Trinidad Energy Services Income Trust announces third quarter results - September 30, 2007



    TSX SYMBOL: TDG.UN

    CALGARY, Nov. 8 /CNW/ - The following is management's discussion and
analysis ("MD&A") concerning the operating and financial results for the three
and nine months ended September 30, 2007, and its outlook based on information
available as at November 2, 2007. The MD&A is based on the Trinidad Energy
Services Income Trust (the "Trust" or "Trinidad") consolidated financial
statements for the period ended September 30, 2007 which were prepared in
accordance with Canadian Generally Accepted Accounting Principles ("GAAP").
The MD&A should be read in conjunction with the audited consolidated financial
statements and MD&A of the Trust for the year ended December 31, 2006.
Additional information is available on the Trust's website
(www.trinidaddrilling.com) and all previous public filings, including the most
recently filed Annual Report and Annual Information Form, are available
through SEDAR (www.sedar.com).

    
    FINANCIAL HIGHLIGHTS

    (thousands except unit and per unit data - Unaudited)

                                Three months ended         Nine months ended
                                   September 30,             September 30,
                                 2007         2006         2007         2006
    -------------------------------------------------------------------------
    Revenue                   162,183      150,625      483,888      418,109
    Gross margin(1)            75,150       66,878      217,554      194,545
    EBITDA(1)                  54,299       54,576      161,390      150,342
      Per unit (diluted)         0.64         0.64         1.56         1.78
    EBITDA before unit
     based compensation(1)     54,807       55,316      163,344      155,665
      Per unit (diluted)         0.64         0.65         1.58         1.84
    Funds flow before
     change in non-cash
     working capital(1)        46,456       48,973      142,619      142,224
      Per unit (diluted)         0.55         0.57         1.42         1.68
    Distributions paid
     and declared              28,843       28,640       86,416       76,846
      Per unit (basic)           0.34         0.34         1.03         0.93
    Payout ratio(2)                 -            -          61%          54%
    Net earnings               15,043       31,573       61,627       92,369
      Per unit (basic)           0.18         0.38         0.73         1.11
      Per unit (diluted)         0.18         0.37         0.65         1.09
    Net earnings before unit
     based compensation        15,551       32,313       63,581       97,692
      Per unit (diluted)         0.18         0.38         0.66         1.15
    Units outstanding -
     basic (weighted
     average)(3)           83,989,145   83,705,299   83,917,739   82,851,643
    Units outstanding -
     diluted (weighted
     average)(3)           85,140,262   85,316,897  103,605,851   84,651,979
    -------------------------------------------------------------------------
    (1) Readers are cautioned that gross margin, EBITDA and funds flow before
    change in non-cash working capital and the related per unit information
    do not have a standardized meaning prescribed by GAAP and therefore may
    not be comparable to similar measures presented by other issuers;
    however, the Trust does compute gross margin, EBITDA and funds flow
    before change in non-cash working capital on a consistent basis for each
    reporting period. EBITDA refers to earnings of the Trust before interest,
    taxes, depreciation and gain or loss on investment in long-term assets;
    gross margin refers to revenue less operating expenses; funds flow before
    change in non-cash working capital refers to the amount of cash that is
    expected to be available for distribution to unitholders.
    (2) Payout ratio is calculated as distributions paid and declared divided
    by funds flow before changes in non-cash working capital and is only
    provided on a year-to-date basis.
    (3) Basic units include the weighted average units outstanding and units
    issuable upon exchange of outstanding exchangeable shares. Diluted units
    include the weighted average units outstanding, units issuable upon
    exchange of outstanding exchangeable shares and the dilutive impact, if
    any, of the deemed conversion of convertible debentures and units
    issuable pursuant to the Trust Unit Rights Incentive Plan. Interest
    expense incurred on the dilutive convertible debentures is added back to
    net earnings and to funds flow before change in non-cash working capital
    for the diluted per unit calculation.


    OPERATING HIGHLIGHTS

    (Unaudited)                 Three months ended         Nine months ended
                                   September 30,             September 30,
                                 2007         2006         2007         2006
    -------------------------------------------------------------------------
    Land Drilling Market
    Operating days
      Canada                    2,718        3,358        7,699        9,368
      United States             3,305        1,891        8,713        4,941
    Rate per drilling
     day (CDN $)
      Canada                   21,746       23,083       24,156       23,469
      United States            23,265       24,042       24,460       23,341
    Utilization rate
      Canada                      47%          64%          45%          62%
      United States               85%          85%          86%          84%
    CAODC industry average        39%          57%          38%          58%
    Number of drilling rigs
      Canada                       63           59           63           59
      United States                43           26           43           26
    Utilization rate for
     service rigs                 46%          68%          35%          61%
    Number of service rigs         20           18           20           18
    Number of coring and
     surface casing rigs           20           17           20           17

    Barge Drilling Market
    Operating days                352            -          352            -
    Rate per drilling day
     (CDN $)                   51,904            -       51,904            -
    Utilization rate             100%            -         100%            -
    Number of drilling rigs         1            -            1            -
    Number of drilling rigs
     under Bareboat Charter
     agreements                     3            -            3            -
    -------------------------------------------------------------------------
    

    FORWARD-LOOKING STATEMENTS

    The MD&A contains certain forward-looking statements relating to the
Trust's plans, strategies, objectives, expectations and intentions.
Expressions such as "anticipate", "expect", "project", "believe", "estimate",
and "forecast" should be used to identify these forward-looking statements.
The Trust believes that the expressions reflected in those forward-looking
statements are reasonable; however, such statements are subject to a number of
known and unknown risks, uncertainties and other factors that may cause actual
results to differ materially from those anticipated in our forward-looking
statements. These statements speak only as of the date of the MD&A and the
Trust does not intend, and does not assume any obligation, to update these
forward-looking statements.

    NON-GAAP MEASURES

    This MD&A contains references to the term "funds flow before change in
non-cash working capital" to refer to the amount of cash that is expected to
be available for distribution to unitholders; the term "EBITDA" to refer to
earnings of the Trust before interest, taxes, depreciation and gain or loss on
investment in long-term assets; the term "gross margin" to refer to revenue
less operating expenses, which the Trust believes are measures followed by the
investment community and therefore provide useful information. The terms
"funds flow before change in non-cash working capital", "EBITDA", "gross
margin" and associated per unit data are not measures recognized by GAAP and
therefore do not have standardized meaning. Accordingly, these measures may
not be comparable to similar measures presented by other companies. However,
the Trust computes "funds flow before change in non-cash working capital",
"EBITDA" and "gross margin" on a consistent basis for each reporting period.

    OVERVIEW

    Through geographical disbursement and expansion of service lines, the
Trust has sustained unitholder value, secured distributions and counteracted
the low industry fundamentals in the Canadian drilling industry. In the third
quarter, revenues from the Trust's operations in the United States exceeded
the Canadian operations by 23.8% with utilization rates consistently at or
above 85% with stable day rates. Through accretive acquisitions and the
substantial completion of the rig construction program, the US rig count has
reached a total of 43 drillings rigs, one barge rig and three barge rigs under
the Bareboat Charter Agreements ("Bareboat Charter" or "Charter"). Throughout
2006 and 2007 the Trust has successfully deployed 31 rigs under the rig
construction program, of which 17 were released into the US, with the
remaining three rigs substantially complete and ready for deployment into the
US in the fourth quarter of 2007, further enhancing the strength of the US
division.
    On July 5, 2007 the Trust acquired the assets of US-based Drilling
Productivity Realized, L.L.C., P.C. Axxis, L.L.C., DPR International, L.L.C.
and DPR Rentals, L.L.C. (collectively, "Axxis") for $148.1 million. The assets
acquired include four land based drilling rigs and one barge drilling rig,
together with related inventory, crew boats and spare parts. Furthermore, the
Trust has assumed the remaining commitments on a second barge drilling rig
currently under construction, expected to be deployed in early 2008. This
acquisition has complemented the current US rig fleet with the addition of
four technologically advanced rigs with the capability to drill at deeper
depths. Additionally, the Trust gained entrance into the niche barge market
and adopted industry expertise, which has positioned the Trust favourably to
capitalize on future opportunities. Concurrent with the acquisition of Axxis
the Trust closed a $325.0 million convertible unsecured subordinated debenture
financing to fund the acquisition. The convertible debentures have a face
value of $1,000, coupon rate of 7.75%, mature July 31, 2012 with interest
being paid semi-annually on June 30 and December 31. The Trust has the option
to redeem the debentures in whole or in part at a redemption price of $1,000
after December 31, 2010 and before their maturity date. On redemption or
maturity, the Trust may elect to satisfy its obligation to repay the principal
by issuing Trust units. Proceeds in excess of the purchase price were used to
pay down the Trust's revolving debt facility.
    Natural gas drilling in the Canadian market has continued to slow in
light of weak commodity prices and high storage levels. Pursuant to the "Our
Fair Share" report issued by the Alberta government, the province's new
royalty system has caused many oil and gas producers to consider curtailing
activity in Alberta. These factors have led to further volatility in the
Canadian market; however, the Trust has continued to perform better than
industry averages by targeting the deeper drilling market and through its
long-term take-or-pay contracts has found stability in the current market.
Through these efforts, the Trust has exceeded industry utilization by 20.5%
for the third quarter of 2007 and increased day rates by 2.9% on a
year-to-date basis. However, due to increased competition and capacity
available in the industry, pricing in the third quarter experienced a 5.8%
decrease from the comparable quarter of 2006.
    Despite the reductions in the Canadian market, the Trust's US expansion
and resulting diversification of funds flow leaves it well positioned to ride
out the volatility in the market. During this time of instability in the
market, when many other energy service companies are struggling to maintain
positive funds flow and sustain distribution levels, the Trust has continued
to exceed the prior year's results and meet market expectations. Growth and
sustainability continue to be a primary focus and accretive growth for our
unitholders remains the Trust's primary goal.

    
    QUARTERLY ANALYSIS             2007
                          Q3        Q2      Q1
    ------------------------------------------------
    Financial Highlights
    (millions except per unit data - Unaudited)

    Revenue               162.2    115.5    206.2
    Gross margin(1)        75.2     46.5     95.9

    Net earnings           15.0      4.7     41.9
    Depreciation and
     amortization          20.2     14.8     18.3
    (Gain) loss on sale
     of assets                -      0.1      0.1
    Unit based
     compensation           0.5      0.7      0.8
    Future income tax
     expense (recovery)     3.3     (3.1)    10.2
    Effective interest on
     financing costs        1.1      0.4      0.3
    Non-cash interest
     expense on debentures  1.0        -        -
    Unrealized foreign
     exchange loss (gain)   5.3      5.8      1.2
    Other                     -        -        -
    ------------------------------------------------
    Funds flow before
     change in non-cash
     working capital(1)    46.4     23.4     72.8

    Earnings per unit
     (diluted)             0.18     0.05     0.49
    Funds flow before
     change in non-cash
     working capital per
     unit (diluted)(1)     0.55     0.27     0.86

    Operating Highlights
    Land Drilling Market
    Operating days
      Canada              2,718    1,165    3,817
      United States       3,305    2,944    2,464
    Rate per drilling
     day (CDN $)
      Canada             21,746   23,527   26,063
      United States      23,265   24,927   25,506
    Utilization rate
      Canada                47%      20%      69%
      United States         85%      88%      85%
    CAODC industry
     average                39%      17%      59%
    Number of drilling
     rigs
      Canada                 63       64       63
      United States          43       38       37
    Utilization rate for
     service rigs           46%      23%      73%
    Number of service
     rigs                    20       21       20
    Number of coring
     and surface casing
     rigs                    20       17       17

    Barge Drilling Market
    Operating days          352        -        -
    Rate per drilling
     day (CDN $)         51,904        -        -
    Utilization rate       100%        -        -
    Number of drilling
     rigs                     1        -        -
    Number of drilling
     rigs under Bareboat
      Charter agreements      3        -        -
    ------------------------------------------------



