 31        Sep 30        Jun 30        Mar 31
    -------------------------------------------------------------------------
    Production
    -------------------------------------------------------------------------
      bbls/d                1,486         1,291         1,295         1,246
    -------------------------------------------------------------------------
      mcf/d                14,189        11,177        10,512        10,889
    -------------------------------------------------------------------------
      boe/d                 3,851         3,154         3,047         3,061
    -------------------------------------------------------------------------
    Financial
    -------------------------------------------------------------------------
      Production revenue   22,165        17,685        12,832        11,984
    -------------------------------------------------------------------------
      Funds flow from
       operations          12,652        10,071         6,563         5,746
    -------------------------------------------------------------------------
         per share
         - basic             0.33          0.26          0.17          0.15
    -------------------------------------------------------------------------
         per share
         - diluted           0.31          0.25          0.16          0.14
    -------------------------------------------------------------------------
      Net income (loss)     2,737         4,336         1,843         1,286
    -------------------------------------------------------------------------
        per share
         - basic             0.07          0.11          0.05          0.03
    -------------------------------------------------------------------------
        per share
         - diluted           0.07          0.11          0.05          0.03
    -------------------------------------------------------------------------
    

    Production increases are typically stronger in the first and fourth
quarters as wells drilled in previous quarters are tied in or begin to produce
to single well batteries. The second quarter is typically characterized by wet
weather and break-up conditions, making access to certain locations difficult.
This can restrict exploration programs, field operations, and basic product
transportation. Volumes in the third quarter of 2006 were directly impacted by
downtime at three third party operating facilities which curtailed production
at both Princess and Sedalia.
    Generally speaking, production revenue and funds flow are largely a
function of production volumes and commodity prices. In 2005, Gentry's average
sales price rose from $43.50/boe in the first quarter to $62.56/boe in the
fourth quarter, with the biggest jump coming in the third quarter. In 2006,
although both crude oil and gas prices were quite volatile, most of the change
in production revenue was volume based, as Gentry's average sales price of
$45.83/boe did not vary by more than $2/boe in any one quarter. Funds flow
from operations was lower than expected in the fourth quarter of 2006 due to
increased production expenses and additional royalties recorded in the period.
    In the fourth quarter of 2005, net income dropped relative to prior
quarters due to increased depletion charges and higher future income taxes.
The depletion charges increased as a result of a larger capital asset base and
a higher depletion rate, while future income taxes went up as the Company
utilized a greater proportion of its tax pools to reduce its taxable income
and current taxes. In the fourth quarter of 2006, the net loss was largely
attributable to the reduced funds flow from operations.

    2007 Outlook

    Gentry's Board of Directors has approved a revised 2007 capital budget of
$45 million, approximately 60% of which is slated for drilling and
completions. The remaining 40% will be spent on land, seismic, and facilities,
including new construction and enhancements to existing infrastructure. This
budget will be funded from funds flow and the existing line of credit.

    Critical Accounting Estimates

    Gentry is required to make certain assumptions and estimates in the
application of GAAP that may have a significant impact on the financial
results of the Company. The following is a discussion of the estimates that
are critical to Gentry's consolidated financial statements.

    Oil and Natural Gas Reserves and Full Cost Accounting

    Gentry follows the full cost method of accounting for its oil and gas
properties and equipment as prescribed by the Canadian Institute of Chartered
Accountants (CICA). Accordingly, all costs associated with the acquisition,
exploration and development of oil and natural gas reserves are capitalized
and then depleted using the unit-of-production method based on estimated
proved reserves. A ceiling test ensures the carrying value of a long-life
asset can be recovered from its undiscounted future cash flows.
    Reserve estimates can have a significant impact on net income and the
carrying value of property and equipment as they are the key component in the
calculation of depletion, depreciation and accretion as well as the ceiling
test. Revisions to reserve estimates could result in a higher or lower
depletion, depreciation and accretion expense being charged to net income
while downward revisions to reserve estimates could result in a write down of
property and equipment based on the ceiling test.
    100% of Gentry's reserves are evaluated by the independent engineering
firm of Sproule Associates Limited. This evaluation requires significant
estimates to be made on various engineering data as well as future production
rates, capital expenditures and commodity prices, all of which are subject to
a number of uncertainties and various interpretations. The Company expects
that over time its estimates of reserves will be revised, either upwards or
downwards, based on future drilling, testing, production rates and commodity
forecasts.

    Asset Retirement Obligations

    Gentry estimates the fair value of each asset retirement obligation. The
obligation is based on current regulations, costs, technologies, and industry
standards and is calculated using estimates for the timing of abandonment,
inflation, and a credit-adjusted risk-free interest rate. The discounted
obligation is initially capitalized as part of the carrying amount of the
property and equipment and a corresponding liability is recognized. The
increase in property and equipment is depleted and depreciated on the same
basis as the remainder of the property and equipment. The liability is
accreted against income, until it is settled or the property is sold, and is
included as a component of depletion, depreciation and accretion expense.
    Retirement obligations can have a material impact on the consolidated
balance sheets and consolidated statements of income of the Company. Revisions
to any or all of the aforementioned factors and estimates used in calculating
the obligation may result in changes to the carrying value of property and
equipment and the related liability, as well as the depletion, depreciation
and accretion expense charged to net income. The Company expects that over
time its estimate of its asset retirement obligations will be revised, either
upwards or downwards, based on future regulations, costs, technologies,
industry standards, timing of abandonment, and interest and inflation rates.

    Stock-based Compensation

    Gentry follows the fair value method of accounting for its stock-based
compensation arrangements relating to stock options grants. The Company
recognizes a compensation expense based on the fair value of the options on
the date of grant using the Black-Scholes option-pricing method and amortizes
the expense over the vesting period of the options. The Black-Scholes method
requires estimates for the volatility of the Company's stock, a risk-free
interest rate, an expected dividend rate, and the expected life of the
options. Changes in these estimates will change the fair value of the option
and affect the compensation expense recorded in the consolidated financial
statements.

