Phoenix Technology Income Fund
TSX : PHX.UN

Phoenix Technology Income Fund

February 27, 2008 21:02 ET

Phoenix Reports Record Revenue and Activity for the Year Ended December 31, 2007 and Reports on Financial Results for the Three-Month Period and Year Ended December 31, 2007

CALGARY, ALBERTA--(Marketwire - Feb. 27, 2008) - Phoenix Technology Income Fund (TSX:PHX.UN) -



FINANCIAL HIGHLIGHTS

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Stated in thousands
of dollars except per
unit amounts, Three-months
percentages and units ended December 31 Years ended December 31
outstanding 2007 2006 % Chg. 2007 2006 % Chg.
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Operating Results
Revenue 31,018 28,882 7 115,548 99,346 16
Net earnings 5,281 6,273 (16) 18,214 20,638 (12)
Earnings per unit
diluted 0.23 0.28 (18) 0.81 0.92 (12)
EBITDA (1) 7,279 8,608 (15) 26,533 29,950 (11)
EBITDA per unit
diluted (1) 0.32 0.38 (16) 1.18 1.34 (12)
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Cash Flow
Cash flows from
operating activities 9,608 8,797 9 26,103 25,941 1
Distributable cash(1) 7,904 8,402 (6) 29,421 28,909 2
Distributable cash
per unit diluted (1) 0.35 0.37 (5) 1.31 1.29 2
Cash distributions
made 4,372 4,343 1 17,434 16,326 7
Cash distributions
per unit (2) 0.195 0.195 - 0.780 0.735 6
Cash payout ratio
(1) 55% 52% 59% 56%
Capital expenditures 3,449 2,222 55 14,610 12,750 15
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Dec 31, Dec 31,
Financial Position 2007 2006
Working capital 15,800 19,611 (19)
Long-term debt 1,775 1,775 -
Unitholders equity 59,860 58,908 2
Fund units
outstanding 22,434,044 22,274,773 1
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(1) Refer to the Non-GAAP measures section.

(2) Cash distributions made on a per unit basis in the year.


Non-GAAP measures

The Fund uses certain performance measures that are not recognizable under Canadian generally accepted accounting principles ("GAAP"). These performance measures include, earnings before interest, taxes, depreciation and amortization ("EBITDA"), EBITDA per unit, distributable cash, distributable cash per unit, and cash distributions per unit. Management believes that these measures provide supplemental financial information that is useful in the evaluation of the Fund's operations. Investors should be cautioned, however, that these measures should not be construed as alternatives to measures determined in accordance with GAAP as an indicator of Phoenix's performance. Phoenix's method of calculating these measures may differ from that of other organizations and, accordingly, these may not be comparable. Please refer to the Non-GAAP measures section.

RESULTS OF OPERATIONS

For the year ended December 31, 2007 revenue increased to a record $115.5 million, or by 16 percent, from $99.3 million for the 2006-year. The Canadian and US regions both reported record activity levels in 2007 that resulted in consolidated MWD operating days increasing by 14 percent to 10,020 days, as compared to 8,788 days in 2006. Phoenix continued to add customers and diversify its client base in 2007 whereby the top client of the Fund represented only eight percent of consolidated revenue.

In 2007, the Fund's overall revenue growth was driven through its US operations. Weak natural gas prices adversely affected overall natural gas drilling in Canada, but in spite of this the Fund realized a modest increase in its Canadian activity. In Canada, day rates declined in 2007 due to the lower level of industry activity where as US day rates strengthened due to increased activity in the American marketplace.

Phoenix, in 2007, continued to have strong geographical diversification with 48 percent of its annual revenue generated from US operations. In addition, the Fund had a good level of diversification between oil and natural gas well drilling services. Phoenix's drilling activity in the US was predominantly centered on natural gas wells. In contrast, the drilling of oil wells represented approximately 45 percent of the Fund's overall Canadian activity in 2007.

Oil prices in 2007 increased steadily throughout the year, with the most significant rise occurring during the last quarter. The average 2007 oil price, as measured by West Texas Intermediate on NYMEX, increased to US $72 per Bbl from US $66 per Bbl in 2006, an increase of nine percent. In comparison, during the fourth quarter of 2007 oil prices averaged approximately US $91 per Bbl. Average natural gas prices, as measured by the NYMEX Henry Hub, increased by four percent from US $6.72 per mmbtu in 2006 to US $6.97 per mmbtu in 2007. However, natural gas prices in the third quarter of 2007 were lower where prices averaged only US $6.18 per mmbtu. (Source: Tudor Pickering Holt & Co)

Consolidated revenue for the three-month period ended December 31, 2007 increased by seven percent to $31.0 million from $28.9 million in the corresponding 2006 period. This revenue level was the second best quarterly result for the Fund.

