Technicoil Corporation
TSX : TEC

Technicoil Corporation

August 11, 2006 18:54 ET

Technicoil Corporation Announces Financial and Operating Results for the Second Quarter Ended June 30, 2006

CALGARY, ALBERTA--(CCNMatthews - Aug. 11, 2006) -

NOT FOR DISTRIBUTION INTO THE UNITED STATES OR TO UNITED STATES WIRE SERVICES

Technicoil Corporation (TSX:TEC) - This news release contains forward-looking information within the meaning of applicable securities laws. Forward-looking information may include estimates, plans expectations, forecasts, guidance or other statements that are not statements of fact. Such information, although considered reasonable by Technicoil Corporation ("Technicoil" or the "Corporation") at the time of preparation is subject to certain risks and uncertainties and may prove to be incorrect and actual results may differ, possibly materially, from expectations. The reader should be aware that historical results are not necessarily indicative of future performance. The Corporation does not undertake an obligation to update its forward-looking statements except as required by law.



SUMMARY

Three months Six months
($ thousands except per share data) ended June 30 ended June 30
(unaudited) 2006 2005 2006 2005
------------------------------------------------------------------------
------------------------------------------------------------------------
Number of rigs owned as at June 30 24 11 24 11
Average number of rigs available
during the period 24.0 9.4 23.4 9.2
Revenue $ 6,281 $ 6,090 $ 23,953 $ 13,312
Gross margin $ 1,211 $ 2,197 $ 9,474 $ 4,445
Gross margin % 19% 36% 40% 33%
General and administrative expenses $ 1,070 $ 818 $ 2,221 $ 1,482
EBITDA(1) $ 141 $ 1,379 $ 7,253 $ 2,963
Net income $ (272)$ 414 $ 3,244 $ 1,070
Earnings per share - basic $ 0.00 $ 0.01 $ 0.06 $ 0.02
Earnings per share - diluted $ 0.00 $ 0.01 $ 0.06 $ 0.02
Funds flow from operations $ 1,307 $ 1,492 $ 7,202 $ 2,970
------------------------------------------------------------------------

June December
30, 31,
2006 2005
------------------------------------------------------------------------
Total assets $ 90,015 $ 82,958
Long-term financial liabilities $ 14,800 $ 7,500
Debt to equity ratio (2) 0.57 0.55
------------------------------------------------------------------------
------------------------------------------------------------------------
1. EBITDA, or earnings before interest, taxes, depreciation and
amortization, is considered to be a non-GAAP measure that does not
have a standardized meaning prescribed by GAAP and therefore may not
be comparable to similar measures presented by other issuers.
Management believes EBITDA is useful for providing investors with a
measure of results generated by the Corporation's principal business
activities prior to consideration of how these activities are
financed, taxed or depreciated.

2. Debt to equity ratio is defined as total liabilities, including
current liabilities, long-term debt and future income taxes, divided
by shareholders' equity. Debt to equity ratio is a non-GAAP measure
that does not have a standardized meaning prescribed by GAAP, and
therefore may not be comparable to similar measures presented by
other issuers.


HIGHLIGHTS

Coming off a busy first quarter which saw drilling and service activities extend until the end of March, spring break-up arrived at the beginning of April with road bans remaining in effect until the end of May in many of the locations where the Corporation's drilling and fracturing rigs operate. Activity levels increased at the conclusion of this extended spring break-up period but were interrupted in mid June due to wet ground conditions in southern Alberta caused by rainfall. These weather related delays, combined with lower natural gas prices and regulatory delays in Coal Bed Methane ("CBM") well licensing, contributed to lower industry activity during the quarter compared to the second quarter of 2005 and resulted in the lowest number of shallow gas wells drilled by the industry in the Western Canadian Sedimentary Basin during the period of April to June since 1999 (source: Daily Oil Bulletin). As a result, despite operating a larger fleet of drilling and fracturing rigs in the second quarter of 2006 versus the second quarter of 2005, total revenue only increased by 3% to $6.3 million in the quarter over the second quarter of 2005. Gross margin as a percentage of revenue and EBITDA(1) declined to 19% and $0.1 million, respectively, in the quarter versus 36% and $1.4 million in the second quarter of 2005 due to lower utilization in the current quarter and higher annual spring maintenance costs in the Corporation's drilling division this year as a result of having a larger rig fleet than in 2005.