    Other Accounting Estimates

    Gentry follows the accrual method of accounting which requires the
Company to incorporate certain estimates in its financial and operating
results. This includes estimates of revenues, royalties, production expenses,
administrative costs and capital items for specific reporting periods for
which actual results have not yet been received. Gentry ensures that the
personnel with the most knowledge of the relevant activities are responsible
for the estimates, which are then reviewed for reasonableness. Past estimates
are also compared to actual results in order to make more informed decisions
when accruing future amounts.

    New Accounting Standards

    During the past and upcoming years, a number of changes to financial
reporting requirements have been introduced. The following outlines the most
notable changes and those which have, or may have, the greatest impact on
Gentry.

    Non-Monetary Transactions

    The CICA introduced handbook section 3831 - "Non-Monetary Transactions"
which became effective for interim and fiscal periods beginning on or after
January 1, 2006. The standard requires that all non-monetary transactions be
measured at fair values, rather than book values, if the transaction has
commercial substance. A transaction will have commercial substance if it
causes an identifiable and measurable change in the economic circumstance of
the entity. For example, if a Company swaps a producing asset for undeveloped
land, there would be an identifiable and measurable change in economic
circumstances and the transaction would be measured at fair value. The impact
of this standard cannot be measured until such time as Gentry completes a
non-monetary transaction.

    Financial Instruments - Recognition and Measurement

    The CICA introduced handbook section 3855 - "Financial Instruments -
Recognition and Measurement" which becomes effective for interim and annual
periods beginning on or after October 1, 2006 (with early adoption permitted).
The standard will require Gentry to classify its financial instruments as:
held for trading, held to maturity, loans and receivables, or available for
sale. Gentry's investments will be classified as available for sale and
measured at fair value with gains and losses recognized in Comprehensive
Income (see new standard below) until the asset is derecognized or becomes
impaired. The Company will adopt this standard for its first quarterly
reporting period beginning January 1, 2007.

    Comprehensive Income

    The CICA introduced handbook section 1530 - "Comprehensive Income" which
becomes effective for interim and annual periods beginning on or after October
1, 2006 (with early adoption permitted). The standard will require Gentry to
recognize gains and losses arising from the fluctuation of the share price of
its investments and include these gains and losses as a separate component in
the Income Statement with the accumulated gains and losses shown as a separate
component of Shareholders Equity. At December 31, 2006, Gentry followed the
cost method of accounting for its investments whereby no gains or losses on
investments were recognized unless there had been a permanent decline in
value. The impact of this new standard to the Company will be dependent on the
changes in market value of Gentry's investments. The Company will adopt this
standard for its first quarterly reporting period beginning January 1, 2007.

    Hedging

    The CICA issued handbook section 3865 - "Hedges" which becomes effective
for interim and annual periods beginning on or after October 1, 2006 (with
early adoption permitted). The new standard is optional, but must be applied
if an entity chooses to use hedge accounting. Hedges must be designated as
either fair value hedges, cash flow hedges, or hedges of a net investment in a
self-sustaining foreign operation. For a fair value hedge, the gain or loss is
recognized in net income in the period of change and the carrying amount of
the hedged item is adjusted for the hedged risk. For other hedges, the
effective portion of the hedging item's gain or loss is initially reported in
Other Comprehensive Income and subsequently reclassified to net income when
the hedged item affects net income. As Gentry had no hedges in place in 2006
and none are in place for 2007, these policy changes currently have no effect
on the Company. Gentry has not yet determined if it will follow this optional
standard.

    Business Risks and Uncertainties

    Gentry, like all companies in the oil and gas industry, operates in an
environment subject to inherent risks. Gentry groups these risks into three
main areas - operational, financial, and regulatory.

    Operational Risks

    Gentry's operational activities are focused on the Western Canadian
Sedimentary Basin, a competitive environment with a number of companies
exploring for hydrocarbons. The high level of activity has put pressure on the
availability and pricing of supplies and materials as well as staff and field
services. Other operational risks include weather delays, mechanical or
technical difficulties, and exploration risks associated with finding
economically viable hydrocarbon reserves. Gentry attempts to manage these
risks by maintaining an inventory of certain critical equipment; conducting
advance planning to manage its drilling programs in an efficient and cost
effective manner; hiring experienced technical staff and personnel to conduct
its exploration programs; and maintaining a broad base of interests in
different areas of the Basin.
    Gentry's field operations are also subject to health, safety and
environmental risks. Gentry maintains a Health, Safety and Environmental
Policy and an Emergency Response Plan which are updated bi-annually or as
needed to comply with current legislation. Both are designed to protect the
health and safety of all concerned persons in addition to respecting any
environmental regulations. Gentry also maintains insurance covering property,
drilling, pollution, and commercial general liability.

    Financial Risks

    Financial risks faced by the Company include fluctuations in commodity
prices, US/Canadian foreign exchange rates, interest rates, the ability to
access capital and/or debt markets, and credit risks associated with its joint
venture partners and purchasers. While Gentry does not hedge its production,
foreign exchange rates or interest rates, it does attempt to mitigate overall
financial risks by maintaining a debt to forward year's cash flow ratio of no
more than 1:1, having a flexible capital program, and managing its reliance on
joint venture partners.

    Regulatory Risks

    Gentry is subject to various policies and legislation governing the oil
and gas industry. Although these policies are out of Gentry's direct control,
Gentry is a member of the Canadian Association of Petroleum Producers, which,
amongst other things, is the voice of the upstream oil and gas industry in
Canada. Gentry operates in a manner that is in compliance with applicable
regulations and industry standards and must react to comply with changes as
they occur.

    Disclosure Controls and Procedures

    Gentry has designed such disclosure controls and procedures to ensure
that information required to be disclosed by the Company is accumulated and
communicated to management as appropriate to allow for timely decisions
regarding required disclosure. Based on their evaluation, the Company's Chief
Executive Officer (CEO) and Chief Financial Officer (CFO) have concluded that
Gentry's disclosure controls and procedures are effective to provide
reasonable assurance that material information related to the Company is made
known to them and that these controls and procedures were operating
effectively as of December 31, 2006. It should be noted that while the
evaluation provides a reasonable level of assurance that the disclosure
controls and procedures are effective, it does not guarantee that they 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.