    QUARTERLY ANALYSIS                       2006                    2005
                                  Q4      Q3      Q2      Q1      Q4      Q3
    -------------------------------------------------------------------------
    Financial Highlights
    (millions except per unit data - Unaudited)

    Revenue                    161.9   150.6   104.5   162.9   106.4    75.3
    Gross margin(1)             74.9    66.9    43.1    84.7    46.4    31.8

    Net earnings                31.3    31.6    20.8    40.0    19.4    13.8
    Depreciation and
     amortization               15.4    14.0     9.7    13.1     9.3     8.0
    (Gain) loss on sale
     of assets                   0.1    (2.0)      -       -     0.2     0.1
    Unit based
     compensation                1.8     0.7     0.8     3.8     0.6     0.5
    Future income tax
     expense (recovery)          6.2     4.6    (8.7)   13.9     5.5     1.7
    Effective interest on
     financing costs               -       -       -       -       -       -
    Non-cash interest
     expense on debentures         -       -       -       -       -       -
    Unrealized foreign
     exchange loss (gain)       (0.1)      -     0.2    (0.2)      -       -
    Other                          -     0.1    (0.3)    0.1       -       -
    -------------------------------------------------------------------------
    Funds flow before
     change in non-cash
     working capital(1)         54.7    49.0    22.5    70.7    35.0    24.1

    Earnings per unit
     (diluted)                  0.37    0.38    0.24    0.48    0.29    0.21
    Funds flow before
     change in non-cash
     working capital per
     unit (diluted)(1)          0.65    0.57    0.26    0.84    0.51    0.37

    Operating Highlights
    Land Drilling Market
    Operating days
      Canada                   3,163   3,358   1,826   4,184   3,795   3,487
      United States            2,105   1,891   1,603   1,447     235      37
    Rate per drilling
     day (CDN $)
      Canada                  26,328  23,083  23,927  23,579  23,280  19,196
      United States           24,621  24,042  24,089  21,596  19,245  20,122
    Utilization rate
      Canada                     61%     64%     36%     86%     78%     73%
      United States              85%     85%     82%     85%     83%    100%
    CAODC industry
     average                     47%     57%     34%     81%     71%     63%
    Number of drilling
     rigs
      Canada                      60      59      57      56      54      52
      United States               31      26      22      21      17       1
    Utilization rate for
     service rigs                64%     68%     31%     85%     67%     61%
    Number of service
     rigs                         18      18      17      17      16      16
    Number of coring
     and surface casing
     rigs                         17      17      17      17      17      18

    Barge Drilling Market
    Operating days                 -       -       -       -       -       -
    Rate per drilling
     day (CDN $)                   -       -       -       -       -       -
    Utilization rate               -       -       -       -       -       -
    Number of drilling
     rigs                          -       -       -       -       -       -
    Number of drilling
     rigs under Bareboat
      Charter agreements           -       -       -       -       -       -
    -------------------------------------------------------------------------
    (1) Readers are cautioned that gross margin and funds flow before change
    in non-cash working capital and per unit information do not have a
    standardized meaning prescribed by GAAP; however, the Trust does compute
    gross margin and funds flow before change in non-cash working capital and
    the per unit information on a consistent basis for each reporting period.


    RESULTS FROM OPERATIONS


    Canadian Drilling Operations

    (thousands except
    percent data and        Three months ended         Nine months ended
    operating data -           September 30,              September 30,
    Unaudited)            2007     2006   % Change   2007    2006   % Change
    -------------------------------------------------------------------------
    Revenue              67,656   87,875    (23.0) 233,991  267,892    (12.7)
    Operating expense    39,390   48,524    (18.8) 137,461  144,934     (5.2)
                       ------------------------------------------------------
    Gross margin         28,266   39,351    (28.2)  96,530  122,958    (21.5)
                       ------------------------------------------------------
    Gross margin
     percentage           41.8%    44.8%     (6.7)   41.3%    45.9%    (10.0)

    Operating days -
     drilling             2,718    3,358    (19.1)   7,699    9,368    (17.8)
    Rate per drilling
     day (CDN $)         21,746   23,083     (5.8)  24,156   23,469      2.9
    Utilization rate -
     drilling               47%      64%    (26.6)     45%      62%    (27.4)
    CAODC industry
     average                39%      57%    (31.6)     38%      58%    (34.5)
    Number of drilling
     rigs                    63       59      6.8       63       59      6.8

    Utilization rate
     - well servicing       46%      68%    (32.4)     35%      61%    (42.6)
    Number of service rigs   20       18     11.1       20       18     11.1
    Number of coring
     and surface casing
     rigs                    20       17     17.6       20       17     17.6

    The Canadian drilling market continued throughout the third quarter to be
impacted by the slower market conditions prevalent across the industry as
reduced utilization levels and downward pressures on day rates continued to
impact the Trust's Canadian drilling fleet. Industry utilization rates
declined by 31.6% from the comparable quarter in 2006 from 57% to 39% and on a
year-to-date basis dropped to 38%, a decrease of 34.5% from the prior year.
The Trust's Canadian drilling operations were impacted by this downward trend;
however, its focus on the deeper drilling market and long-term contracts did
shelter operations from the full reduction experienced in the drilling market,
allowing Trinidad to continue to exceed industry's average utilization by
20.5% for the quarter and 18.4% year-to-date. Growth in the Trust's drilling
fleet from 59 rigs at September 30, 2006 to 63 rigs at September 30, 2007
provided an increased asset base, slightly offsetting the impact of the
reduced utilization rates on operating days. However, quarter-over-quarter and
on a year-to-date basis these reductions were still present.
    Quarter-over-quarter revenue declined by 23.0% from $87.9 million in 2006
to $67.7 million in 2007 and on a year-to-date basis was reduced by
$33.9 million to $234.0 million. The Trust's drilling division contributed to
the bulk of the decline as the largest component of the Canadian operations.
Slight reductions were also seen in the well servicing and surface casing and
coring divisions; however, oil sands activity and operators focused on
lengthening the production of current wells in light of reductions in their
capital budget lessened the impact of the slower market in these sectors.
Additionally, increased competition in the market due to the reduced activity
levels prompted downward market pressures on day rates throughout the period,
ultimately adversely impacting both revenue and margins. These slower market
conditions continued to adversely impact day rates as drilling contractors
competed for less work which reduced margin levels from 45.9% in 2006 to 41.3%
in 2007, reducing the overall gross margin obtained in the Canadian
operations.

    United States Drilling Operations

    (thousands except
    percent and             Three months ended         Nine months ended
    operating data -           September 30,              September 30,
    Unaudited)            2007     2006   % Change   2007    2006    % Change
    -------------------------------------------------------------------------
    Revenue              83,771   45,473     84.2  220,005  115,337     90.7
    Operating expense    39,700   20,265     95.9  105,254   50,215    109.6
                       ------------------------------------------------------
    Gross margin         44,071   25,208     74.8  114,751   65,122     76.2
                       ------------------------------------------------------
    Gross margin
     percentage           52.6%    55.4%     (5.1)   52.2%    56.5%     (7.6)

    Land drilling rigs
    Operating days
     - drilling           3,305    1,891     74.8    8,713    4,941     76.3
    Rate per drilling
     day (CDN $)         23,265   24,042     (3.2)  24,460   23,341      4.8
    Utilization rate -
     drilling               85%      85%        -      86%      84%      2.4
    Number of drilling
     rigs                    43       26     65.4       43       26     65.4

    Barge drilling rigs
    Operating days -
     drilling               352        -    100.0      352         -   100.0
    Rate per drilling
     day (CDN $)         51,904        -    100.0   51,904         -   100.0
    Utilization rate -
     drilling              100%        -    100.0     100%         -   100.0
    Number of drilling
     rigs                     1        -    100.0        1         -   100.0
    Number of drilling
     rigs under Bareboat
     Charter agreements       3        -    100.0        3         -   100.0
    

    The US drilling operations have become a key component in the overall
success of the Trust, providing continued growth and an increasing source of
funds flow. Through growth in this sector of the business, the Trust has
managed to sustain unitholder value, secure distributions and counteract the
volatile Canadian market. Under the rig construction program 13 rigs have been
deployed since September 30, 2006, all backed by take-or-pay contracts with
excellent utilization levels and stable day rates. To further complement the
construction program, the acquisition of the Axxis assets has resulted in the
addition of four more land rigs with deep depth ratings and the latest
technology. On a year-to-date basis, the Trust has managed to optimize the
benefits of these additional rigs through a 4.8% increase in day rates and
2.4% increase in utilization on a substantially larger fleet of drilling rigs,
resulting in an overall increase in revenues of 90.7% from the prior year.
Revenue increased 84.2% quarter-over-quarter and the Trust maintained
utilization at 85% for the quarter with a 3.2% decrease in day rates primarily
due to slightly lower day rates that are being honoured on existing contracts
on the four acquired Axxis land rigs. These contracts will be completed within
the next 12 months, at which point day rates will be re-negotiated and will
become more reflective of the rest of the US fleet.
    In addition, the Trust entered the offshore drilling market in the third
quarter with the acquisition of one barge drilling rig from Axxis and the
assumption of three Bareboat Charter agreements (see "Bareboat Charters" for
further details). Entrance into the barge market has provided $5.5 million in
incremental revenue, including $1.0 million net earned from the Bareboat
Charter, for the period ended September 30, 2007 due to exceptional day rates
of $51,904 per day and a utilization level of 100%. The barge rigs have added
geographical diversification to the asset base and have provided the Trust
with significant opportunities to grow in other jurisdictions.
    Operating expenses grew as a result of the overall growth in revenue
throughout the quarter from $20.3 million in 2006 to $39.7 million in 2007
with an overall decline in operating margins from 55.4% to 52.6%. An increase
in year-to-date operating expenses also produced declining margins from 56.5%
in 2006 to 52.2% in 2007. Despite an exceptionally high margin on the barge
rig of 71.8% and margins of 55.3% on the four Axxis land rigs, the incremental
costs associated with new rig deployments in the existing US division have
resulted in the decline in margins. Start-up costs for new rigs include costs
incurred to prepare them for the field as well as additional training costs
for the crews once the rigs are fully operational. As the number of new rigs
being deployed declines and the rig construction program is completed, margin
levels should increase to levels comparable with 2006.

    Bareboat Charters

    As a part of the Axxis acquisition the Trust entered into an Assignment
Agreement in which the contracts to operate three barge rigs were transferred
to the Trust. Under the Bareboat Charters, the Trust is committed to operate
the rigs, for a three year period, on behalf of a third party. In turn, as
owners of the rigs, this third party is entitled to receive 25% of the Net
Operating Revenues and 50% of the Net Margin earned under each Charter. Under
the original agreement any earnings in excess of this payment were to be
retained as compensation for the operation of the barge rigs; however, as part
of the purchase agreement the Trust committed to pay the former owners of
Axxis US$12.5 million per year for the next three consecutive years, of which
one-third of the payment, or US$4.2 million, shall be attributable to each of
the three Bareboat Charters and is recorded as an intangible asset and
deferred purchase price on the acquisition. The Trust has reported all
transactions pertaining to the Bareboat Charters on a net basis in accordance
with EIC 123, Reporting Revenue Gross as a Principal versus Net as an Agent,
for purposes of financial statement disclosure as the Trust does not bear the
significant risks and rewards of the arrangement nor does it absorb the
associated credit risk or asset risk. For the three and nine months ended
September 30, 2007, the Trust recorded $1.0 million in net revenue pertaining
to the Bareboat Charters due to better than expected day rates.

    
    Construction Operations

    (thousands except
    percent data -         Three months ended         Nine months ended
    Unaudited)                 September 30,              September 30,
                          2007     2006   % Change   2007    2006    % Change
    -------------------------------------------------------------------------

    Revenue(1)           19,507   31,040    (37.2)  76,700   75,935      1.0
    Operating expense(1) 16,694   28,721    (41.9)  70,427   69,470      1.4
                       ------------------------------------------------------
    Gross margin          2,813    2,319     21.3    6,273    6,465     (3.0)
                       ------------------------------------------------------
    Gross margin
     percentage           14.4%     7.5%     92.0     8.2%     8.5%     (3.5)

    (1) Includes inter-segment revenue and operating expenses of $8.8 million
    and $13.8 million for the three months ended September 30, 2007 and 2006,
    respectively and $46.8 million and $41.1 million for the nine months
    ended September 30, 2007 and 2006, respectively.
    