Despite the lower gross margins and EBITDA(1) in the quarter compared to the second quarter of 2005, funds flow from operations decreased by only $0.2 million over the same period to $1.3 million due to a reduction in current income tax expense. Current income tax expense was positively impacted by higher tax deductions associated with increased tax depreciation from the Corporation's 2005 capital expansion program being claimed in the second quarter of 2006 versus the second quarter of 2005. The Corporation also benefited from a reduction in federal and provincial corporate income tax rates enacted during the quarter which resulted in a one-time future income tax recovery of $0.9 million being recorded into net income in the quarter. The corporate income tax rate reductions enacted during the quarter will reduce the Corporation's corporate income tax rate by 4.6% by 2010. This positive tax adjustment partially offset lower operating results, however, this adjustment was not sufficient to fully offset the lower results and the Corporation realized a $0.3 million loss during the quarter versus reporting $0.4 million in net income, or $0.01 per share, in the second quarter of 2005.

On a year to date basis, the Corporation has benefited from the expansion in its fracturing and drilling businesses undertaken in 2005 resulting in revenue increasing by 80% over the first six months of 2005 to $24.0 million. In addition, as a result of the increased economies of scale, the Corporation has generated a 145% increase in EBITDA(1) to $7.3 million and a 203% increase in net income to $3.2 million in the first six months of 2006 versus the comparable period in 2005.



RESULTS OF OPERATIONS

FRACTURING OPERATIONS

------------------------------------------------------------------------
Three months ended June 30 %
($ thousands) (unaudited) 2006 2005 Variance Change
------------------------------------------------------------------------
------------------------------------------------------------------------
Fracturing revenue $ 3,061 $ 4,529 ($1,468) (32%)
Operating expenses 2,377 2,376 1 0%
------------------------------------------------------------------------
Gross margin $ 684 $ 2,153 ($1,469) (68%)
Gross margin % 22% 48% (26%) (54%)
Utilization % 13% 49% (36%) (73%)
Average number of rigs available
during the period 18.0 7.0 11.0 157%
Number of wells completed 279 446 (167) (37%)
------------------------------------------------------------------------
------------------------------------------------------------------------


------------------------------------------------------------------------
Six months ended June 30 %
($ thousands) (unaudited) 2006 2005 Variance Change
------------------------------------------------------------------------
------------------------------------------------------------------------
Fracturing revenue $ 10,351 $ 9,209 $ 1,142 12%
Operating expenses 6,410 5,325 1,085 20%
------------------------------------------------------------------------
Gross margin $ 3,941 $ 3,884 $ 57 1%
Gross margin % 38% 42% (4%) (10%)
Utilization % 24% 51% (27%) (53%)
Average number of rigs available
during the period 17.4 7.0 10.4 149%
Number of wells completed 849 847 2 0%
------------------------------------------------------------------------
------------------------------------------------------------------------


Fracturing revenue decreased by 32% to $3.1 million in the quarter compared to $4.5 million in the second quarter of 2005. The extended spring break-up and weather related delays in June, combined with low natural gas prices and regulatory delays in CBM well licensing, negatively impacted the Corporation's fracturing operations during the quarter. Although similar weather related delays were experienced in June 2005, significantly higher activity levels were attained in May 2005 due to high industry demand and a shorter spring break-up period. In addition to a decline in overall shallow gas activity levels during the quarter, the Corporation also experienced a decline in the number of CBM wells being fractured as a percentage of total wells fractured by the Corporation. CBM well fracturing accounted for 26% of the wells fractured by the Corporation in the second quarter of 2006 versus 32% in the second quarter of 2005. This decline is largely due to oil and gas exploration and development companies curtailing their CBM well programs in light of the lower natural gas price environment combined with delays caused by increased regulatory requirements for CBM wells. Over the last twelve months, CBM wells have accounted for 46% of the Corporation's fracturing activity.

As a result of the above factors, the Corporation's fracturing rigs attained a utilization percentage of only 13% for the quarter versus 49% in the second quarter of 2005. On a year to date basis, the Corporation's fracturing rigs have averaged 24% utilization versus 51% in 2005. Utilization levels in the first six months of 2005 were higher than 2006 as a result of high industry demand for shallow natural gas in 2005 combined with the Corporation operating a smaller rig fleet to service this high demand.