    Internal Control Over Financial Reporting

    In accordance with Multilateral Instrument 52-109, Gentry has, under the
supervision of its CEO and CFO, designed a process of internal control over
financial reporting. The process was designed to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with Canadian
generally accepted accounting principles (GAAP).
    Based on the CEO and the CFO's review of the design of internal controls
over financial reporting, a limitation in the control system has been
identified. As a small organization, and similar to other small organizations,
Gentry's staff and management is composed of a small number of key individuals
such that it is not economically feasible to achieve a complete segregation of
duties. As a result of this weakness, there is only reasonable, not absolute,
assurance that a material misstatement would not be prevented or detected.
Management and Audit Committee reviews are utilized to mitigate the risk of
material misstatement in the financial reporting process. Additional
accounting staff will be added as the Company grows and this is expected to
remediate this issue.
    It should be noted that while the design of internal control over
financial reporting provides a reasonable level of assurance that a material
misstatement would be prevented, it does not guarantee that it 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.



    
                            GENTRY RE

SOURCES LTD. CONSOLIDATED BALANCE SHEETS As at December 31, 2006 and 2005 ------------------------------------------------------------------------- ASSETS 2006 2005 ----------------------------- CURRENT Cash and cash equivalents $ 18,406 $ 13,090 Accounts receivable 11,992,126 14,819,088 Prepaid expenses 580,361 625,961 ----------------------------- 12,590,893 15,458,139 INVESTMENTS (NOTE 2(c)) 1,809,583 1,707,458 PROPERTY AND EQUIPMENT (NOTE 3) 127,425,551 114,901,195 ----------------------------- $141,826,027 $132,066,792 ----------------------------- ----------------------------- LIABILITIES & SHAREHOLDERS' EQUITY CURRENT Accounts payable and accrued liabilities $ 18,858,031 $ 20,179,163 Income taxes payable 294,859 303,405 Bank debt (Note 4) 40,750,000 34,150,000 ----------------------------- 59,902,890 54,632,568 ASSET RETIREMENT OBLIGATIONS (NOTE 5) 5,104,300 3,473,144 FUTURE INCOME TAXES (NOTE 6(a)) 12,393,282 11,897,016 ----------------------------- 77,400,472 70,002,728 ----------------------------- SHARE CAPITAL (NOTE 7) 43,515,360 42,906,253 CONTRIBUTED SURPLUS (NOTE 7(d)) 2,335,783 823,918 RETAINED EARNINGS 18,574,412 18,333,893 ----------------------------- 64,425,555 62,064,064 ----------------------------- $141,826,027 $132,066,792 ----------------------------- ----------------------------- Commitments (NOTE 10) Please refer to the accompanying notes. GENTRY RE

SOURCES LTD. CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS For the years ended December 31, 2006 and 2005 ------------------------------------------------------------------------- 2006 2005 ----------------------------- REVENUE Production $ 69,832,337 $ 64,665,175 Less: royalties, net of Alberta Royalty Tax Credit (17,132,839) (11,870,924) ----------------------------- 52,699,498 52,794,251 ----------------------------- EXPENSES Depletion, depreciation & accretion 25,481,638 19,550,137 Production 15,908,052 11,886,328 General & administrative 3,808,274 3,755,310 Interest on bank debt 2,093,392 1,425,161 Stock-based compensation (Note 7(b) AND 7(d)) 1,835,971 643,882 ----------------------------- 49,127,327 37,260,818 ----------------------------- INCOME BEFORE INCOME TAXES 3,572,171 15,533,433 ----------------------------- INCOME TAXES (NOTE 6(b)) Current 318,695 534,757 Future 496,266 4,796,238 ----------------------------- 814,961 5,330,995 ----------------------------- NET INCOME 2,757,210 10,202,438 Retained earnings, beginning of year 18,333,893 9,048,384 Less: excess of cost of shares acquired over stated value (NOTE 7(c)) (2,516,691) (916,929) ----------------------------- Retained earnings, end of year $ 18,574,412 $ 18,333,893 ----------------------------- ----------------------------- NET INCOME PER SHARE Basic (Note 8) $ 0.07 $ 0.26 ----------------------------- ----------------------------- Diluted (Note 8) $ 0.07 $ 0.25 ----------------------------- ----------------------------- Please refer to accompanying notes. GENTRY RE

SOURCES LTD. CONSOLIDATED STATEMENTS OF CASH FLOWS For the years ended December 31, 2006 and 2005 ------------------------------------------------------------------------- 2006 2005 ----------------------------- OPERATING ACTIVITIES Net income $ 2,757,210 $ 10,202,438 Adjustments for: Depletion, depreciation & accretion 25,481,638 19,550,137 Stock-based compensation 1,835,971 643,882 Future income taxes 496,266 4,796,238 Asset retirement expenditures (126,137) (160,441) ----------------------------- 30,444,948 35,032,254 Changes in non-cash working capital items 4,557,570 145,741 ----------------------------- 35,002,518 35,177,995 ----------------------------- INVESTING ACTIVITIES Capital expenditures (43,283,284) (53,854,150) Dispositions of property and equipment 7,034,583 - Acquisition of investments (102,125) - Changes in non-cash working capital items (3,119,841) 2,426,446 ----------------------------- (39,470,667) (51,427,704) ----------------------------- FINANCING ACTIVITIES Proceeds from (repayments on) bank debt, net 6,600,000 16,930,000 Redemption of share capital (3,195,388) (1,163,098) Proceeds on issuance of share capital, net 963,697 539,071 Changes in non-cash working capital items 105,156 (111,461) ----------------------------- 4,473,465 16,194,512 ----------------------------- INCREASE (DECREASE) IN CASH 5,316 (55,197) CASH AND CASH EQUIVALENTS, beginning of year 13,090 68,287 ----------------------------- CASH AND CASH EQUIVALENTS, end of year $ 18,406 $ 13,090 ----------------------------- ----------------------------- SUPPLEMENTAL CASH FLOWS DISCLOSURE: Interest paid $ 2,093,392 $ 1,425,161 ----------------------------- ----------------------------- Income taxes paid $ 327,241 $ 278,092 ----------------------------- ----------------------------- Please refer to the accompanying notes. GENTRY RE