    On March 16, 2006 the Trust acquired Mastco Derrick Service Ltd.
("Mastco") to facilitate the construction of 10 rigs committed by the Canadian
drilling operations and four rigs committed by the US drilling operations,
which enhanced control over the timing and construction of these rigs.
Throughout 2006 and 2007, Mastco's main focus was on completing this rig
construction program resulting in the deployment of all 10 Canadian rigs and
one US rig as of September 30, 2007, with only 3 rigs left for deployment in
the US. Additionally, as the construction program nears completion, Mastco's
capacity is also being utilized to complete inter-segment recertification and
repair work. This focus on supporting the Trust's drilling operations resulted
in Mastco recognizing inter-segment revenue and operating expenses of
$8.8 million and $13.8 million for the three months ended September 30, 2007
and 2006, respectively and $46.8 million and $41.1 million for the nine months
ended September 30, 2007 and 2006.
    Third quarter revenues decreased by 37.2% from the prior year due to
substantial completion of the rig program while revenues for the nine months
ended September 30, 2007 remained relatively stable as the incremental two and
half months of revenue in 2007 offset the decreased activity in the third
quarter. A decrease in third party revenue also contributed to the decline, at
$29.9 million for the nine months ended September 30, 2007 generating margins
of 21.0% compared to the prior year's $34.8 million at an 18.6% margin. The
focus on creating internal efficiencies by completing inter-segment work has
resulted in a decrease in third party contracts.

    
    GENERAL AND ADMINISTRATIVE EXPENSE

    (thousands except
    percent data -           Three months ended         Nine months ended
    Unaudited)                 September 30,              September 30,
                          2007     2006   % Change   2007    2006    % Change
    -------------------------------------------------------------------------
    General and
     administrative
     expenses            14,949   11,607     28.8   41,927   37,835     10.8
    % of revenue           9.2%     7.7%              8.7%     9.0%
    

    Changes in the composition of the Trust's business through the
acquisition of Axxis and the expansion of the US drilling operations have
resulted in an increase in general and administrative expenses
quarter-over-quarter and year-to-date. From a quarterly perspective, the 28.8%
increase is primarily a result of incremental general and administrative
expenses from the addition of Axxis as well as property taxes payable on rigs
operating in the US. As of September 30, 2007, the Trust has assessed $3.4
million of property taxes of which $1.6 million was recorded in the current
quarter. Property taxes of this nature are assessed based on the value and
location of rigs on the first day of each year; hence the balance in the prior
year was minimal given that the Trust's rig count in the US was substantially
lower in the prior year.
    The Trust continues to focus on maintaining conservative expenditure
levels to ensure accretive growth for unitholders by creating internal
efficiencies, centralizing certain required functions and integrating its
management team. As a result of this focus, year-to-date general and
administrative expenses as a percentage of revenue decreased from 9.0% to
8.7%.

    
    INTEREST

                            Three months ended         Nine months ended
    (thousands -               September 30,              September 30,
    Unaudited)            2007     2006   % Change   2007    2006    % Change
    -------------------------------------------------------------------------
    Interest on
     bank debt            6,749    6,388      5.7   24,107   13,740     75.4
    Effective interest
     on deferred
     financing costs        425        -    100.0    1,177        -    100.0
                       ------------------------------------------------------
                          7,174    6,388     12.3   25,284   13,740     84.0
                       ------------------------------------------------------

    Interest on
     convertible
     debentures           6,621        -    100.0    6,621        -    100.0
    Effective interest
     on deferred
     financing costs        654        -    100.0      654        -    100.0
    Accretion of
     convertible
     debenture            1,027        -    100.0    1,027        -    100.0
                       ------------------------------------------------------
                          8,302        -    100.0    8,302        -    100.0
                       ------------------------------------------------------
    

    The Trust fulfilled a number of capital initiatives in the current year
including the acquisition of Axxis, the substantial completion of the rig
construction program and the purchase of three additional rigs which increased
the asset base of the coring and surface casing division. Financing this
extensive capital program was critical in order to realize the benefits of the
expanded breadth and depth of the Trust's drilling fleet. This was facilitated
in April 2006 when the Trust closed a new debt facility, which increased the
principal available from $250.0 million to a debt facility with total Canadian
dollar equivalent capacity of approximately $474.4 million, excluding a
temporary increase of $35.0 million which was obtained in the second quarter
of 2007 and fully repaid in July 2007. The debt facility encompasses both US
and Canadian term and revolving facilities which bear interest at the LIBOR
and Bankers Acceptance ("BA") rates, respectively, plus a spread whereas under
the original agreement, the Trust was obligated to pay interest at a fixed
borrowing rate. In order to mitigate the risk of fluctuations in floating
interest rates on the debt facility, Trinidad entered into an interest rate
swap at the beginning of the third quarter of 2006 on 50% of the outstanding
Canadian and US term facilities. The net settlement of the interest rate swaps
increased interest expense for the quarter and on a year-to-date basis by
$0.2 million and $0.7 million, respectively. This effort to expand service
lines and further enhance existing ones resulted in the Trust increasing debt
levels throughout 2006 and into 2007 which increased interest expense on the
bank facility by $10.4 million on a year-to-date basis and $0.4 million
quarter-over-quarter.
    Effective July 5, 2007, the Trust closed the issuance of $325.0 million
convertible debentures in order to facilitate the acquisition of Axxis.
Proceeds in excess of the purchase price were used to repay $187.8 million of
the Canadian revolving facility which significantly reduced the debt drawn
under the facility. As at September 30, 2007 the combined debt facility
balance of approximately $327.2 million was comparable to the balance at
September 30, 2006, explaining the small variance in interest expense
quarter-over-quarter.
    Interest on the convertible debentures is paid semi-annually at a coupon
rate of 7.75% and for the three and nine months ended, the Trust recorded
associated interest expense of $6.6 million. The fixed interest rate on the
convertible debentures will reduce the Trust's exposure to interest rate
fluctuations and further enhance funds flow stability.
    Non-cash interest expense represents $2.1 million of total interest
expense on a quarterly basis and $2.9 million on a year-to-date basis. The
Trust's adoption of CICA 3855, Financial Instruments - Recognition and
Measurement, requires the amortization of transaction costs that were
previously classified as amortization expense to be recorded as part of
interest expense under the effective interest method. The application of this
method resulted in a $1.1 million and $1.8 million increase in interest
expense for the three and nine months ended September 30, 2007, respectively.
Furthermore, the convertible debt balance accretes over time to the amount
owing at maturity and such increases to the debt balance have resulted in a
$1.0 million increase in non-cash interest expense for the period.

    
    UNIT BASED COMPENSATION

                             Three months ended         Nine months ended
    (thousands -               September 30,              September 30,
    Unaudited)            2007     2006   % Change   2007    2006    % Change
    -------------------------------------------------------------------------
    Unit based
     compensation           508      740    (31.4)   1,954    5,323    (63.3)

    The Trust has established a Trust Unit Rights Incentive Plan to assist
directors, officers, employees and consultants of the Trust and its affiliates
to participate in the growth and development of the Trust and uses the fair
value method to calculate compensation expense associated with rights granted
under the Plan. This compensation expense is recognized into earnings over the
vesting period of the rights granted with a corresponding increase in
contributed surplus. Unit based compensation for the nine months ended
September 30, 2007 decreased by $3.4 million from the comparable period in
2006 due to the granting of 2.3 million options in the first quarter of 2006
in comparison with 0.6 million options in 2007. Unit based compensation for
the three months ended September 30, 2007 experienced a minimal change in
comparison to the prior quarter, as no option grants took place in either the
third quarter of 2006 or 2007.

    FOREIGN EXCHANGE (GAIN) LOSS

                             Three months ended         Nine months ended
    (thousands -               September 30,              September 30,
    Unaudited)            2007     2006   % Change   2007    2006    % Change
    -------------------------------------------------------------------------
    Foreign exchange
     loss (gain)          5,394      (45) 12,086.7  12,283    1,045  1,075.4

    Foreign exchange loss increased significantly both quarter-over-quarter
and year-to-date primarily due to unrealized losses in the Canadian entity on
US denominated intercompany balances. The intercompany debt was minimal in
2006 as the US operations drew on the US portion of the debt facility to fund
the capital requirements under the rig construction program. However, in early
2007 Trinidad announced the construction of an additional five US rigs which
were not contemplated in the original debt facility and therefore required
funding through the Canadian revolver. This resulted in the intercompany
balance increasing significantly in 2007 which, when coupled with the
continuing weakness of the US dollar created unrealized losses on the
intercompany balance. The loss corresponds to an unrealized gain in the US
subsidiary that is capitalized in the cumulative translation adjustment which
is reflected in equity as part of accumulated other comprehensive income.

    DEPRECIATION AND AMORTIZATION

                             Three months ended         Nine months ended
    (thousands -               September 30,              September 30,
    Unaudited)            2007     2006   % Change   2007    2006    % Change
    -------------------------------------------------------------------------
    Depreciation         20,190   13,695     47.4   53,279   35,851     48.6
    Amortization              -      281   (100.0)       -      936   (100.0)
    Loss (gain) on sale
     of assets               31   (2,032)   101.5      238   (2,002)   111.9
    

    Increases in depreciation of $6.5 million quarter-over-quarter and
$17.4 million year-over-year have resulted from changes in the composition of
Trinidad's asset base as a result of the current rig construction program,
growth in the Trust's drilling fleet and the acquisition of Axxis. These
growth initiatives increased the land drilling fleet by 32 drilling rigs
throughout 2006 and into 2007, many of these rigs being the most
technologically advanced in the industry. The higher capital costs on these
rigs together with an increased number of drilling days in comparison with
2006 have increased depreciation expense on both a quarterly and year-to-date
basis. In addition, the acquisition of the assets of Axxis increased the
Trust's fleet of land drilling rigs by four and added a barge rig contributing
approximately $1.7 million in depreciation for the third quarter of 2007. The
US operations as a whole contributed $30.8 million to depreciation expense for
2007, compared to only $14.2 million in 2006, an increase of 116.9%, which
represents a significant portion of the increase year-over-year. As the
majority of the growth initiatives over the last year have been focused on the
US operations and the market continues to thrive, it is expected that this
trend will continue.
    Depreciation rates per day for US operations also rose from $2,878 to
$3,527 on a year-to-date basis and $3,086 to $3,615 quarter-over-quarter as a
result of the higher capital costs associated with the newly released rigs.
Additionally, depreciation rates per day for Canadian operations have risen by
18% to $2,929 for 2007 and on a quarterly basis have increased to $3,033 from
$2,424; however, the decline in operating days compared to 2006 has resulted
in only a marginal increase in the Canadian depreciation expense for the
period.
    Due to the adoption of CICA 3855, Financial Instruments - Recognition and
Measurement, transaction costs that were previously classified as amortization
expense are now recorded as part of interest expense under the effective
interest method. The application of this method resulted in a $0.3 million and
$0.9 million decrease in amortization for the three and nine months ended
September 30, 2007, respectively.