Activity levels increased at the end of June, and from the period of July 1 to August 11, 2006, the Corporation's fracturing rigs have averaged approximately 38% utilization. Reduced shallow gas activities continue to hamper utilization levels. However, the Corporation has taken steps to improve utilization of its fracturing rig fleet through expansion into other traditional well servicing activities, including, well cleanouts and stimulations. In addition, subsequent to quarter end, the Corporation decided to delay the construction of two of its six new fracturing rigs and reallocate a similar amount of capital to the construction of a new coiled tubing drilling rig. The delay in construction of these new fracturing rigs is in response to decreased industry activity levels for shallow natural gas and CBM well fracturing. The Corporation will re-evaluate its fracturing rig capital expansion at a later date once industry activity levels increase or as other opportunities arise.

The decrease in revenue is primarily related to activity levels as pricing remained approximately 8% higher on an average revenue per well basis and averaged $10,971 for the quarter versus $10,155 for the second quarter of 2005. On a year to date basis, the average revenue per well has averaged $12,191 in the first six months of 2006 versus $10,872 in the comparable period of 2005. The average revenue per well was higher in the first quarter of 2006 due to a greater proportion of the fractured wells being deeper during the quarter, which attracted additional revenue. This increased average revenue rate combined with additional services has allowed the Corporation to increase its total revenue in the fracturing division by 12% to $10.4 million for the first six months of 2006 versus the first six months of 2005. This increase has been achieved while only fracturing two more wells in the period.

The Corporation's gross margin from fracturing activities decreased to $0.7 million in the quarter versus $2.2 million in the second quarter of 2005. This decrease is due to reduced fracturing activity levels during the quarter, which were not sufficient enough to significantly offset higher fixed operating costs. Fixed operating costs increased to $0.7 million in the second quarter of 2006 versus $0.5 million in the second quarter of 2005. This increase in fixed overhead costs is due to the expansion of the Corporation's fracturing business operations subsequent to the second quarter of 2005. On a year to date basis, fixed operating costs for the fracturing division were $1.3 million versus $1.0 million for the first six months of 2005. Although the rig fleet was larger in the current quarter, annual maintenance costs were not proportionately higher due to the majority of the fracturing rigs being added to the fleet late in the fourth quarter of 2005, thus the equipment was new and required minimal annual maintenance in the current year. The sporadic activity during the quarter contributed to inefficient operations which also negatively impacted margins during the quarter.

As a result of the lower margins in the quarter, the year to date gross margin percentage decreased to 38% versus 42% for the first six months of 2005. Margins are expected to increase to historical levels once activity rates recover following the Corporation's traditionally slow second quarter period.



DRILLING OPERATIONS

------------------------------------------------------------------------
Three months ended June 30 %
($ thousands) (unaudited) 2006 2005 Variance Change
------------------------------------------------------------------------
------------------------------------------------------------------------
Drilling revenue $ 3,220 $ 1,561 $ 1,659 106%
Operating expenses 2,693 1,517 1,176 78%
------------------------------------------------------------------------
Gross margin $ 527 $ 44 $ 483 1,098%
Gross margin % 16% 3% 13% 433%
Utilization % 25% 43% (18%) (42%)
Average number of rigs available
during the period 6.0 2.4 3.6 150%
Number of wells completed 56 40 16 40%
------------------------------------------------------------------------
------------------------------------------------------------------------


------------------------------------------------------------------------
Six months ended June 30 %
($ thousands) (unaudited) 2006 2005 Variance Change
------------------------------------------------------------------------
------------------------------------------------------------------------
Drilling revenue $ 13,602 $ 4,103 $ 9,499 232%
Operating expenses 8,069 3,542 4,527 128%
------------------------------------------------------------------------
Gross margin $ 5,533 $ 561 $ 4,972 886%
Gross margin % 41% 14% 27% 193%
Utilization % 56% 57% (1%) (2%)
Average number of rigs available
during the period 6.0 2.2 3.8 173%
Number of wells completed 214 86 128 149%
------------------------------------------------------------------------
------------------------------------------------------------------------


Similar to the fracturing division, the drilling division was negatively impacted by an extended spring break-up and wet weather in June. Despite having an increased drilling fleet in the second quarter of 2006 versus 2005, the Corporation was only able to drill 16 more wells in the current quarter versus the same period in 2005. Low natural gas prices resulted in oil and gas exploration and development companies curtailing their shallow gas drilling activities during the quarter. In addition, regulatory delays in CBM well licensing impacted CBM well drilling activities and contributed to a decline in the percentage of CBM wells drilled by the Corporation in the second quarter of 2006 to nine percent from 30% in the first quarter of 2006. Over the last 12 months, CBM wells have accounted for 20% of the Corporation's drilling activity. As a result of the lower activity, utilization of the Corporation's drilling rigs decreased to 25% in the quarter versus 43% in the second quarter of 2005.