SOURCES LTD. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 2006 AND 2005 ------------------------------------------------------------------------- 1. Company activities The Company's activities are the exploration for and development of petroleum and natural gas properties in Canada. 2. Summary of significant accounting policies These financial statements have been prepared using accounting principles generally accepted in Canada which include: a) Principles of consolidation On April 1, 2005, the Company amalgamated with its wholly owned subsidiaries, Gentry Resources (Saskatchewan) Ltd. and Gentry Income Funds Inc. The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiary, Gentry Resources (West Africa) Inc., which is inactive and has no production operations. b) Cash and cash equivalents Cash and cash equivalents consist of amounts on deposit with banks and broker accounts. c) Investments The Company records its investment in Stratic Energy Corporation ("Stratic"), a corporation which was formerly related by virtue of common directors and officers, and its other investment using the cost method of accounting whereby the investments are initially recorded at cost. Earnings are recognized only to the extent received or receivable. Where there has been a permanent or other than temporary decline in value, the investments are stated at estimated net realizable value. d) Petroleum and natural gas exploration and development expenditures The Company follows the Canadian full cost method of accounting whereby all costs related to the exploration for and the development of petroleum and natural gas reserves are initially capitalized and accumulated in cost centres by country. Costs capitalized include land acquisition costs, geological and geophysical expenditures, costs of drilling productive and non- productive wells, together with overhead and interest directly related to exploration and development activities and lease and well equipment. Gains or losses are not recognized upon disposition of petroleum and natural gas properties unless such a disposition would significantly alter the related cost centre's rate of depletion and depreciation. A significant disposition is defined as causing a change of 20% or more in the annual depletion rate. Costs capitalized are depleted and depreciated using the unit-of- production method by cost centre based upon gross proved petroleum and natural gas reserves as determined by independent engineers. For purposes of the calculation, petroleum and natural gas reserves are converted to a common unit of measure on the basis of their relative energy content, whereby one barrel of oil is equivalent to six thousand cubic feet of natural gas. The costs of significant unproved properties are excluded from the depletion and depreciation base until it is determined whether proved reserves are attributable to the properties, or impairment has occurred. The Company tests impairment against undiscounted future net revenues from proved reserves using expected future product prices and costs. Impairment is recognized when the carrying amount is greater than the undiscounted future net revenues, at which time assets are written down to the fair value of proved and probable reserves plus the cost of unproved properties, net of impairment allowances. Fair value is determined using expected future product prices and costs, and amounts are discounted using a risk-free interest rate. e) Depreciation Other assets are depreciated using the declining balance method at annual rates of 20% to 100%. f) Income taxes Income taxes are accounted for using the liability method of income tax allocation. Under the liability method, income tax assets and liabilities are recorded to recognize future income tax inflows and outflows arising from the settlement or recovery of assets and liabilities at the carrying values. Income tax assets are also recognized for the benefits from tax losses and deductions that cannot be identified with particular assets or liabilities, provided those benefits are more likely than not to be realized. Future income tax assets and liabilities are determined based on the tax laws and rates that are anticipated to apply in the year of realization. g) Asset retirement obligations The estimated fair value of each asset retirement obligation is recorded in the period a well or related asset is drilled, constructed or acquired. Fair value is estimated using the present value of the estimated future cash outflows to abandon the asset at the Company's credit-adjusted risk-free interest rate. The obligation is reviewed regularly by Company management based upon current regulations, costs, technologies and industry standards. The discounted obligation is initially capitalized as part of the carrying amount of the related oil and natural gas properties and a corresponding liability is recognized. The increase in oil and natural gas properties is depleted and depreciated on the same basis as the remainder of the oil and natural gas properties. The liability is accreted against income until it is settled or the property is sold and is included as a component of depletion, depreciation and accretion expense. Actual restoration expenditures are charged to the accumulated obligation as incurred. h) Flow-through shares The Company, from time to time, issues flow-through shares to finance a portion of its capital expenditure program. Pursuant to the terms of the flow-through share agreements, the tax deductions associated with the expenditures are renounced to the subscribers. Accordingly, share capital is reduced and a future tax liability is recorded equal to the estimated amount of future income taxes payable by the Company as a result of the renunciations. This reduction to share capital and increase in future tax liability is recognized when the expenditures are renounced. i) Stock-based compensation The Company has a stock option plan as described in Note 7(a). Stock-based compensation expense is recorded for all options granted on or after January 1, 2003, with a corresponding increase recorded to contributed surplus. The compensation expense is recognized over the vesting period. The fair value of options granted are estimated at the date of grant using the Black-Scholes valuation model. Upon the exercise of stock options, consideration paid by employees or directors together with the amount previously recognized in contributed surplus is recorded as an increase to share capital. j) Net income per share Diluted net income per share is calculated using the treasury stock method, whereby it is assumed that proceeds from the exercise of in-the-money stock options plus the unamortized portion of stock-based compensation are used by the Company to repurchase Company shares at the weighted average market price during the year. k) Revenue recognition Revenue from the sale of petroleum and natural gas is recognized based on volumes delivered to customers at contractual delivery points and rates. The costs associated with the delivery, including operating and maintenance costs, transportation, and production based royalty expenses are recognized in the same period in which the related revenue is earned and recorded. l) Foreign currency translation The Company follows the temporal method when translating foreign currency transactions and the financial statements of its integrated subsidiary. Under this method, foreign currency denominated assets and liabilities are translated at the exchange rate prevailing at the balance sheet date for monetary items and at the transaction date for non-monetary items. Revenues and expenses, except