    
    INCOME TAXES

                             Three months ended         Nine months ended
    (thousands -               September 30,              September 30,
    Unaudited)            2007     2006   % Change   2007    2006    % Change
    -------------------------------------------------------------------------
    Current tax expense
     (recovery)             299       36    730.6    2,283     (389)   686.9
    Future tax expense    3,260    4,635    (29.7)  10,377    9,837      5.5
    

    Effective June 12, 2007, the Canadian government substantively enacted
Bill C-52 and on June 22, 2007 the bill received Royal Assent. The new
legislation has resulted in a "Distribution Tax" of 18.5% on distributions of
publicly traded income trusts and limited partnerships (specified investment
flow-through entities, or "SIFTs") plus the "provincial SIFT tax factor" of
13% and reduces the general corporate tax rate to 18.5% starting in 2011.
Under Canadian GAAP the SIFT legislation, now enacted, will trigger the
recognition of future income tax assets and liabilities based on temporary
differences expected to reverse after the date that the changes take effect.
The Trust assessed the impact of the SIFT legislation and has recorded a
future income tax impact of $0.5 million pertaining to financing costs on the
issuance of the convertible debentures.
    Year-to-date and quarter-to-date future income tax expense increased by
5.5% and decreased by 29.7%, respectively, primarily due to the acquisition of
Axxis assets resulting in a substantial increase in the tax pools of the US
division and large temporary differences between book-to-tax depreciation.
This factor was offset by future income tax recoveries in the Canadian
divisions, as weak industry fundamentals have resulted in lower earnings on
both a quarterly and year-to-date basis. Furthermore, the construction segment
recognized a future income tax recovery in the current year which was higher
than that of the comparable period due to the additional four months of
incremental operations. The enactment of Bill C-52 has resulted in a slight
reduction in the effective tax rate in accordance with the general rate
reduction to 18.5% for 2011 and beyond.
    On May 19, 2006, the Texas Legislature implemented a significant change
to Texas franchise tax for all corporations. As a result, corporations
including limited liability partnerships, which previously had limited
exposure to Texas franchise tax, are now, effective January 1, 2007, subject
to "Margins Tax". This new law results in the application of a 1% tax rate to
the taxable margin of the US operations which resulted in the Trust recording
$0.9 million to current income tax expense for the nine month period ended
September 30, 2007. In addition, Canadian current income tax expense increased
due to current federal and provincial tax of $1.3 million recognized on the
earnings of certain smaller divisions of the Trust, due to taxable earnings
surpassing the available capital cost allowance claim.

    
    NET EARNINGS AND FUNDS FLOW

    (thousands except
    per unit data -          Three months ended         Nine months ended
    Unaudited)                 September 30,              September 30,
                          2007     2006   % Change   2007    2006    % Change
    -------------------------------------------------------------------------
    Net earnings         15,043   31,573    (52.4)  61,627   92,369    (33.3)
      Per unit
      (diluted)(1)         0.18     0.37    (51.4)    0.65     1.09    (40.4)
    Funds flow from
     operations          46,456   48,973     (5.1) 142,619  142,224      0.3
      Per unit
      (diluted)(1)         0.55     0.57     (3.5)    1.42     1.68    (15.5)

    (1) Diluted units include the weighted average units outstanding, units
    issuable upon exchange of outstanding exchangeable shares and the
    dilutive impact, if any, of the deemed conversion of convertible
    debentures and units issuable pursuant to the Trust Unit Rights Incentive
    Plan. Interest expense incurred on the dilutive convertible debentures is
    added back to net earnings and to funds flow before change in non-cash
    working capital for the diluted per unit calculation.
    

    Geographical disbursement and expansion of service lines have enabled the
Trust to effectively counteract the prevailing market conditions in Canada.
Results in the current period continued to demonstrate the strength of the US
operations, which were further enhanced with the acquisition of Axxis. Gross
margin in the US division increased by 76.2% to $114.8 million for the nine
months ended September 30, 2007 and 74.8% to $44.1 million for the three
months ended September 30, 2007, representing incremental margin from the
acquisition of Axxis as well as the additional revenue generated through rig
deployments. The results of the US division were offset by a 21.5% decline in
the gross margin of the Canadian operations from $123.0 million for the nine
months ended September 30, 2006 to $96.5 million in the comparable period of
2007. On a quarterly basis, gross margin decreased 28.2% to $28.3 million in
2007 from $39.4 million in the comparable quarter of 2006 as a result of
overall declines across the Canadian market. The Trust has minimized the
downward impact of the declining Canadian market by securing higher
year-to-date day rates in comparison to the prior year, consistently
performing at utilization levels above industry averages and ensuring that the
well servicing, surface casing and coring and manufacturing divisions continue
to perform at optimal levels.
    From an operational perspective, the Trust's performance improved from
the prior year from both a quarterly and year-to-date perspective; however,
higher interest expense including non-cash interest on the accretion of the
convertible debentures and transaction costs being amortized into interest
expense, depreciation expense increases and an unrealized foreign exchange
loss contributed to the overall decline in net earnings. Higher debt levels
required to fund the Trust's capital initiatives increased cash interest
expense and the capital cost of the Trust's asset base continued to increase
with the addition of newer and deeper rigs, resulting in higher per day
depreciation rates which have increased overall depreciation expense.
Furthermore, weakening of the US dollar since 2006 and the higher balance of
US dollar denominated intercompany balances resulted in the Trust recognizing
a significant unrealized foreign exchange loss in 2007.
    Funds flow from operations before change in non-cash working capital
remained relatively stable in comparison to prior periods at $142.6 million
year-to-date and $46.5 million for the third quarter as non-cash reductions
that impacted net earnings during the period were added back to reconcile to
the cash position of the Trust. Overall stability was achieved through strong
results in the US operations where higher revenues in the US offset lower
margins in the Canadian segment. The Trust continues to follow an investment
strategy designed to ensure accretive growth for unitholders, including the
expansion into the US market as well as diversification of the Trust's asset
base which enabled the Trust to maintain funds flow for the period despite the
reduction in the Canadian market.