Despite drilling only 16 more wells in the quarter versus the second quarter of 2005, drilling revenue increased by 106% to $3.2 million in the quarter compared to $1.6 million in the second quarter of 2005. This revenue growth is due primarily to an increase in the average day rate to $23,668 per operating day versus $17,156 per operating day in the second quarter of 2005. Pricing was skewed higher in the quarter by approximately $3,000 per day due to higher than normal third party pass-through items such as rig transportation, fuel and other ancillary items. Due to the extended winter drilling season, some of the Corporation's rigs were not moved from location until early April. The revenue associated with these moves thus had a larger impact on revenue per operating day as a result of the lower number of operating days in the second quarter due to spring break-up.

The Corporation's drilling gross margin increased by 1,098% in the quarter to $0.5 million. This increase exceeds the 106% increase in revenue over the same period as the division benefited from improved operating performance of the Corporation's drilling rigs and greater economies of scale with the larger rig fleet. Gross margin as a percentage of revenue was 16% in the quarter compared to 3% in the second quarter of 2005. Similar to the fracturing division, margins were negatively impacted in the quarter by lower industry activity, resulting in fixed costs becoming a larger percentage of the division's total operating costs. Fixed operating costs were $0.2 million in the second quarter which is consistent with the second quarter of 2005 as the expansion of the infrastructure to support the Corporation's drilling business was largely in place by the second quarter of 2005. On a year to date basis, fixed operating costs for the drilling division are $0.5 million versus $0.4 million for the first six months of 2005. During the quarter, $0.6 million was incurred for annual equipment re-certifications and preventative maintenance versus $0.1 million spent in the second quarter of 2005. The higher costs are due to the increased size of the rig fleet. The sporadic activity during the quarter contributed to inefficient operations which also negatively impacted margins during the quarter.

As a result of the larger fleet and strong demand from customers for the Corporation's rigs, revenue has increased 232% to $13.6 million in the first six months of 2006 versus the comparable period in 2005. In addition, the larger fleet has provided the drilling division with greater economies of scale and has allowed the Corporation's drilling rigs to improve gross margin by 886% to $5.5 million.

The Corporation continues to receive strong demand from customers for its drilling rigs. As a result of this demand and a desire to further improve economies of scale for the Corporation's drilling division, subsequent to quarter end, the Corporation placed an order for one new coiled tubing drilling rig to be delivered late in the second quarter of 2007. Other than minor design improvements, this rig will be similar to the drilling rigs added to the fleet in 2005. The estimated cost for this rig is approximately $7.0 million and will be funded by capital previously allocated to the two delayed fracturing rigs and by operating cash flow.

General and Administrative Expenses

General and administrative expenses increased by 31% to $1.1 million in the quarter from $0.8 million in the second quarter of 2005 and by 50% to $2.2 million in the first six months of 2006 from $1.5 million in the first six months of 2005. The increase is due to the larger organization in the current year versus the prior year. As a result of the larger organization combined with moderate second quarter revenue, general and administrative expenses as a percentage of revenue increased to 14% of revenue in the quarter compared to 13% in the second quarter of 2005. On a year to date basis, general and administrative expenses as a percentage of revenue have averaged 9% versus 11% in 2005.

Depreciation

Depreciation expense increased by 167% to $1.6 million in the quarter from $0.6 million in the second quarter of 2005 and is $3.0 million year to date versus $1.2 million in the first six months of 2005. This increase is consistent with the increase in depreciable assets over the same period due to the addition of two new drilling rigs and 11 new fracturing rigs since the second quarter of 2005.

Interest, Foreign Currency and Taxes

The Corporation incurred $0.2 million of interest expense in the quarter as the Corporation drew on its long-term debt facilities to fund its 2005 and 2006 capital additions. On a year to date basis, the Corporation has incurred $0.4 million of interest expense.