depletion, depreciation and accretion, are translated at average exchange rates for the year. Depletion, depreciation and accretion are translated at the same rate as the related assets. Exchange gains or losses on translation of current and non-current monetary items are included in the determination of net income. m) Joint venture accounting Substantially all of the Company's exploration and production activities are conducted jointly with others, and accordingly, these financial statements reflect only the Company's proportionate interest in such activities. n) Measurement uncertainty The amounts recorded for depletion, depreciation and accretion, asset retirement obligations and the ceiling test are based on estimated proved reserves, production rates, future petroleum and natural gas prices and future costs. By their nature, these estimates are subject to measurement uncertainty and the effect of changes in such estimates in future periods could be significant. The amounts used to estimate fair values of stock options issued are based on estimates of future volatility of the Company's share price, expected lives of the options, expected dividends to be paid by the Company and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty and the effect of changes in such estimates on the financial statements of future periods could be significant. 3. Property and equipment 2006 2005 ----------------------------- Petroleum and natural gas properties including exploration and development thereon $149,592,699 $128,195,327 Production equipment and facilities 54,190,215 37,851,471 Other 973,488 907,947 ----------------------------- 204,756,402 166,954,745 Accumulated depletion and depreciation 77,330,851 52,053,550 ----------------------------- $127,425,551 $114,901,195 ----------------------------- ----------------------------- During the year, the Company capitalized $1,468,683 (2005 - $1,489,120) in general and administrative expenses. No interest has been capitalized. Costs of unproved petroleum and natural gas properties amounting to $22,054,459 (2005 - $20,584,330) have been excluded from the depletion calculation. The Company prepared a ceiling test calculation at December 31, 2006 to assess the recoverability of its petroleum and natural gas properties. The ceiling test was based upon a valuation of the petroleum and natural gas properties prepared by an independent engineering firm based upon future oil and gas benchmark prices and adjusted for commodity price differentials specific to the Company. The following table summarizes the benchmark references prices used in the ceiling test calculation: --------------------------------------------------------------------- Edmonton AECO Light Sweet Natural Gas WTI Oil 40 degrees API Spot Price ($US/bbl) ($Cdn/bbl) ($Cdn/mmbtu) --------------------------------------------------------------------- 2007 65.73 74.10 7.72 --------------------------------------------------------------------- 2008 38.82 77.62 8.59 --------------------------------------------------------------------- 2009 62.42 70.25 7.74 --------------------------------------------------------------------- 2010 58.37 65.56 7.55 --------------------------------------------------------------------- 2011 55.20 61.90 7.72 --------------------------------------------------------------------- 2012 56.31 63.15 7.85 --------------------------------------------------------------------- 2013 57.43 34.42 7.99 --------------------------------------------------------------------- 2014 58.58 65.72 8.12 --------------------------------------------------------------------- 2015 59.75 67.04 8.26 --------------------------------------------------------------------- 2016 60.95 68.39 8.40 --------------------------------------------------------------------- 2017 62.17 69.76 8.54 --------------------------------------------------------------------- Prices increase at a rate of 2.00% thereafter. 4. Bank debt The Company has an uncommitted demand revolving credit facility to a maximum of $50,000,000. The facility is available to the Company by way of prime rate based loans, banker's acceptances and letters of credit. Interest is payable monthly at the bank's prime lending rate. The facility is secured by a general assignment of book debts, a $100,000,000 demand debenture with a floating charge over all assets with a Negative Pledge and Undertaking to provide fixed charges upon request. Under the terms of the agreement, the Company is required to meet certain financial and other reporting requirements and may not breach certain financial tests without prior consent of the bank. The credit facility is subject to review on a semi-annual basis. The next review will be undertaken on or before May 31, 2007. 5. Asset retirement obligations The following table summarizes changes in the asset retirement obligations for the years ended December 31, 2006 and 2005: ----------------------------- 2006 2005 ----------------------------- Asset retirement obligations, beginning of year $ 3,473,144 $ 2,671,657 Liabilities incurred 1,684,394 745,691 Liabilities settled (126,137) (160,441) Liabilities acquired - 69,369 Liabilities disposed (131,438) - Accretion expense 204,337 146,868 ----------------------------- Asset retirement obligations, end of year $ 5,104,300 $ 3,473,144 ----------------------------- ----------------------------- The inflated, undiscounted amount of the estimated future cash flows required to settle the obligations is $9,809,550 (2005 - $6,921,310). These obligations are expected to be paid over the next several years with a weighted average life of approximately 11 years (2005 - 11 years). The estimated future cash flows have been discounted at the credit-adjusted risk-free rate of 6.00% (2005 - 5.25%). As at December 31, 2006 no funds have been set aside to settle these obligations. 6. Income taxes a) Future Income Tax Liability Significant components of the future income tax liability are as follows: ----------------------------- 2006 2005 ----------------------------- Temporary differences related to property and equipment and asset retirement obligations $ 12,728,414 $ 12,441,035 Share issuance and financing costs (233,014) (425,714) Temporary differences related to investments (102,118) (118,305) ----------------------------- $ 12,393,282 $ 11,897,016 ----------------------------- ----------------------------- b) Income Taxes Expense Income taxes expense differs from that which would be expected from applying the combined Canadian federal and provincial income tax rate of 35.00% (2005 - 39.10%) to income before income taxes. The difference results from the following: ----------------------------- 2006 2005 ----------------------------- Expected Tax provision $ 1,250,260 $ 6,073,572 Increases (decreases) resulting from: Resource allowance (1,052,048) (2,507,882) Non-deductible crown payments, net of Alberta Royalty Tax Credit 827,086 1,558,483 Change in tax rates (1,057,731) (422,640) Large corporation and capital taxes 284,452 324,687 Non-deductible stock-based compensation 604,756 217,736 Other (41,814) 87,039 ----------------------------- $ 814,961 $ 5,330,995 ----------------------------- ----------------------------- 7. Share capital Authorized Unlimited number of voting common shares Unlimited number of non-voting preferred shares Issued ------------------------------------------------------------------------- Common shares: 2006 2005 ------------------------------------------------------------------------- Number Stated Value Number Stated Value ------------------------------------------------------------------------- Balance, beginning of year 