    
    LIQUIDITY AND CAPITAL RE

SOURCES September 30, December 31, (thousands except percent data - Unaudited) 2007 2006 ------------------------------------------------------------------------- Working capital 71,343 58,246 Current portion of long-term debt 1,547 3,232 Convertible debentures(2) 314,203 - Long-term debt(2) 364,575 388,276 -------------------------- Total debt 680,325 391,508 -------------------------- Total debt as a percentage of assets 45.8% 31.4% Net debt(1) 607,435 330,030 Net debt as a percentage of assets(1) 40.9% 26.5% Total assets 1,485,975 1,245,633 Total long-term liabilities 732,426 434,065 Total long-term liabilities as a percentage of assets 49.3% 34.8% Unitholders' equity 647,559 698,092 Total debt to unitholders' equity 105.1% 56.1% Total debt to unitholders' equity - assuming debenture conversion 38.1% 56.1% Net debt to unitholders' equity(1) 93.8% 47.3% ------------------------------------------------------------------------- (1) Readers are cautioned that net debt does not have a standardized meaning prescribed by GAAP and therefore may not be comparable to similar measures presented by other issuers; however, the Trust does compute net debt on a consistent basis for each reporting period. Net debt refers to the Trust's long-term debt including convertible debentures less its working capital position and is indicative of the Trust's overall indebtedness. (2) Convertible debentures and long-term debt are reflected net of associated transaction costs. Under the rig construction program the Trust has successfully deployed 31 rigs and with only three rigs remaining, the program is substantially complete. In light of the construction program coming to a close as well as the completion of three well servicing rigs, the purchase of three surface casing and coring rigs and the acquisition of Axxis on July 5, 2007, the Trust has increased total debt from the prior year by $288.8 million. Year-to-date capital expenditures totalled $350.4 million which was funded through both internally generated funds flow and long-term debt, of which $124.4 million was associated with the cash portion of the Axxis acquisition. As the rig construction program nears completion with the deployment of five Canadian drilling rigs and eight US drilling rigs during the nine months ended September 30, 2007, the Trust's capital requirements should begin to decline as the outstanding commitment on the construction program is minimal with the remaining three rigs ready for deployment in the early part of the fourth quarter of 2007. In connection with the closing of the Axxis acquisition on July 5, 2007, the Trust issued $354.3 million convertible debentures, of which $325.0 million was issued through a public offering and $29.3 million was issued to former owners of Axxis to finance a portion of the acquisition (see details of the convertible debentures below). The remaining portion of the purchase price of $124.4 million was financed through the proceeds raised on the closing of the convertible debenture, including $5.6 million to reimburse the former owners for construction costs spent on a barge rig under construction as at the date of acquisition. As part of the acquisition the Trust acquired a commitment to complete a second barge rig at an estimated cost of $27.5 million, of which $19.8 million was remaining at end of the third quarter of 2007. With the remaining proceeds of $197.8 million, the Trust reduced its Canadian Revolving Credit Facility to $106.0 million. Subsequent to this payment, approximately $51.8 million was drawn down on the revolver to fund the remaining construction commitments on the build program, construction costs on the barge rig, the purchase of three coring and surface casing rigs, and various other minor capital initiatives resulting in an overall decline in the revolver of $146.0 million from the balance at June 30, 2007. Due to the adoption of CICA 3855, Financial Instruments - Recognition and Measurement, the increase in long-term debt was slightly offset by the reclassification of deferred financing costs to long-term debt. This resulted in the balance of bank debt being offset by $4.0 million of deferred financing costs. Similarly, the balance of convertible debentures at September 30, 2007 is reflected net of $12.9 million in transaction costs. Working capital experienced a favourable increase of $13.1 million from the prior year, of which the working capital from the Axxis acquisition contributed an incremental $9.5 million. Despite the addition of Axxis working capital, total accounts receivable and accounts payable decreased by 2.6% and 2.8%, respectively from December 31, 2006 as a result of a slower Canadian market, resulting in a reduction of revenues and operating expenses in comparison to the prior year and more aggressive collection practices. Inventory also increased by approximately $7.6 million from the prior year in construction operations due to spare equipment and parts purchased to facilitate construction and recertification programs. Unitholders' equity decreased $50.5 million from year-end due to a significant cumulative translation adjustment on the Trust's US self-sustaining subsidiary as a result of an increasingly favourable Canadian dollar. Year-to-date distributions of $84.4 million also contributed to the decline while the equity component of the convertible debentures and net earnings for the nine months ended September 30, 2007 increased unitholders' equity by $28.2 million and $61.6 million, respectively. Convertible debentures In connection with the acquisition of Axxis, the Trust issued $354.3 million in unsecured subordinated debentures, of which $325.0 million was issued through a public offering and $29.3 million was issued to former owners of Axxis. The debentures are convertible into units of the Trust at the option of the holder at any time prior to maturity at a conversion price of $19.30. They have a face value of $1,000, coupon rate of 7.75%, mature July 31, 2012 with interest being paid semi-annually on June 30 and December 31. The Trust has the option to redeem the debentures in whole or in part at a redemption price of $1,000 after December 31, 2010 and before their maturity date. On redemption or maturity, the Trust may elect to satisfy its obligation to repay the principal by issuing Trust units. The value of the conversion feature was determined to be $28.2 million and has been recorded as equity with the remaining $326.1 million allocated to long-term debt, net of $13.6 million of transaction costs. The debentures are being accreted such that the liability at maturity will equal the face value of $354.3 million. As at September 30, 2007 there were no conversions of these debentures. ------------------------------------------------------------------------- UNITHOLDERS' CAPITAL September 30, December 31, (thousands - Unaudited) 2007 2006 ------------------------------------------------------------------------- Unitholders' capital 675,712 669,584 Exchangeable shares 2,477 5,777 ------------------------------------------------------------------------- Unitholders' capital increased from the 2006 year-end by $6.1 million, with the conversion of 311,367 Series C exchangeable shares ($3.3 million) to 356,404 trust units and the exercise of 274,089 rights ($2.5 million) into trust units. Unitholders' capital on November 2, 2007 was $675.7 million (83,613,130 units). DISTRIBUTIONS (thousands except unit and per unit Three months ended Nine months ended data - Unaudited) September 30, September 30, 2007 2006 2007 2006 ------------------------------------------------------------------------- Cash flow from operating activities 48,388 2,366 122,450 119,894 Net change in non-cash operating working capital (1,932) 46,607 20,169 22,330 ----------------------------------------------------- Funds flow before change in non-cash working capital 46,456 48,973 142,619 100% 142,224 100% Distributions paid & declared (28,843) (28,640) (86,416) 61% (76,846) 54% ----------------------------------------------------- Funds retained for growth, debt reduction & future distribution 17,613 20,333 56,203 39% 65,378 46% Funds flow before change in non-cash working capital per unit (basic)(1) 0.55 0.59 1.70 1.72 Distributions paid & declared per unit (0.34) (0.34) (1.03) (0.93) ----------------------------------------------------- Funds retained per unit 0.21 0.25 0.67 0.79 Quarter ending annualized distribution per unit 1.38 1.38 1.38 1.38 ------------------------------------------------------------------------- (1) Includes trust units to be issued upon conversion of exchangeable shares. During the three and nine months ended September 30, 2007, Trinidad distributed $28.8 million and $86.4 million, respectively, to unitholders. Distributions per unit have remained stable quarter-over-quarter; however, lower distributions in the earlier part of 2006 resulted in an increase in distributions paid and declared by $0.2 million and $9.6 million for the three and nine months ended September 30, 2007. Despite distribution reductions across the sector, the Trust has sustained annualized distributions per unit at $1.38 throughout the current period and maintained a conservative payout ratio of 61% for the nine months ended September 30, 2007. The Trust has maintained stable funds flow through its significant presence in the US drilling market which has been uninterrupted by seasonality or fluctuations in commodity prices. Entrance into the offshore barge market will further enhance the future stability of funds flow. Low industry fundamentals in Canada have resulted in a 7% increase in the payout ratio in comparison to the nine months ended September 30, 2006. However, the payout ratio continues to improve as the year progresses and as the US segment capitalizes on additional rig deployments and the Canadian segment enters into a busier fourth quarter. The Trust manages its distributions based on a payout ratio goal of up to 75%, with the remainder retained for future growth opportunities, debt repayment, or incremental distributions to unitholders. SEASONALITY The Trust operates the majority of its fleet in Western Canada and therefore operations are heavily dependent upon the seasons. The winter season, which incorporates the first quarter, is a busy period as oil and gas companies take advantage of frozen conditions to move drilling rigs into regions which might otherwise be inaccessible to heavy equipment due to swampy conditions. The second quarter normally encompasses a slow period referred to as spring break-up. During this period melting conditions result in temporary municipal road bans that effectively prohibit the movement of drilling rigs. The third and fourth quarters are usually representative of average activity levels. The Trust's expansion into the US market has reduced its overall exposure to the seasonal factors that are present in its Canadian operations. These seasonal conditions typically limit Canadian drilling activity, whereas in the United States operators can work throughout the year. This increased number of operating days throughout the year will allow the Trust to better manage its business with more sustainable funds flow throughout the annual cycle. CRITICAL ACCOUNTING ESTIMATES The preparation of the consolidated financial statements requires that certain estimates and judgements be made with regard to the reported amount of revenues and expenses and the carrying values of assets and liabilities. These estimates are based on historical experience and management judgement. Anticipating future events involves uncertainty and consequently the estimates used by management in the preparation of the consolidated financial statements may change as future events unfold, additional experience is acquired or the Trust's operating environment changes. Depreciation The accounting estimate that has the greatest impact on the Trust's financial results is depreciation. Depreciation of the Trust's property and equipment incorporates estimates of useful lives and residual values. These estimates may change as more experience is obtained or as general market conditions change, impacting the operation of the Trust's capital assets. Unit based compensation Compensation expense associated with rights at grant date are estimates based on various assumptions such as volatility, annual distribution yield, risk free interest rate and expected life using the Black-Scholes methodology to produce an estimate of the fair value of such compensation. Allowance for doubtful accounts receivable The Trust performs credit evaluations of its customers and grants credit based on past payment history, financial conditions and anticipated industry conditions. Customer payments are regularly monitored and a provision for doubtful accounts is established based on specific situations and overall industry conditions. The Trust's history of bad debt losses has been minimal and generally limited to specific customer circumstances; however, given the cyclical nature of the oil and gas industry, the credit risks can change suddenly and without notice. Goodwill In accordance with Canadian Generally Accepted Accounting Principles, the Trust performs an annual goodwill impairment test each fiscal year. This test was performed based on current industry factors and no goodwill impairment exists. Fair value of interest rate swaps The fair value of the interest rate swaps are estimated based on future projected interest rates and adjusted on a quarterly basis for monthly settlements and changes in projections. The Trust receives the valuation from the contract counterparty on a quarterly basis and records the associated change in fair value at each reporting period. Convertible debentures The proceeds from the offering have been bifurcated into separate liability and equity components. The value of the conversion feature has been determined based on an option pricing model and recorded as equity on the Consolidated Balance Sheet. CHANGES IN ACCOUNTING POLICY Effective January 1, 2007, the Trust adopted the following new accounting standards issued by the Canadian Institute of Chartered Accountants ("CICA"), as described further in note 1 of the Notes to the Consolidated Financial Statements. Section 1530, Comprehensive Income Section 1530 introduces a new Statement of Comprehensive Income, which reflects changes in the fair value of financial instruments designated as cash flow hedges, to the extent that they are effective, and changes in the foreign currency translation of self-sustaining subsidiaries of the Trust. These cumulative changes are reflected in equity as part of accumulated other comprehensive income and the Trust's Consolidated Financial Statements now include a Consolidated Statement of Comprehensive Income and Consolidated Statement of Accumulated Other Comprehensive Income ("AOCI"). Previously, the accumulated gains and losses arising from translation of $0.8 million were deferred and included in the foreign currency translation adjustment as part of unitholders' equity. In accordance with the transitional provisions, this prior year balance was reclassified into AOCI. In addition, the foreign currency translation adjustment for the three and nine months ended September 30, 2007 of $29.5 million and $56.2 million, respectively, has been recognized into OCI. Section 3855, Financial Instruments - Recognition and Measurement Section 3855 establishes standards for recognizing and measuring financial instruments, including financial assets, financial liabilities and derivatives. All financial instruments are required to be measured at fair value upon initial recognition of the transaction and measurement in subsequent periods is dependant on whether the instrument is classified as "held-for-trading", "available-for-sale", or "held-to-maturity" based on the standard. Financial instruments classified as "held-for-trading" are subsequently re-valued to fair market value with changes in the fair value being recognized into earnings; financial instruments classified as "available-for-sale" are subsequently re-valued to fair market value with changes in the fair value being recognized to OCI and financial instruments designated as "held-to-maturity" are valued at amortized cost using the effective interest method of amortization. Upon initial adoption of the financial instrument standard, long-term debt is recognized at fair value net of transaction costs directly attributable to the issuance of the debt. Accordingly, at January 1, 2007, previously deferred costs of $5.7 million that were