For the year ended December 31, 2007 net earnings decreased to $18.2 million, $0.81 per unit diluted, as compared to $20.6 million, $0.92 per unit diluted in 2006. EBITDA was $26.5 million, $1.18 per unit diluted, for the year ended December 31, 2007 compared to $30.0 million, $1.34 per unit diluted, in 2006. The Fund's levels of net earnings and EBITDA for the 2007-year were both impacted by lower margins and higher SG&A costs, and bad debt provisions of $1.7 million. The bad debt provisions equate to an earnings per unit amount of $0.05 on a dilutive basis. If the bad debt provisions were excluded, the 2007 period's EBITDA as a percentage of revenue would increase from 23 percent to 24 percent.

Net earnings for the three-month period ended December 31, 2007 decreased by 16 percent to $5.3 million, $0.23 per unit diluted, compared to $6.3 million, $0.28 per unit diluted, for the prior year's period. For the three-month period ended December 31, 2007, EBITDA decreased to $7.3 million, $0.32 per unit diluted, compared to $8.6 million, $0.38 per unit diluted, in 2006.

Distributions to unitholders for the year ended December 31, 2007 was $17.4 million, or $0.78 per unit, as compared to $16.3 million, or $0.735 per unit, in 2006. The resulting cash payout ratio in 2007 was 59 percent compared to 56 percent in 2006. Distributable cash for the year ended December 31, 2007 increased by two percent over 2006 to a record of $29.4 million.

As at December 31, 2007 the Fund had working capital of $15.8 million, which was $3.8 million lower than the $19.6 million reported at December 31, 2006. In 2007, working capital was used to finance a portion of the Fund's capital expenditures, which in aggregate in 2007 totaled $14.6 million. The continued capital investment was made for both increased job capacity expansion and increased profitability through the minimization of third-party equipment rentals.

Phoenix's job capacity increased by four in 2007 to 90 concurrent jobs through the addition of one current loop telemetry ("CLT") electromagnetic ("EM") measurement while drilling ("MWD") system and three positive pulse MWD systems. An additional four CLT EM-MWD systems that were originally expected to be placed in service in the last quarter of 2007 were delayed into 2008. After taking into consideration these four additional systems, the Fund's MWD fleet will be comprised of 50 CLT EM-MWD systems and 44 positive pulse MWD systems, of which 56 systems will be stationed in Canada with the balance in the US. In order to meet the expected increase in customer demand the Fund plans to add another eight CLT EM-MWD systems and six positive pulse MWD systems to its fleet in 2008, which would bring the Fund's total job capacity to 108 concurrent jobs.

The Fund did not complete any business acquisitions in 2007 nor 2006. The Fund has strategically positioned itself to generate future internal growth through continued US marketing personnel expansion and research and development activities.

REVENUE

The Fund reports one operating segment on a geographical basis throughout the western Canadian provinces of Alberta, Saskatchewan and British Columbia and throughout the Gulf Coast, Northeast and Rocky Mountain regions of the US.



(stated in thousands Three-month period ended
of dollars) December 31, Year ended December 31,
2007 2006 % Change 2007 2006 % Change
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Canada 16,057 16,332 -2% 60,092 59,602 1%
United States 14,961 12,550 19% 55,456 39,744 40%
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31,018 28,882 7% 115,548 99,346 16%
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CANADIAN REVENUE

For the year ended December 31, 2007 the Fund's Canadian revenue increased by one percent to a record $60.1 million from $59.6 million in 2006. In 2007, many natural gas exploration and production companies cut back on their natural gas drilling programs due to poor drilling economics or difficulties they encountered in obtaining project financing. As a result, horizontal and directional drilling activity in the western Canadian industry in 2007 was one percent lower than that in 2006. During 2007, there were 7,021 horizontal and directional wells drilled in western Canada compared to 7,108 in the prior year. (Source: Daily Oil Bulletin) Even though the number of total wells drilled in 2007 in Canada was approximately 20 percent below 2006 levels, horizontal and directional wells drilled as a percentage of total wells drilled increased to a record high of 38 percent. This higher percentage was generated in part from increased horizontal drilling in both oil and natural gas well applications. Oil well drilling, which typically uses horizontal drilling techniques, was active in southeastern Saskatchewan in 2007 due to high oil commodity prices and improved fracturing techniques. Gas wells that typically used vertical drilling in the past are now, in some high profile areas such as the Montney in northern BC, utilizing horizontal drilling techniques in conjunction with well fracturing to gain improved production economics. Phoenix has been an active participant in the Montney region in 2007.