38,830,799 $ 42,906,253 38,471,234 $ 42,474,623 Stock options exercised for cash (Note 7(a)) 551,102 855,598 546,167 452,058 Fair value of options excercised - 216,008 - 51,717 Issued under employee share purchase plan (Note 7(b)) 41,529 216,198 36,298 174,025 Normal Course Issuer Bids (Note 7(c)) (612,300) (678,697) (222,900) (246,170) ------------------------------------------------------------------------- Balance, end of year 38,811,130 $ 43,515,360 38,830,799 $ 42,906,253 ------------------------------------------------------------------------- ------------------------------------------------------------------------- a) Stock Option Plan Under the Company's stock option plan, the Company may grant options to its directors, officers, employees, and consultants. The maximum number of shares which may be reserved for issuance under the plan is 5,000,000 common shares. The maximum number of shares which may be reserved for issuance to any one person under the plan is 5% of the issued common shares. The plan also provides that the price at which options may be granted cannot be less than the market price of the common shares at the time the option is granted. Options granted under the plan will have a term not exceeding ten years. The vesting period is set by the Board of Directors at the time the options are granted. A summary of the status of the Company's stock option plan, as of December 31, 2006 and 2005 and changes during the years then ending are as follows: ------------------------------------------------------ 2006 2005 ------------------------------------------------------ Weighted Weighted Average Average Number of Exercise Number of Exercise Options Price Options Price ------------------------------------------------------ Outstanding, beginning of year 2,604,667 $1.76 2,995,000 $1.49 Granted 1,240,000 5.60 217,500 3.28 Exercised (551,102) 1.55 (546,167) 0.84 Cancelled (66,665) 3.27 (61,666) 2.25 ----------- ----------- Outstanding, end of year 3,226,900 $3.24 2,604,667 $1.76 ----------- ----------- ----------- ----------- Options exercisable at year-end 2,001,896 $2.33 1,805,226 $1.39 ----------- ----------- ----------- ----------- The following table summarizes the stock options outstanding at December 31, 2006: Options Outstanding Options Exercisable ------------------------------------------------------------------------- Weighted Weighted Average Weighted Average Remaining Average Range of Number of Exercise Contractual Number of Exercise Exercise Prices Options Price Life Options Price ------------------------------------------------------------------------- $0.45 217,500 $0.45 3.1 217,500 $0.45 $0.77 275,000 0.77 4.2 275,000 0.77 $1.18 to $1.53 499,400 1.36 1.2 499,400 1.36 $2.30 to $2.75 865,000 2.31 2.7 576,664 2.31 $3.98 to $4.90 330,000 4.57 4.2 86,666 4.14 $5.24 to $5.74 1,040,000 5.73 4.3 346,666 5.73 ----------- ----------- Total 3,226,900 $3.24 3.3 2,001,896 $2.33 ----------- ----------- ----------- ----------- b) Employee Share Purchase Plan The Company maintains an employee share purchase plan (the "Plan"), whereby the Company is authorized to match employees' purchases under the Plan from a minimum of two percent to a maximum of five percent of the employees' regular gross earnings, through the issuance of common shares of the Company, for all full-time employees. Compensation expense is recognized when shares are issued under the Plan and an equal amount is recorded as share capital. Shares are issued from Treasury to employees at the weighted average market price for the month immediately preceding the date of purchase of the Company's shares. The maximum number of common shares which can be issued under the plan is 500,000, of which 222,698 have been issued to December 31, 2006. Compensation costs of $108,098 (2005 - $87,012) have been expensed as part of stock-based compensation. c) Normal Course Issuer Bid Pursuant to Normal Course Issuer Bids, the Company acquired 612,300 (2005 - 222,900) common shares at an average price of $5.22 (2005 - $5.21) per share. The excess of cost of reacquisition over stated value of $2,516,691 (2005 - $916,929) has been charged against retained earnings. At December 31, 2006, a maximum of 3,316,500 common shares may be acquired by the Company until October 1, 2007 under the present Normal Course Issuer Bid. d) Stock-based Compensation Expense The fair value of stock options granted during 2006 was estimated on the dates of grant using the Black-Scholes option-pricing method with the following assumptions: Risk free interest rate of 3.79 to 4.26% (2005 - 3.12 to 3.48%) Expected life of options of 3.5 to 4.5 years (2005 - 3.5 to 4.5 years) Expected volatility of 81.24 to 87.52% (2005 - 67.47 to 70.69%) Expected dividend rate of 0% (2005 - 0%) Weighted average fair value per option granted of $3.54 (2005 - $2.25) Compensation costs of $1,727,873 (2005 - $556,870) have been expensed resulting in the recognition of $1,727,873 (2005 - $556,870) of contributed surplus during 2006. 8. Net income per share Net income per share has been calculated based on the weighted average number of common shares outstanding during the year of 38,652,164 (2005 - 38,755,860). A reconciliation of the denominators for the per share calculations is outlined below: ----------------------------- 2006 2005 ----------------------------- Basic weighted average shares 38,652,164 38,755,860 Effect of dilutive stock options 1,127,898 1,789,440 ----------------------------- Dilutive weighted average shares 39,780,062 40,545,300 ----------------------------- ----------------------------- The calculation of diluted net income per share does not include 1,165,000 (2005 - Nil) stock options, as the inclusion of these options would have been anti-dilutive. There is no change in the numerator in the calculation of diluted net income per share for either year. 9. Financial instruments a) Fair Values The fair values of the Company's accounts receivable and accounts payable and accrued liabilities approximate their carrying values due to the short-term nature of these financial instruments. The fair value of investments at December 31, 2006 is $13,895,591 (2005 - $8,503,467). The fair value of bank debt approximates its carrying value as it bears interest at market rates. b) Credit Risk The majority of the Company's accounts receivable are due from joint venture partners in the oil and gas industry and from purchasers of the Company's oil and natural gas production. The Company generally extends unsecured credit to these customers and therefore, the collection of accounts receivable may be affected by changes in economic or other conditions. Management believes the risk is mitigated by the size and reputation of the companies to which they extend credit. The Company has not experienced any credit loss in the collection of accounts receivable to date. c) Interest Rate Risk The Company is exposed to interest rate cash flow risk to the extent that its bank debt is at a floating rate of interest. d) Commodity Price Risk The nature of the Company's operations results in exposure to fluctuations in commodity prices. Management monitors commodity prices and initiates instruments to manage exposure to these risks when it deems appropriate. Currently, no such instruments have been initiated. e) Currency Risk The Company is exposed to foreign currency fluctuations as crude oil and natural gas prices are referenced to U.S. dollar denominated prices. 