The Corporation realized a nominal foreign exchange loss in 2006 due to unfavorable changes in the exchange rates at the time of payment of invoices for U.S. dollar denominated payables outstanding for equipment purchases. The Corporation's operations are based in Canada, therefore, it has limited exposure to foreign currency risk at this time.

During the quarter the Corporation recorded a one-time $0.9 million reduction to its future income tax expense as a result of corporate tax rate reductions enacted during the quarter by the federal and provincial governments. In addition, the Corporation's negative pretax income and high tax depreciation deductions related to the Corporation's increased rig fleet resulted in a $1.1 million current income tax recovery this quarter. On a year to date basis, the Corporation's effective tax rate is only 16% however, if the impact of the one-time future income tax adjustment is removed, the Corporation's effective tax rate is 39% in the first six months of 2006 versus 41% in the first six months of 2005. The effective tax rate decrease over the prior year is due to stock-based compensation expense, a non-deductible expense for tax purposes, decreasing from 22% of pre-tax income in the first six months of 2005 to 14% of the Corporation's pre-tax income in the first six months of 2006.

LIQUIDITY AND CAPITAL RESOURCES

The Corporation ended the quarter with $4.5 million in cash and $18.4 million in total long-term debt compared to $3.0 million in cash and $9.0 million in total long-term debt as at December 31, 2005. The increased debt is a result of funding for the Corporation's 2005 capital expansion program and initial payments on its 2006 capital expenditures.

Although net income decreased by 166% during the quarter, funds flow from operations decreased by only 12% to $1.3 million in the quarter versus $1.5 million in the second quarter of 2005. Funds flow from operations benefited from low current tax expense in the quarter as a result of higher tax deductions associated with increased tax depreciation from the Corporation's 2005 capital expansion program being claimed in the second quarter of 2006. In addition, with the larger rig fleet in the current year, an additional $1.0 million of depreciation expense was recorded in the quarter versus the second quarter of 2005. While this increased depreciation expense reduced net income, it had no impact on funds flow from operations as it is a non-cash expense. On a year to date basis, the Corporation has generated $7.2 million in funds flow from operations versus $3.0 million in the first six months of 2005. This 142% increase is due to the expansion of the Corporation's business and strong operating performance of the Corporation's drilling fleet in the first six months of 2006 versus the comparable period in 2005.

Property, plant and equipment expenditures for the quarter were $4.8 million and primarily related to construction of the first two rigs of the Corporation's four new fracturing rigs to be delivered in 2006. The Corporation took delivery of the first rig during the third week of July and the remaining rigs are expected to be delivered on a schedule of one per month from August to October. As discussed previously, subsequent to the end of the quarter the Corporation decided to delay construction of the final two fracturing rigs from it's previously announced six fracturing rig expansion program. Of the estimated $5.6 million total capital cost for these two fracturing rigs, the Corporation has already incurred approximately $1.0 million in expenditures related to ancillary equipment for these final two rigs. However, the majority of this equipment can be utilized in the conversion of the Corporation's body style rigs to trailer rigs or in current operations. The remaining $4.6 million to construct these final two fracturing rigs will no longer be incurred in 2006 as a result of the delay in construction of these rigs. Subsequent to quarter end, the Corporation also placed an order to construct one new drilling rig for delivery late in the second quarter of 2007. As a result of these capital reallocations, the Corporation anticipates spending $21.0 million in capital expenditures for 2006. The Corporation expects to fund these expenditures through its existing debt facilities and cash flow.

Proceeds from the exercise of stock options provided nominal cash inflows in the quarter. As at June 30, 2006, the Corporation had 57,836,853 common shares issued and outstanding. The Corporation also had 2,768,001 stock options issued and outstanding of which 1,292,332 were vested. No new stock options have been issued subsequent to June 30, 2006.