separately presented as a component of other assets on the Consolidated Balance Sheet and amortized into income using the straight-line method over the life of the debt were reclassified to long-term debt. The cost capitalized as a portion of long-term debt will be amortized using the effective interest method. The change in amortization methodology was immaterial for adjustment to opening retained earnings and the reclassification of transactions costs resulted in a net decrease in other assets and long-term debt by $4.9 million. Similarly, costs related to the issuance of the Trust's convertible debentures are netted against the carrying value of the convertible debentures and amortized into earnings over the life of the convertible debentures using the effective interest rate method. Section 3865, Hedges Section 3865 establishes how hedge accounting may be applied. For cash flow hedges the fair value of the hedged instrument is recognized on the balance sheet and changes in the fair value, to the extent that the hedge is effective, are recognized into OCI and any ineffectiveness is recognized into income in the period. In accordance with transitional provisions, the cumulative prior period effect of $5.6 million has been recognized into OCI without restatement of prior period amounts, net of $1.9 million to reflect the future income tax asset that would have arisen in the prior year in accordance with the new standards. Section 1506, Accounting Changes Section 1506 allows for voluntary changes in accounting policy only if they result in financial statements which provide reliable and more relevant information. Accounting policy changes are applied retrospectively unless it is impractical to determine the period or cumulative impact of the change. Corrections of prior period errors are applied retrospectively and changes in accounting estimates are applied prospectively by including these changes in earnings. The Trust has adopted the requirements of this section and will apply these standards to any future changes in accounting policies and/or estimates. There are no other material impacts on the Consolidated Financial Statements for the adoption of these new standards. DISCLOSURE CONTROLS & PROCEDURES AND INTERNAL CONTROLS OVER FINANCIAL REPORTING Disclosure controls and procedures are designed to provide reasonable assurance that all information required to be disclosed by the Trust is recorded, processed, summarized and reported to senior management, including the CEO and CFO, in an appropriate manner to allow timely decisions regarding required disclosure as defined under Multilateral Instrument 52-109, Certification of Disclosures in Annual and Interim Filings. The Trust has evaluated the effectiveness of the design and operation of disclosure controls and procedures, under the supervision of the CEO and the CFO. Internal controls over financial reporting are designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with Canadian GAAP. There have been no changes in the Trust's internal controls over financial reporting that occurred during the three months ended September 30, 2007 that have materially affected, or are reasonably likely to affect the Trust's internal controls over financial reporting. The Trust is currently completing an assessment of the business process controls of Mastco and Axxis and has not concluded on the design effectiveness as at September 30, 2007. As a result, the Trust has relied on management's review to assess the accuracy of the financial statements at the reporting date. OUTLOOK Under the "Our Fair Share" report issued by the Alberta government, the province's new royalty system has caused many oil and gas producers to re-evaluate Alberta based activity and potentially shift investment dollars into other regions of Canada and into the US. Furthermore, in conjunction with weak natural gas prices and an influx of supply, Canadian drillers are challenged and being forced to endure idle capacity and competitive consumer pricing. The CAODC is projecting 16,339 well completions in 2007 and early forecasts for 2008 do not indicate signs of improvement for the coming year. The Trust is prepared to face these challenges with approximately 80% of the Canadian rig fleet tailored to the medium and deeper drilling market with depths in excess of 2,000 metres. The Canadian rig construction program has successfully reached completion resulting in a rig fleet equipped with modern, high quality, deeper drilling rigs with all rigs deployed under the rig build program secured by three to five year take-or-pay contracts. These factors have allowed the Trust to mitigate decreasing industry fundamentals resulting in utilization levels that have surpassed the Canadian industry average by 18.4% in 2007 and will continue to do so by focusing on the deeper drilling market and fulfilling obligations under the take-or-pay contracts. Operations in the US market are now contributing more than 50% to the overall results of the Trust. With the completion of the rig construction program in the fourth quarter of 2007 and the acquisition of Axxis, the combined US rig fleet will include 46 land drilling rigs, one barge rig, three barge rigs under Bareboat Charters and one barge rig under construction. All rigs deployed under the rig construction program are secured by long-term take-or-pay contracts while rigs acquired through Axxis are secured by fixed price contracts. By capitalizing on US opportunities, the Trust has managed to maintain funds flow at levels consistent with the prior year. Future cash flows will be further enhanced with the deployment of the second barge drilling rig. The acquisition of Axxis has added a fleet of recently built high quality assets, an experienced management team and an opportunity to further diversify the services of the Trust into a lucrative niche market. Unlike jack-up rigs that operate in the deeper waters of the Gulf of Mexico, the barge rigs acquired from Axxis are tailored to shallower waters which is more cost effective for the operators and less impacted by the poor weather conditions experienced in the Gulf of Mexico in recent years. The barge drilling market is an expanding niche with opportunities for growth both in the US and other international regions. The combination of Trinidad's technology construction expertise and the experienced management of Axxis will allow this division to grow and add value for investors. We are focused on continuing to add to our distribution capabilities by accretively growing our business and focusing on being the market leader. All future capital investments will continue to be evaluated based on return on capital with a focus on low risk operating environments. Trinidad Energy Services Income Trust is a growth-oriented oil and natural gas services provider based in Calgary, Alberta. Focusing on deeper drilling, modern rig fleets, in-house design and technology-based advancement, Trinidad has positioned itself as a premium service provider. Trinidad's growth is driven by chasing and capturing new horizons - advancing technologies, offering new services, entering new markets and performing strategic acquisitions. With the completion of the current rig construction programs and the acquisition of Axxis, the Trust will have 109 drilling rigs ranging in depths from 1,000 - 6,500 metres and two barge drilling rigs. In addition to its drilling rigs, Trinidad has 20 service rigs that have been completely retrofitted or are new within the past five years and 20 pre-set and coring rigs. Trinidad is focused on providing modern, reliable, expertly designed equipment operated by well-trained and experienced personnel. Trinidad's drilling fleet is one of the most adaptable and competitive in the industry. "signed" Michael E. Heier "signed" Brent J. Conway ------------------------- -------------------------- Chairman of the Board Chief Financial Officer Chief Executive Officer The Toronto Stock Exchange has neither approved nor disapproved the information contained herein. CONSOLIDATED BALANCE SHEETS (thousands - Unaudited) September 30, December 31, 2007 2006 ------------------------------------------------------------------------- Assets Current assets Cash and cash equivalents 10,113 9,413 Accounts receivable 147,994 151,990 Inventory 15,054 7,451 Prepaid expenses 4,172 2,868 -------------------------- 177,333 171,722 Deposit on capital assets 3,118 42,172 Capital assets 1,101,689 903,111 Goodwill 169,387 123,483 Other long-term assets 34,448 5,145 -------------------------- 1,485,975 1,245,633 -------------------------- Liabilities Current liabilities Accounts payable and accrued liabilities 85,556 88,083 Accrued trust distributions 9,615 9,543 Current portion of deferred revenue 7,399 9,090 Current portion of long-term debt 1,547 3,232 Current portion of fair value of interest rate swap (note 7) 1,179 - Future income taxes 694 3,528 -------------------------- 105,990 113,476 Deferred revenue 5,379 7,070 Long-term debt, net of transaction costs (note 3, 7 and 8) 364,575 388,276 Convertible debentures, net of transaction costs (note 8) 314,203 - Fair value of interest rate swaps (note 7) 3,055 - Future income taxes 45,214 38,719 -------------------------- 838,416 547,541 Unitholders' equity Unitholders' capital (note 4) 675,712 669,584 Exchangeable shares (note 5) 2,477 5,777 Convertible debentures (note 8) 28,223 - Contributed surplus (note 4) 13,349 11,722 Accumulated other comprehensive income (59,172) (750) Accumulated trust distributions (note 9) (276,400) (189,984) Accumulated earnings 263,370 201,743 -------------------------- 647,559 698,092 -------------------------- 1,485,975 1,245,633 -------------------------- (See Notes to the Consolidated Financial Statements) Commitments (note 10) CONSOLIDATED STATEMENTS OF OPERATIONS AND ACCUMULATED EARNINGS (thousands except unit and per unit data - Unaudited) Three months ended Nine months ended September 30, September 30, 2007 2006 2007 2006 ------------------------------------------------------------------------- Revenue Oilfield services 160,980 149,924 482,128 416,041 Bareboat revenue (note 10) 1,021 - 1,021 - Other 182 701 739 2,068 ---------------------------------------------------- 162,183 150,625 483,888 418,109 ---------------------------------------------------- Expenses Operating 87,033 83,747 266,334 223,564 General and administrative 14,949 11,607 41,927 37,835 Interest on long-term debt 7,174 6,388 25,284 13,740 Interest on convertible debentures (note 8) 8,302 - 8,302 - Unit based compensation 508 740 1,954 5,323 Foreign exchange loss (gain) 5,394 (45) 12,283 1,045 Depreciation and amortization 20,190 13,976 53,279 36,787 Loss (gain) on sale of assets 31 (2,032) 238 (2,002) ---------------------------------------------------- 143,581 114,381 409,601 316,292 ---------------------------------------------------- Earnings before income taxes 18,602 36,244 74,287 101,817 Income taxes Current tax expense (recovery) 299 36 2,283 (389) Future tax expense 3,260 4,635 10,377 9,837 --------------------------------------------------- 3,559 4,671 12,660 9,448 --------------------------------------------------- Net earnings 15,043 31,573 61,627 92,369 Charges for normal course issuer bid - (96) - (96) Accumulated earnings - beginning of period 248,327 139,212 201,743 78,416 ---------------------------------------------------- Accumulated earnings - end of period 263,370 170,689 263,370 170,689 ---------------------------------------------------- Earnings per unit Basic 0.18 0.38 0.73 1.11 Diluted 0.18 0.37 0.65 1.09 Weighted average number of trust units Basic 83,989,145 83,705,299 83,917,739 82,851,643 Diluted 85,140,262 85,316,897 103,605,851 84,651,979 (See Notes to the Consolidated Financial Statements) CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (thousands - Unaudited) Three months ended Nine months ended September 30, September 30, 2007 2006 2007 2006 ------------------------------------------------------------------------- Net earnings 15,043 31,573 61,627 92,369 Other comprehensive income Change in fair value of derivatives designated as cash flow hedges, net of income tax (264) - 1,474 - Foreign currency translation adjustment (29,510) 319 (56,196) (12,677) ---------------------------------------------------- Total other comprehensive income (loss) (29,774) 319 (54,722) (12,677) Comprehensive income (loss) (14,731) 31,892 6,905 79,692 CONSOLIDATED STATEMENT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (thousands - Unaudited) September 30, September 30, 2007 2006 ------------------------------------------------------------------------- Accumulated other comprehensive loss - beginning of period (750) - Adjust opening balance due to adoption of new accounting policies (3,700) - Other comprehensive loss during the period (54,722) (12,677) -------------------------- Accumulated other comprehensive loss - end of period (59,172) (12,677) -------------------------- (See Notes to the Consolidated Financial Statements) CONSOLIDATED STATEMENTS OF CASH FLOWS (thousands - Unaudited) Three months ended Nine months ended September 30, September 30, 2007 2006 2007 2006 ------------------------------------------------------------------------- Cash provided by (used in) Operating activities Net earnings for the period 15,043 31,573 61,627 92,369 Items not affecting cash Depreciation and amortization 20,190 13,976 53,279 36,787 Loss (gain) on sale of assets 31 (2,032) 238 (2,002) Unit based compensation 508 740 1,954 5,323 Future income taxes 3,260 4,635 10,377 9,837 Effective interest on financing costs (note 7) 1,078 - 1,830 - Accretion on convertible debentures (note 8) 1,028 - 1,028 - Unrealized foreign exchange loss (gain) 5,318 81 12,286 (90) ----------------------------------------------- Funds flow from operations before change in non-cash working capital 46,456 48,973 142,619 142,224 Net change in non-cash operating working capital 1,932 (46,607) (20,169) (22,330) ----------------------------------------------- 48,388 2,366 122,450 119,894 ----------------------------------------------- Investing activities (Increase) decrease in deposits on capital assets 278 5,122 37,242 (22,891) Acquisition of Mastco Derrick Service Ltd. (note 3) - 13,523 - (24,717) Acquisition of Axxis Drilling Inc. (note 3) (124,370) - (124,370) - Purchase of capital assets (44,703) (89,203) (233,958) (223,731) Proceeds from dispositions 532 5,592 1,021 6,598 Change in non-cash working capital item - accounts payable and accrued liabilities (20,773) 7,317 10,521 6,024 ----------------------------------------------- (189,036) (57,649) (309,544) (258,717) ----------------------------------------------- Financing activities (Decrease) increase in long-term debt - net (146,745) 53,318 (34,450) 231,984 Net proceeds from unit issues (note 4) 199 1,891 2,501 8,088 Proceeds from debenture issuance (note 8) 325,000 - 325,000 - Increase (decrease) in deferred revenue (2,812) - (1,311) - Purchased units (note 4) - (276) - (276) Trust unit distribution (note 9) (28,843) (28,640) (86,416) (76,846) Debt financing costs (note 7) (13,593) (111) (14,193) (5,204) Change in non-cash working capital item - accrued distributions 2 22 72 2,839 ----------------------------------------------- 133,208 26,204 191,203 160,585 ----------------------------------------------- Cash flow from operating, investing and financing activities (7,440) (29,079) 4,109 21,762 Effect of translation on foreign currency cash 449 (97) (3,409) (817) ----------------------------------------------- Increase (decrease) in cash for the period (6,991) (29,176) 700 20,945 Cash - beginning of period 17,104 61,870 9,413 11,749 ----------------------------------------------- Cash - end of period 10,113 32,694 10,113 32,694 ----------------------------------------------- Interest paid 7,503 5,427 24,421 11,338 Taxes paid 38 46 185 1,195 (See Notes to the Consolidated Financial Statements) NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) 1. ACCOUNTING POLICIES AND ESTIMATES These consolidated interim financial statements are prepared by management, in accordance with Canadian Generally Accepted Accounting Principles, and follow the same accounting policies and methods as the audited consolidated financial statements for the year ended December 31, 2006, except as noted below, and therefore do not contain all of the disclosures required for the annual financial statements. As a result, the unaudited consolidated interim financial statements should be read in conjunction with the consolidated financial statements contained in the annual report for the year ended