10. Commitments The Company has obligations under operating leases for office space and transportation obligations as follows: --------------------- 2007 $213,439 --------------------- 2008 170,648 --------------------- 2009 69,496 --------------------- 2010 69,496 --------------------- 2011 11,583 --------------------- 11. United States accounting principles and reporting The Company's consolidated financial statements have been prepared in Canadian dollars and in accordance with Canadian generally accepted accounting principles ("Canadian GAAP"), which in most respects conform to accounting principles generally accepted in the United States ("U.S. GAAP"). Significant differences between Canadian and U.S. GAAP are described in this note: a) Full Cost Accounting In accordance with U.S. GAAP, a ceiling test is applied to ensure the unamortized capitalized costs in each cost centre do not exceed the sum of the present value, discounted at 10 percent, of the estimated unescalated future net operating revenue from proved reserves plus unimpaired unproved property costs less future development costs, related production costs, asset retirement obligations and applicable taxes. Under Canadian GAAP, a similar ceiling test calculation is performed with the exception that future revenues are undiscounted and use forecast pricing to determine whether an impairment exists and are on a before tax basis. Any impairment amount is measured using the fair value of proved and probable reserves. Depletion under U.S. GAAP is calculated by reference to proved reserves estimated using constant prices and costs. Depletion under Canadian GAAP is calculated by reference to proved reserves estimated using future prices and costs. In computing consolidated net income for U.S. GAAP purposes, the Company recorded additional depletion in prior years as a result of the application of the ceiling test. These charges were not required under the Canadian GAAP ceiling test. As a result, the depletion base of unamortized capitalized costs is less for U.S. GAAP purposes. No ceiling test write-down is required under Canadian GAAP or U.S. GAAP as at December 31, 2006 and 2005. b) Income Taxes Canadian GAAP previously required the Company to record potential future taxes using the deferral method. However, the Canadian Institute of Chartered Accountants' (CICA) accounting standard is now similar to U.S. GAAP. Upon implementation of the new Canadian standard, retained earnings was decreased for temporary differences that had not previously been recognized. Under U.S. GAAP, these temporary differences would have already been reflected in property and equipment, therefore further differences in depletion and depreciation expense results in subsequent years. Under U.S. GAAP, enacted tax rates are used to calculate future taxes, whereas under Canadian GAAP, substantively enacted tax rates are used. c) Flow-through Shares U.S. GAAP requires the stated capital on flow-through share issuances to be equal to the estimated fair market value of the shares on the date of issue. The difference between the gross proceeds received on the issuance of the shares and the estimated fair market value of the shares is recorded as a liability ("the Premium"). Under Canadian GAAP, the gross proceeds received on flow-through share issuances are initially recorded as share capital. The Premium recorded as a current liability under U.S. GAAP for 2006 is $Nil (2005 - $Nil). When the tax deductions are renounced to subscribers, Canadian GAAP requires that the stated capital be reduced by and a future tax liability be recorded for the estimated future income taxes payable as a result of the renouncement. Under U.S. GAAP, when expenditures are incurred the future tax liability is recorded through a charge to income tax expense less the reversal of the Premium previously reported. d) Investments Under U.S. GAAP, the Company must classify investments in equity securities that have readily determinable fair values as either available for sale or held for trading. The Company's investments are classified as available for sale as they were not acquired and are not held principally for the purposes of selling them in the near term. These available for sale investments are revalued at the end of each period based on their fair values and any unrealized gain or loss is recorded, net of tax effects, as a component of other comprehensive income in the period. Additionally, U.S. GAAP requires the disclosure, as other comprehensive income, of changes in equity during the period from transactions and other events from non-owner sources. Canadian GAAP does not require similar disclosure. Comprehensive income for U.S. purposes arose on valuing the Company's investments at their fair market value. e) Variable Interest Entities The CICA issued a standard effective for all periods beginning on or after November 1, 2004. This standard requires variable interest entities to be consolidated by their primary beneficiary which is similar to the U.S. Financial Accounting Standards Board's (FASB) Interpretation No. 46 "Consolidation of Variable Interest Entities." At December 31, 2006, the Company did not have any interests in variable interest entities. f) Share-based Payments Under Canadian GAAP, compensation costs have been recognized in the consolidated financial statements based on the fair value of stock options granted to employees, officers and directors which follows similar recommendations under FASB Statement of Financial Accounting Standards (FAS) 123(R). Under FAS 123(R), entities are required to use the grant-date fair value of the award in measuring the cost of employee services received in exchange for an equity award of equity instruments. Compensation costs are required to be recognized over the requisite service period. Forfeitures must be estimated. For liability awards, entities are required to re-measure the fair value of the award at each reporting date up until the settlement date. Changes in fair value of liability awards during the requisite service period are required to be recognized as compensation costs over the vesting period. Compensation costs are not recognized for equity instruments for which employees do not render the requisite service. The Company elected to apply the modified prospective application in adopting FAS 123(R) on January 1, 2006. Under the modified prospective application, FAS 123(R) applies to new awards and to awards modified, repurchased or cancelled after January 1, 2006. The adoption of FAS 123(R) did not result in restatement of prior periods. g) Consolidated Statement of Cash Flows Under U.S. GAAP, separate subtotals within cash flow from operating activities are not presented. h) Consolidated Statement of Income The Company presents the gross amount of petroleum and natural gas sales and the gross amount of royalty expenses. Under U.S. GAAP, these items are combined and presented on a net basis. i) Recent Accounting Pronouncements i) Accounting Changes and Error Corrections Effective January 1, 2006 the Company adopted, for U.S. GAAP purposes, FAS 154 "Accounting Changes and Error Corrections, a replacement of Accounting Principles Board Opinion No. 20 and FAS 3". FAS 154 requires retrospective application of changes in accounting principle to prior period financial statements, unless it is impracticable to do so. Previously, Opinion 20 required that voluntary changes in accounting principles be recognized by including the cumulative effect of the new accounting principle in net income of the period of the change. This standard did not have an impact on the consolidated financial statements. ii) Uncertain Tax Positions As of January 1, 2007, the Company will be required to adopt, for U.S. GAAP purposes, FASB Interpretation No. 48 "Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109" which