RISKS AND UNCERTAINTIES

A complete discussion on the business risks faced by the Corporation can be found in Technicoil's annual report for the year ended December 31, 2005, and the Corporation's Annual Information Form dated March 16, 2006, each of which are available on SEDAR.
OUTLOOK AND FUTURE RISKS

As an oilfield services company, the Corporation is dependent on the capital spending of its customers, with the whole oil and gas industry largely influenced by current and anticipated future crude oil and natural gas prices. The oil and gas industry activity benefited from high crude oil and natural gas prices throughout 2005 and this high commodity price continued into the first quarter of 2006. However, subsequent to the first quarter of 2006, the AECO natural gas spot price declined to levels not seen since 2004. This decline has had a negative impact on cash flows for some oil and gas exploration companies resulting in some of those companies reducing their capital expenditure programs or reallocating their capital investments into projects other than shallow natural gas projects. These revised capital investments combined with regulatory delays in CBM well licensing has resulted in the lowest number of shallow gas wells to be drilled in the Western Canadian Sedimentary Basin during the period of April to June since 1999. While activity levels have increased early into the Corporation's traditionally busy third quarter period, utilization levels for the Corporation's rigs still remain lower than historical averages. From the period of July 1 to August 11, 2006, utilization of the Corporation's fracturing rigs has averaged approximately 38%, with the drilling rigs averaging approximately 44%. During the prior two years the Corporation averaged 59% and 67% utilization for its fracturing and drilling rigs, respectively, in the third quarter.

While the Corporation has been successful in maintaining a reasonable utilization of its drilling equipment during this slower period and the Corporation's fracturing customers continue to indicate strong activity levels for fracturing services into the near future, further softening in natural gas prices could have a significant negative impact on activity levels and or services pricing in the industry. Current consensus appears to indicate that the current low gas price levels are short-term as futures contracts for winter gas prices remain strong. In addition, natural gas pricing has begun to strengthen in August due to strong demand caused by increased electricity use for cooling systems in the United States as a result of abnormally warm summer temperatures. However, a number of factors such as increasing natural gas storage levels and the possibility of a warm winter could result in a decline in winter prices and thus a further decline in natural gas drilling and services activities and revenue rates.

While management is cautious about reduced activity levels over the next six to 12 months caused by soft natural gas prices, management believes a number of factors such as increasing demand for natural gas from users such as oil sands producers and rapid decline curves for natural gas production in the Western Canadian Sedimentary Basin will result in a rebalancing of the supply and demand relationship for natural gas and should result in a return to stronger natural gas prices within the next 12 months. This opinion appears to be generally shared by analysts in the industry as gas price forecasts remain strong for 2007 and industry drilling activity forecasts remain high for 2007.

In the meantime, management continues to expand its customer base for both its fracturing and drilling operations and is focusing on diversifying its business operations beyond its traditional shallow natural gas market. This diversification strategy includes expansion into traditional well servicing activities and participation in heavy oil drilling projects. While the majority of the Corporation's business activities will still be focused on shallow natural gas activities, these initiatives will assist in improving utilization for the Corporations rigs during the current temporary slow down in the shallow natural gas industry. Management believes that through its recent equipment expansion and strong relationships with its customers, the Corporation is well positioned to benefit from the eventual increase in shallow natural gas activities.

In addition to expanding service offerings with the Corporation's existing fleet, the Corporation continues to seek and evaluate acquisition opportunities which will further expand and diversify the Corporation's business operations. However, the decline of the Corporation's share price in the current year is presently an impediment to the Corporation's acquisition strategies.



Consolidated BALANCE SHEETS

------------------------------------------------------------------------
(Thousands) June 30, 2006 December 31, 2005
------------------------------------------------------------------------
(unaudited)
Assets
Current assets:
Cash and cash equivalents $ 4,486 $ 2,979
Accounts receivable 6,045 8,308
Income taxes receivable 1,194 897
Inventory 1,860 1,144
Prepaid expenses 923 535
------------------------------------------------------------------------
14,508 13,863
Property, plant and equipment 75,507 69,095
------------------------------------------------------------------------
$ 90,015 $ 82,958
------------------------------------------------------------------------
------------------------------------------------------------------------

Liabilities and Shareholders' Equity
Current liabilities:
Accounts payable and accrued
liabilities $ 8,840 $ 15,444
Current portion of long-term debt 3,600 1,500
------------------------------------------------------------------------
12,440 16,944
Long-term debt 14,800 7,500
Future income taxes 5,509 5,155
------------------------------------------------------------------------
32,749 29,599
------------------------------------------------------------------------