December 31, 2006. Adoption of New Accounting Standards Effective January 1, 2007, the Trust adopted the following new accounting standards issued by the Canadian Institute of Chartered Accountants (CICA): Section 1530, Comprehensive Income, introduces a new Statement of Comprehensive Income, which reflects changes in the fair value of financial instruments designated as cash flow hedges, to the extent that they are effective, and changes in the foreign currency translation of self-sustaining subsidiaries of the Trust. These cumulative changes are reflected in equity as part of accumulated other comprehensive income and the Trust's Consolidated Financial Statements now include a Consolidated Statement of Comprehensive Income and Consolidated Statement of Accumulated Other Comprehensive Income ("AOCI"). Section 3855, Financial Instruments - Recognition and Measurement, establishes standards for recognizing and measuring financial instruments, including financial assets, financial liabilities and derivatives. All financial instruments are required to be measured at fair value upon initial recognition of the transaction and measurement in subsequent periods is dependant on whether the instrument is classified as "held-for-trading", "available-for- sale", or "held-to-maturity" based on the standard. Financial instruments classified as "held-for-trading" are subsequently re-valued to fair market value with changes in the fair value being recognized into earnings; financial instruments classified as "available-for-sale" are subsequently re-valued to fair market value with changes in the fair value being recognized to other comprehensive income ("OCI") and financial instruments designated as "held-to- maturity" are valued at amortized cost using the effective interest method of amortization. Section 3865, Hedges, establishes how hedge accounting may be applied. For cash flow hedges any change in the fair value of a financial instrument designated as a cash flow hedge is recognized into income in the same period as the hedged item. Any fair value change in the financial instrument is recognized on the balance sheet and changes in the fair value, to the extent that the hedge is effective, are recognized into OCI and any ineffectiveness is recognized into income in the period. Section 1506, Accounting Changes, allows for voluntary changes in accounting policy only if they result in financial statements which provide reliable and more relevant information. Accounting policy changes are applied retrospectively unless it is impractical to determine the period or cumulative impact of the change. Corrections of prior period errors are applied retrospectively and changes in accounting estimates are applied prospectively by including these changes in earnings. The Trust has adopted the requirements of this section and will apply these standards to any future changes in accounting policies and/or estimates. Financial Instruments and Hedge Accounting Translation of self-sustaining foreign operations As a result of adopting CICA Section 1530, a new Consolidated Statement of Comprehensive Income forms part of the Trust's consolidated financial statements. Gains and losses resulting from the translation of the assets and liabilities of the Trust's self- sustaining foreign operations into Canadian dollars are included in the Consolidated Statement of Comprehensive Income as a separate component of OCI. Previously, the accumulated gains and losses arising from translation of $0.8 million were deferred and included in the foreign currency translation adjustment as part of unitholders' equity. In accordance with the transitional provisions, this prior year balance was reclassified into AOCI. In addition, the foreign currency translation adjustment for the three and nine months ended September 30, 2007 of $29.5 million and $56.2 million, respectively, has been recognized into OCI. Cash flow hedge The application of hedge accounting to the Trust's interest rate swaps and forward foreign exchange contract has resulted in the designation of cash flow hedges whereby gains and losses resulting from changes in the fair value of the hedge are included in the Consolidated Statement of Comprehensive Income, to the extent that the hedge is effective. In accordance with transitional provisions, the cumulative prior period effect of $5.6 million pertaining to the interest rate swaps has been recognized into OCI without restatement of prior period amounts, net of $1.9 million to reflect the future income tax asset that would have arisen in the prior year in accordance with the new standards. The forward foreign exchange contract was entered into in the current year; hence, there is no impact on prior year figures. Transaction costs Upon initial adoption of the financial instrument standard, long-term debt is recognized at fair value net of transaction costs directly attributable to the issuance of the debt. Accordingly, at January 1, 2007, previously deferred costs of $5.7 million that were separately presented as a component of other assets on the Consolidated Balance Sheet and amortized into income using the straight-line method over the life of the debt were reclassified to long-term debt. The cost capitalized as a portion of long-term debt will be amortized using the effective interest method. The change in amortization methodology was immaterial for restatement and the reclassification of transaction costs resulted in a net decrease in other assets and long-term debt by $4.9 million. Similarly, costs related to the issuance of the Trust's convertible debentures are netted against the carrying value of the convertible debentures and amortized into earnings over the life of the convertible debentures using the effective interest rate method. There are no other material impacts on the Consolidated Financial Statements for the adoption of these new standards. Convertible Debentures The Trust's convertible debentures have been classified as debt with a portion of the proceeds representing the value of the conversion option bifurcated to equity. The debt balance accretes over time to the amount owing on maturity and such increases in the debt balance are reflected as non-cash interest expense in the Consolidated Statement of Operations. Upon conversion, portions of debt and equity are transferred into Unitholders' Capital. Capital assets The acquisition of substantially all the assets of Axxis (defined herein) in the third quarter diversified the Trusts' operations to include barge drilling rigs, with related inventory, crew boats and spare parts. Additional asset classes resulting from the acquisition include barge drilling rigs that have been assigned a useful life of 9,125 days (10% salvage value) to be depreciated on a unit-of- production basis and crew boats that have been assigned a useful life of 15 years on a straight-line basis. The Trust has applied existing policies to all other assets acquired. Future income taxes On June 22, 2007, Bill C-52 was enacted for Canadian accounting purposes that effectively imposed a new income tax on distributions from income trusts for taxation years beginning in 2011, at a rate of 31.5%. The enactment of this legislation triggered the recognition of future income taxes based on temporary differences expected to reverse after the date that the taxation changes take effect. There was no impact of this legislation for the Trust at the end of the second quarter of 2007; however, an additional future income tax recovery of $0.5 million was recognized in the third quarter of 2007 on financing costs incurred on the issuance of the convertible debentures. 2. SEASONALITY The Trust operates the majority of its fleet in Western Canada and therefore operations are heavily dependent upon the seasons. The winter season, which incorporates the first quarter, is a busy period as oil and gas companies take advantage of frozen conditions to move drilling rigs into regions which might otherwise be inaccessible to heavy equipment due to swampy conditions. The second quarter normally encompasses a slow period referred to as spring break-up. During this period melting conditions result in temporary municipal road bans that effectively prohibit the movement of drilling rigs. The third and fourth quarters are usually representative of average activity levels. The Trust's expansion to the US market has reduced its overall exposure to the seasonal factors that are present in its Canadian operations. These seasonal conditions typically limit Canadian drilling activity, whereas in the United States operators can work throughout the year. This increased number of operating days throughout the year will allow the Trust to better manage its business with more sustainable cash flows throughout the annual cycle. 3. ACQUISITIONS Amalgamation of Mastco Derrick Service Ltd. Effective March 16, 2006, the Trust amalgamated one of its wholly- owned subsidiaries with Mastco Derrick Service Ltd. ("Mastco") for consideration of $62.4 million, less outstanding debts adjusted for net working capital. Mastco's purchase price was subject to a working capital adjustment which has been finalized as of March 31, 2007. The acquisition was funded through internal funds flow of $14.7 million and the issuance of 1,494,557 trust units with a value of $24.7 million. The consideration paid for this acquisition has been allocated under the purchase method as follows: (thousands) 2006 ---------------------------------------------------------------------- Purchase price allocated as follows: Working capital, net (22,943) Other assets 329 Goodwill 42,837 Capital assets 17,148 Future income taxes 2,018 ---------------- 39,389 ---------------- Financed as follows: Trust units 24,720 Cash, net of working capital adjustment 14,669 ---------------- 39,389 ---------------- Goodwill from this acquisition is not tax deductible. Acquisition of assets of Axxis Effective July 5, 2007, a subsidiary of the Trust, purchased substantially all of the assets of US-based Drilling Productivity Realized, L.L.C., P.C. Axxis, L.L.C., DPR International, L.L.C. and DPR Rentals, L.L.C. (collectively, "Axxis") for consideration of $148.1 million. Additionally, the Trust acquired a commitment to construct an additional barge rig for approximately $27.5 million, of which $5.6 million had been spent at the time of acquisition and was included in the purchase price. The acquisition was funded through the issuance of $29.3 million of convertible debentures to the former shareholders of Axxis and $124.4 million in cash proceeds raised through a public issuance of 325,000 convertible debentures for gross proceeds of $325.0 million. The consideration paid for this acquisition has been allocated under the purchase method as follows: (thousands) 2007 ---------------------------------------------------------------------- Purchase price allocated as follows: Capital assets 96,490 Assets under construction 5,624 Intangible assets 39,569 Goodwill 51,593 Long-term liabilities (39,569) ---------------- 153,707 ---------------- Financed as follows: Convertible debentures 29,337 Cash 124,370 ---------------- 153,707 ---------------- Goodwill from this acquisition is tax deductible. As a result of the acquisition of Axxis the Trust is obligated to pay US$12.5 million annually to the former shareholders of Axxis for the next three years pertaining to provisions under the Bareboat Charter, discussed further in Note 10 - Commitments. The consideration will be paid annually and is contingent on the continued operation of three barge rigs currently under contract. To the extent that these contracts are terminated prior to the end of the three years no further payments will be required. The amount paid under this commitment is considered a cost of the purchase and has been included in the purchase price and will be accrued and recorded against the associated revenue earned from the rigs and reported net as Bareboat revenues in accordance with EIC-123, Reporting Revenue Gross as a Principal versus Net as an Agent. 4. UNITHOLDERS' CAPITAL AND CONTRIBUTED SURPLUS a) Unitholders' capital Authorized Unlimited number of trust units, voting, participating (thousands except unit data) September 30, 2007 December 31, 2006 ---------------------------------------------------------------------- Number Amount Number Amount of Units $ of Units $ --------------------------------------------------- Unitholders' capital - opening balance 82,981,952 669,584 78,909,976 621,972 Trust units issued on acquisitions - - 1,494,557 24,720 Trust units issued on conversion of exchangeable shares 356,404 3,300 1,505,630 13,825 Trust units issued on exercise of options and rights 274,089 2,501 1,138,289 8,272 Trust units repurchased under normal course issuer bid - - (66,500) (537) Contributed surplus transferred on exercised options and rights - 327 - 1,332 --------------------------------------------------- Unitholders' capital - ending balance 83,612,445 675,712 82,981,952 669,584 --------------------------------------------------- Basic earnings per unit are calculated using the weighted average number of Trust units outstanding during the three and nine month period ended September 30, 2007 of 83,989,145 and 83,917,739, respectively, (three and nine months ended September 30, 2006 - 83,705,299 and 82,851,643). For purposes of calculating diluted earnings per unit, 1,151,117 and 1,328,664 units issuable pursuant to the Trust Unit Rights Incentive Plan for the three and nine month period ended September 30, 2007, respectively (three and nine months ended September 30, 2006 - 1,611,598 and 1,800,336) were added to the weighted average calculation. Additionally, the diluted earnings per unit calculation for the three months ended September 30, 2007 does not include 18,359,448 of potentially issuable units pursuant to the conversion of the convertible debentures as the impact on net earnings was anti-dilutive; however, this impact has been reflected in diluted net earnings per unit for the nine months ended September 30, 2007. b) Contributed surplus (thousands) September 30, December 31, 2007 2006 ---------------------------------------------------------------------- Contributed surplus - opening balance 11,722 5,949 Unit based compensation expense 1,954 7,105 Contributed surplus transferred on exercise of rights (327) (1,332) ------------------------- Contributed surplus - ending balance 13,349 11,722 ------------------------- 5. EXCHANGEABLE SHARES A subsidiary of the Trust has issued the following exchangeable shares: (thousands except unit data) September 30, 2007 December 31, 2006 ---------------------------------------------------------------------- Number Amount Number Amount of Units $ of Units $ --------------------------------------------------- Exchangeable shares - opening balance 611,966 5,777 2,007,883 19,602 Exchangeable shares exchanged, Initial Series - - (347,100) (2,707) Exchangeable shares exchanged, Series C (311,367) (3,300) (1,048,817) (11,118) --------------------------------------------------- Exchangeable shares - ending balance 300,599 2,477 611,966 5,777 --------------------------------------------------- The exchange ratio for the 253,430 initial series exchangeable shares is 1.31831 at September 30, 2007 and the trust units issuable upon conversion are 334,099. The exchange ratio for the 47,169 Series C exchangeable shares is 1.20431 at September 30, 2007 and the trust units issuable upon conversion are 56,806. 6. UNIT OPTION AND RIGHTS PLAN Trust Unit Rights Incentive Plan On May 2, 2003, the Trust established the Trust Unit Rights Incentive Plan to assist directors, officers, employees and consultants of the Trust and its affiliates to participate in the growth and development of the Trust. The following table sets out unit options that are outstanding under the Trust Unit Rights Incentive Plan: ---------------------------------------------------------------------- September 30, 2007 December 31, 2006 ---------------------------------------------------------------------- Weighted Weighted Number of Average Number of Average Rights Exercise Price Rights Exercise Price ($) ($) --------------------------------------------------- Outstanding - opening balance 8,246,839 12.43 5,746,326 9.64 Granted during the period 63,486 13.44 3,890,818 15.13 Exercised during the period (274,089) 9.13 (1,118,437) 7.36 Forfeited during the period (31,128) 13.81 (271,868) 13.09 --------------------------------------------------- Outstanding - ending balance 8,005,108 12.55 8,246,839 12.43 --------------------------------------------------- The Trust uses the Black-Scholes option-pricing model to determine the estimated fair value of the unit rights issued subsequent to January 1, 2003. The per unit weighted average fair value of stock options granted during the period ended September 30, 2007 was $1.49 (2006 - $2.66). 