specifies how tax benefits for uncertain tax positions are to be recognized, measured, and derecognized in financial statements and requires certain disclosures of uncertain tax matters. The Company is currently assessing the impact of this interpretation. iii) Fair Value Measurements As of January 1, 2008, the Company is required to adopt, for U.S. GAAP purposes, FAS 157 "Fair Value Measurements". FAS 157 defines fair value, establishes a framework in measuring fair value and provides disclosure guidance. This statement is intended to increase the consistency and comparability of fair value measurements and eliminate different definitions of fair value under various U.S. standards. The Company is currently assessing the impact of this standard. iv) Financial Instruments On January 1, 2007, the Company is required to adopt, for Canadian GAAP purposes, CICA Handbook Section 3855, "Financial Instruments - Recognition and Measurement". This Section prescribes when a financial instrument is to be recognized on the balance sheet and at what amount. It also specifies how financial instrument gains and losses are to be presented. The Company is assessing the impact of this new standard on its consolidated financial statements. v) Hedges On January 1, 2007, the Company is required to adopt, for Canadian GAAP purposes, CICA Handbook Section 3865, "Hedges". This Section provides guidance on how to designate qualifying transactions as hedges for accounting purposes by specifying how hedge accounting is applied and what disclosures are necessary when it is applied. The Company is assessing the impact of this new standard on its consolidated financial statements. vi) Comprehensive Income On January 1, 2007, the Company is required to adopt, for Canadian GAAP purposes, CICA Handbook Section 1530, "Comprehensive Income". This Section introduces a new requirement to temporarily present certain gains and losses from changes in fair value outside net income (similar to U.S. standards). The Company is assessing the impact of this new standard on its consolidated financial statements. j) Summary of Significant Differences Between U.S. GAAP and Canadian GAAP i) Reconciliation of Consolidated Net Income Under Canadian GAAP to U.S. GAAP ------------------------------------------------------------------------- 2006 2005 ------------------------------------------------------------------------- Net income under Canadian GAAP $ 2,757,210 $ 10,202,438 U.S. GAAP adjustments Depletion, depreciation & accretion 266,454 286,161 Future tax expense on flow-through share renouncements - (73,024) Future income taxes (133,247) (529,616) ------------------------------------------------------------------------- Net income under U.S. GAAP $ 2,890,417 $ 9,885,959 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Net income per share ------------------------------------------------------------------------- Basic $ 0.07 $ 0.26 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Diluted $ 0.07 $ 0.24 ------------------------------------------------------------------------- ------------------------------------------------------------------------- ii) Statements of Comprehensive Income ------------------------------------------------------------------------- 2006 2005 ------------------------------------------------------------------------- Net income under U.S. GAAP $ 2,890,417 $ 9,885,959 Unrealized gain (loss) on investments, net of tax effect of $(690,146) (2005 - $36,333) 4,599,853 (172,359) ------------------------------------------------------------------------- Comprehensive income $ 7,490,270 $ 9,713,600 ------------------------------------------------------------------------- ------------------------------------------------------------------------- iii) Condensed Consolidated Balance Sheets ------------------------------------------------------------------------- 2006 2005 ------------------------------------------------------------------------- Canadian U.S. Canadian U.S. GAAP GAAP GAAP GAAP ------------------------------------------------------------------------- Current assets $ 12,590,893 $ 12,590,893 $ 15,458,139 $ 15,458,139 Investments 1,809,583 13,895,591 1,707,458 8,503,467 Property and equipment 127,425,551 126,253,266 114,901,195 113,462,456 ------------------------------------------------------------------------- $141,826,027 $152,739,750 $132,066,792 $137,424,062 ------------------------------------------------------------------------- ------------------------------------------------------------------------- Current liabilities $ 59,902,890 $ 59,902,890 $ 54,632,568 $ 54,632,568 Asset retirement obligations 5,104,300 5,104,300 3,473,144 3,473,144 Future income taxes 12,393,282 13,950,922 11,897,016 12,631,263 ------------------------------------------------------------------------- 77,400,472 78,985,112 70,002,728 70,736,975 ------------------------------------------------------------------------- Share capital 43,515,360 45,394,825 42,906,253 44,785,718 Contributed surplus 2,335,783 2,335,783 823,918 823,918 Retained earnings 18,574,412 15,838,353 18,333,893 15,464,627 Accumulated other comprehensive income - 10,212,677 - 5,612,824 ------------------------------------------------------------------------- 64,425,555 73,781,638 62,064,604 66,687,087 ------------------------------------------------------------------------- $141,826,027 $152,739,750 $132,066,792 $137,424,062 ------------------------------------------------------------------------- ------------------------------------------------------------------------- iv) Non-cash working capital under U.S. GAAP ----------------------------- 2006 2005 ----------------------------- Cash provided by (used for) Accounts receivable $ 2,826,962 $ (2,010,806) Prepaid expenses 45,600 669,027 Accounts payable and accrued liabilities (1,321,132) 3,549,166 Income taxes (8,546) 253,339 ----------------------------- Changes in non-cash working capital $ 1,542,884 $ 2,460,726 ----------------------------- ----------------------------- About Gentry Gentry is a Calgary-based oil and natural gas company active in the exploration, development and production of crude oil and natural gas in western Canada. The Company has grown primarily through aggressive exploration and development of its lands. Gentry trades on the TSX under the symbol "GNY" and currently has 38,849,110 common shares outstanding. Disclaimer: Statements in this press release may contain forward-looking statements, including management's assessment of future plans and operations and including expectations of future production and capital expenditures. These statements are based on current expectations that involved numerous risks and uncertainties, which will cause actual results to differ from those anticipated. These risks include, but are not limited to: the risks of the oil and gas industry (e.g. operational risks in exploration, development and production; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to production, costs and expenses, and health, safety and environmental risks), and price fluctuation. As a consequence, actual results may differ materially from those anticipated in the forward-looking statements.

For further information:

For further information: For Details, Contact: Hugh Ross, President &
Chief Executive Officer, (403) 264-6161; R. Gordon McKay, Chief Operating
Officer, (403) 264-6161; Ketan Panchmatia, Chief Financial Officer, (403)
264-6161; Roger Fullerton, Manager, Investor Relations, (952) 929-7243;  
www.gentryresources.com; gentry@gentryresources.com

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