Shareholders' equity
Share capital 38,584 38,445
Contributed surplus 1,797 1,273
Retained earnings 16,885 13,641
------------------------------------------------------------------------
57,266 53,359
------------------------------------------------------------------------
$ 90,015 $ 82,958
------------------------------------------------------------------------
------------------------------------------------------------------------


Consolidated Statements
of
OPERATIONS and RETAINED EARNINGS

------------------------------------------------------------------------
Three Three Six Six
Months Months Months Months
(Thousands, except Ended Ended Ended Ended
per share data) June 30, June 30, June 30, June 30,
(unaudited) 2006 2005 2006 2005
------------------------------------------------------------------------

Coil tubing service and
drilling revenue $ 6,281 $ 6,090 $ 23,953 $ 13,312
Operating expenses 5,070 3,893 14,479 8,867
------------------------------------------------------------------------
Gross margin 1,211 2,197 9,474 4,445
General and administrative
expenses 1,070 818 2,221 1,482
Depreciation 1,558 638 3,049 1,223
Gain on sale of assets - - - (8)
Interest on long-term debt 235 1 382 1
Other interest income (29) (35) (33) (103)
Foreign exchange (gain)
loss (1) 23 6 54
------------------------------------------------------------------------

Net (loss) income before
income tax (1,622) 752 3,849 1,796

Income tax (recovery)
expense:
Current (1,119) 127 251 435
Future (231) 211 354 291
------------------------------------------------------------------------
(1,350) 338 605 726
------------------------------------------------------------------------

Net (loss) income for the
period (272) 414 3,244 1,070

Retained earnings,
beginning of period 17,157 9,993 13,641 9,337
------------------------------------------------------------------------

Retained earnings, end of
period $ 16,885 $ 10,407 $ 16,885 $ 10,407
------------------------------------------------------------------------
------------------------------------------------------------------------

Earnings per share
Basic $ 0.00 $ 0.01 $ 0.06 $ 0.02
Diluted $ 0.00 $ 0.01 $ 0.06 $ 0.02
------------------------------------------------------------------------
------------------------------------------------------------------------


Consolidated Statements
of
CASH FLOWS

------------------------------------------------------------------------
Three Three Six Six
Months Months Months Months
Ended Ended Ended Ended
(Thousands) June 30, June 30, June 30, June 30,
(unaudited) 2006 2005 2006 2005
------------------------------------------------------------------------
Cash provided by (used in):
Operating activities:
Net income for the period $ (272) $ 414 $ 3,244 $ 1,070
Add (deduct) non-cash
items:
Depreciation 1,558 638 3,049 1,223
Gain on sale of assets - - - (8)
Stock-based compensation
expense 252 229 555 394
Future income tax (231) 211 354 291
------------------------------------------------------------------------
Funds flow from operations 1,307 1,492 7,202 2,970
Net change in non-cash
working capital from
operations 6,988 (2,794) 621 (4,598)
------------------------------------------------------------------------
Cash flow from operating
activities 8,295 (1,302) 7,823 (1,628)
------------------------------------------------------------------------
Financing activities:
Common shares issued 39 25 108 277
Proceeds from long-term
debt 3,000 1,700 10,500 1,700
Repayment of long-term debt (825) - (1,100) -
------------------------------------------------------------------------
Cash flow from financing
activities 2,214 1,725 9,508 1,977
------------------------------------------------------------------------
Investing activities:
Acquisition of property,
plant and equipment (4,830) (10,773) (9,466) (17,017)
Proceeds on sale of
property, plant and
equipment - - 5 25
Net change in non-cash
working capital from the
purchase of property, plant
and equipment (3,223) 681 (6,363) 993
------------------------------------------------------------------------
Cash flow from investing
activities (8,053) (10,092) (15,824) (15,999)
------------------------------------------------------------------------
Net increase (decrease) in
cash and cash
equivalents 2,456 (9,669) 1,507 (15,650)
Cash and cash equivalents,
beginning of period 2,030 9,826 2,979 15,807
------------------------------------------------------------------------
Cash and cash equivalent,
end of period $ 4,486 $ 157 $ 4,486 $ 157
------------------------------------------------------------------------
------------------------------------------------------------------------

------------------------------------------------------------------------
Cash interest paid $ 228 - $ 367 -
Cash income taxes paid $ 225 $ 556 $ 450 $ 2,539
------------------------------------------------------------------------
------------------------------------------------------------------------



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