7. FINANCIAL INSTRUMENTS Interest rate swap The Trust entered into cash flow hedges using interest rate swap arrangements to hedge the floating rate interest on fifty percent of the outstanding balance of the US and Canadian term debt facilities. These contracts have been recorded at their fair value on the Trust's consolidated financial statements. The Trust recorded a loss of $0.3 million and gain of $1.5 million in OCI for the three and nine months ended September 30, 2007 due to the change in fair value of the cash flow hedge. The Trust has assessed 100% hedge effectiveness; hence the entire change in fair value has been recorded in OCI. Financing costs The carrying value of long-term debt has been adjusted in accordance with CICA Section 3855, Financial Instruments - Recognition and Measurement, on financial instruments. Debt issuance costs which were previously classified as a component of other assets have been reclassified to long-term debt. The Trust recorded interest expense of $0.4 million and $1.2 million for the three and nine months ended September 30, 2007 under the effective interest method. Additionally, the carrying value of the debt component of convertible debentures is reflected net of $13.6 million in financing costs. The Trust recorded interest expense of $0.7 million for the three and nine months ended September 30, 2007 under the effective interest method. Foreign exchange forward contract On June 29, 2007 the Trust entered into a forward contract to purchase US currency to fund the acquisition of the assets of Axxis - see note 3. The future commitment of US$111.2 million exposed the Trust to foreign currency risk which was mitigated by a forward contract to purchase US currency at a rate of 1.0631 on the date of closing. The Trust designated this contract as a cash flow hedge and assessed it as 100% effective and as such no gain or loss was recorded on the contract and the acquisition was recorded at the forward contracted rate. 8. LONG-TERM DEBT Revolving Credit Facility Effective June 18, 2007, Trinidad amended its current Canadian Revolving Credit Facility (the "First Amending Agreement") to provide a temporary increase of $35.0 million, increasing the principal available from $250.0 million to $285.0 million. This increase was underwritten by GE Energy Financial Services, as agent for the Credit Facilities and is subject to similar terms and conditions as the original Revolving Credit Facility. This increase was made available to the Trust for six months subsequent to the execution of the First Amending Agreement and any repayments will be first applied to the $35.0 million increase prior to any other reductions in the original Revolving Credit Facility. This temporary increase was fully repaid and retired on July 5, 2007 with a portion of the proceeds from the issuance of the convertible unsecured subordinated debentures issued on this same date. Convertible Debentures In connection with the acquisition of the assets of Axxis on July 5, 2007 the Trust issued $354.3 million in convertible unsecured subordinated debentures, of which $325.0 million was issued through a public offering and $29.3 million was issued to former owners of Axxis. The debentures are convertible into units of the Trust at the option of the holder at any time prior to maturity at a conversion price of $19.30. They have a face value of $1,000, coupon rate of 7.75%, mature July 31, 2012 with interest being paid semi-annually on June 30 and December 31. The Trust has the option to redeem the debentures in whole or in part at a redemption price of $1,000 after December 31, 2010 and before their maturity date. On redemption or maturity, the Trust may elect to satisfy its obligation to repay the principal by issuing Trust units. The value of the conversion feature was determined to be $28.2 million and has been recorded as equity with the remaining $326.1 million allocated to long-term debt, net of $13.6 million of transaction costs. The debentures are being accreted such that the liability at maturity will equal the face value of $354.3 million. As at September 30, 2007 there were no conversions of these debentures. Interest on convertible debentures of $8.3 million represents accrued coupon payments of $6.6 million, $1.0 million pertaining to the accretion of the convertible debenture and $0.7 million pertaining to the effective interest on financing costs for the three and nine months ended September 30, 2007. 9. ACCUMULATED CASH DISTRIBUTIONS Pursuant to the Trust Indenture established on September 17, 2002, distributions are determined at the discretion of the Board of Directors. The intention of the Board of Directors is to provide stability to the monthly distributions based on anticipated cash flow; however, the actual amount of distributions paid by the Trust is subject to review by the Board of Directors, taking into account the prevailing financial and market circumstances of the Trust at the relevant time. ---------------------------------------------------------------------- Three months ended Nine months ended September 30, September 30, (thousands) 2007 2006 2007 2006 ---------------------------------------------------------------------- Accumulated cash distributions - beginning of period 247,557 132,715 189,984 84,509 Cash distributions 19,228 19,094 76,801 67,300 Distributions declared and payable 9,615 9,546 9,615 9,546 --------------------------------------------------- Accumulated cash distributions - end of period 276,400 161,355 276,400 161,355 --------------------------------------------------- 10. COMMITMENTS Rig Construction Program Trinidad has continued to focus on the expansion of its existing drilling fleet through its commitment to construct 34 new diesel electric drilling rigs which will be deployed in both Canada and the US. This construction program has enabled the Trust to actively pursue growth opportunities in the market and provide accretive growth to its unitholders. All of the rigs are backed by take-or-pay contracts which provide for committed drilling days and drilling rates over the next three to five years. Furthermore, the costs of construction on seven of these rigs have been partially financed through customer contributions, to be returned in equal payments over the term of the take-or-pay contract commencing upon the delivery of each rig. As of September 30, 2007, 31 of these rigs were completed, with the remaining scheduled to be completed and deployed in the fourth quarter of 2007 and substantially all the costs pertaining to the rig build program have been expended. In conjunction with the acquisition of the assets of Axxis the Trust has assumed the remaining construction commitments of a barge rig, of which $5.6 million had been spent as at the date of the acquisition and was reimbursed to the former owners of Axxis. Total capital costs of construction are expected to be $27.5 million of which $7.8 million was spent as of September 30, 2007. The barge rig is expected to be deployed in the second quarter of 2008. Bareboat Charters As a part of the Axxis acquisition the Trust entered into an Assignment Agreement in which the contracts to operate three barge rigs (the "Bareboat Charter" or "Charter") were transferred to the Trust. Under the Bareboat Charters, the Trust is committed to operate the rigs on behalf of a third party. In turn, as owners of the rigs, this third party is entitled to receive 25% of the Net Operating Revenues and 50% of the Net Margin earned under each Charter. Under the original agreement any earnings in excess of this payment were to be retained as compensation for the operation of the barge rigs however, as part of the purchase agreement the Trust committed to pay the former owners of Axxis US$12.5 million per year for the next three consecutive years, of which one-third of the payment, or US$4.2 million, shall be attributable to each of the three Bareboat Charters. This payment is contingent on the continued operation of the rigs and to the extent that the contract is terminated by the owners of the rigs, no further payments will be required. This fixed payment was structured to represent the residual earnings in excess of the payment to the third party owners; hence the Trust is exposed to minimal risk and rewards of the arrangement. In the instance that day rates or expenses fluctuate from the original provisions in the Bareboat Charters, the Trust is exposed to the residual gain or loss; however, it was determined the impact would be minimal. The Trust has disclosed all transactions pertaining to the Bareboat Charters on a net basis in accordance with EIC 123, Reporting Revenue Gross as a Principal versus Net as an Agent, for purposes of financial statement disclosure as the Trust does not bear the significant risks and rewards of the arrangement nor does it absorb the associated credit risk or asset risk. 11. SEGMENTED INFORMATION Since Trinidad first announced its intent to expand operations in 2005 into the US marketplace operations have been diversified from its primary geographic focus in Western Canada to include various locations in the United States, such that a significant portion of the Trust's operations are now driven from the US market. The acquisitions of Cheyenne Drilling and Axxis as well as the Trust's rig construction program added additional rigs of varying depths and capabilities to the drilling fleet operating in the Canadian market complementing the Trust's drilling operations. Despite the similarities in the assets acquired, the increased management depth in the United States and the varying conditions between the Canadian and United States market have resulted in management evaluating the Trust's drilling operations performance on a geographically segmented basis. In addition, the acquisition of Mastco in 2006 further broadened the operations of the Trust to include the capability to design, manufacture, sell and refurbish drilling rigs and related equipment. The unique characteristics of this subsidiary from the Trust's core drilling operations have resulted in management's separate evaluation of its results. Transactions between the segments are recorded at cost and have been eliminated upon consolidation. --------------------------------------------------------------------- Three months ended United September 30, Canadian States Inter- 2007 Drilling Drilling Construction segment (thousands) Operations Operations Operations Eliminations Total --------------------------------------------------------------------- Revenue 67,656 83,771 19,507 (8,751) 162,183 Operating expense 39,390 39,700 16,694 (8,751) 87,033 ----------------------------------------------------- Gross margin 28,266 44,071 2,813 - 75,150 Interest 4,051 3,107 16 - 7,174 Interest on convertible debentures 8,302 - - - 8,302 Depreciation and amortization 8,074 11,946 170 - 20,190 Loss (gain) on sale of assets 35 (4) - - 31 ----------------------------------------------------- Income before corporate items 7,804 29,022 2,627 - 39,453 General and administrative 14,949 Unit based compensation 508 Foreign exchange loss 5,394 Income taxes 3,559 ----------------------------------------------------- Net earnings 15,043 ----------------------------------------------------- Capital expenditures (including acquisitions and deposits) 11,324 186,745 63 - 198,132 --------------------------------------------------------------------- --------------------------------------------------------------------- Three months ended United September 30, Canadian States Inter- 2006 Drilling Drilling Construction segment (thousands) Operations Operations Operations Eliminations Total --------------------------------------------------------------------- Revenue 87,875 45,473 31,040 (13,763) 150,625 Operating expense 48,524 20,265 28,721 (13,763) 83,747 ----------------------------------------------------- Gross margin 39,351 25,208 2,319 - 66,878 Interest 3,324 3,054 10 - 6,388 Depreciation and amortization 7,995 5,836 145 - 13,976 Gain on sale of assets (1,992) (40) - - (2,032) ----------------------------------------------------- Income before corporate items 30,024 16,358 2,164 - 48,546 General and administrative 11,607 Unit based compensation 740 Foreign exchange gain (45) Income taxes 4,671 ----------------------------------------------------- Net earnings 31,573 ----------------------------------------------------- Capital expenditures (including acquisitions and deposits) 32,394 38,070 94 - 70,558 --------------------------------------------------------------------- --------------------------------------------------------------------- Nine months ended United September 30, Canadian States Inter- 2007 Drilling Drilling Construction segment (thousands) Operations Operations Operations Eliminations Total --------------------------------------------------------------------- Revenue 233,991 220,005 76,700 (46,808) 483,888 Operating expense 137,461 105,254 70,427 (46,808) 266,334 ----------------------------------------------------- Gross margin 96,530 114,751 6,273 - 217,554 Interest 15,559 9,683 42 - 25,284 Interest on convertible debentures 8,302 - - - 8,302 Depreciation and amortization 22,068 30,730 481 - 53,279 Loss on sale of assets 212 26 - - 238 ----------------------------------------------------- Income before corporate items 50,389 74,312 5,750 - 130,451 General and administrative 41,927 Unit based compensation 1,954 Foreign exchange loss 12,283 Income taxes 12,660 ----------------------------------------------------- Net earnings 61,627 ----------------------------------------------------- Capital expenditures (including acquisitions and deposits) 71,702 278,616 105 - 350,423 --------------------------------------------------------------------- --------------------------------------------------------------------- Nine months ended United September 30, Canadian States Inter- 2006 Drilling Drilling Construction segment (thousands) Operations Operations Operations Eliminations Total --------------------------------------------------------------------- Revenue 267,892 115,337 75,935 (41,055) 418,109 Operating expense 144,934 50,215 69,470 (41,055) 223,564 ----------------------------------------------------- Gross margin 122,958 65,122 6,465 - 194,545 Interest 8,218 5,374 148 - 13,740 Depreciation and amortization 22,258 14,220 309 - 36,787 Gain on sale of assets (1,944) (58) - - (2,002) ----------------------------------------------------- Income before corporate items 94,426 45,586 6,008 - 146,020 General and administrative 37,835 Unit based compensation 5,323 Foreign exchange loss 1,045 Income taxes 9,448 ----------------------------------------------------- Net earnings 92,369 ----------------------------------------------------- Capital expenditures (including acquisitions and deposits) 169,315 126,602 142 - 296,059 --------------------------------------------------------------------- --------------------------------------------------------------------- As at United September 30, Canadian States Inter- 2007 Drilling Drilling Construction segment (thousands) Operations Operations Operations Eliminations Total ------------------------------------------------------- Total assets 727,942 752,532 5,501 - 1,485,975 Goodwill 38,154 84,616 46,617 - 169,387 --------------------------------------------------------------------- --------------------------------------------------------------------- As at United December 31, Canadian States Inter- 2006 Drilling Drilling Construction segment (thousands) Operations Operations Operations Eliminations Total ------------------------------------------------------- Total assets 680,591 528,872 36,170 - 1,245,633 Goodwill 38,155 42,491 42,837 - 123,483 --------------------------------------------------------------------- 12. COMPARATIVE FIGURES Certain comparative figures have been reclassified to conform to the current year's presentation. Such reclassification did not impact previously reported net income or retained earnings.

For further information:

For further information: Michael Heier, Chairman & Chief Executive
Officer or Brent Conway, Chief Financial Officer, Phone: (403) 265-6525, Fax:
(403) 265-4168, E-mail: mbentley@trinidaddrilling.com

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Trinidad Drilling Ltd.

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