Phoenix's continued presence in the robust oil well drilling market in southern Saskatchewan and its increased drilling activity in shallow gas wells using its Remote Access Directional Drilling ("RADD") system has helped the Fund perform beyond the change in industry activity that occurred in 2007 over 2006. Phoenix's drilling days in western Canada for the year ended December 31, 2007 increased by three percent to 6,070 days from 5,915 in 2006. Competitive pressures have caused the Fund's Canadian day rates to decline on average by five percent in 2007 in comparison to 2006.

Canadian industry horizontal and directional activity for the three-month period ended December 31, 2007 increased by 11 percent to 2,019 wells compared to 1,821 wells in the corresponding 2006 period. (Source: Daily Oil Bulletin) The strengthening of natural gas prices during the fourth quarter of 2007 helped to contribute to this positive development.

During this same period, the Fund's Canadian operating days increased by 10 percent to 1,737 days in 2007 from 1,578 days in the comparable 2006 period. Despite the increased operating days, revenue for the three-month period ended December 31, 2007 declined by two percent to $16.1 million from $16.3 million in 2006. The primary reasons for this decline:

- Customer day rates on average were seven percent lower in the fourth quarter of 2007 compared to 2006;

- Revenue from MWD leases to other horizontal and directional service providers declined; and

- Third-party revenue associated with insurance declined due to a larger percentage of customers opting not to take out downhole insurance coverage in 2007 as compared to 2006.

In the fourth quarter of 2007 approximately 48 percent of the Fund's Canadian revenue was achieved through the drilling of oil wells predominantly in southern Saskatchewan.

UNITED STATES REVENUE

Nevis Energy Services Inc. ("Nevis"), the Fund's wholly owned subsidiary, increased its revenue for the year ended December 31, 2007 by 40 percent to a record $55.5 million from $39.7 million in 2006. Nevis operates predominantly in the active natural gas drilling market across the US.

The Northeast region, headquartered in Traverse City, Michigan, had its first full-year of operations since its inception in April 2006, and this region accounted for a significant portion of Nevis' 2007 growth. Activity increased with both coal bed methane ("CBM") de-gasification drilling services in West Virginia and Pennsylvania, and shale gas drilling in Kentucky and West Virginia. The Fund continued to be an active service provider in the Barnett Shale region in Texas, but it was also successful in diversifying its operations into other areas in that region, including a large deep gas-drilling project in a highly environmental sensitive National Park area in Texas.

Full service US operating days increased by approximately 37 percent to 3,950 days in the 2007 year from 2,873 days in 2006. Due to the strength of drilling activity in the industry Nevis saw moderate increases in day rate pricing to its customers.

In comparison to Nevis' growth, US industry activity, as measured by the average number of horizontal and directional rigs running on a daily basis, increased by 15 percent in 2007 to 769 rigs from 669 rigs in 2006. (Source: Baker Hughes) Horizontal and directional drilling activity accounted for approximately 44 percent of the total wells drilled in 2007 as compared to 40 percent in 2006. As in Canada, producers are realizing the benefits of improved economics utilizing horizontal drilling in conjunction with advanced fracturing techniques in areas such as the Barnett Shale in Texas and the northeastern US.

In 2007 Nevis opened new sales offices in Denver, Colorado and Oklahoma City, Oklahoma in order to start building a presence in selected areas. A further sales office was opened in Dallas, Texas early in 2008. It is expected that the US operations will continue to grow and contribute a healthy percentage of the Fund's overall activity in 2008.

Lead by the Fund's Northeast region, US drilling activity for Nevis remained strong in the fourth quarter of 2007 with revenue increasing by 19 percent to $15.0 million as compared to $12.6 million for the 2006 period. This was the second highest revenue result for the US operations. Full service operating days for the three-month period ended December 31, 2007 increased by 19 percent to 986 days from 823 days in the corresponding 2006 period. In the fourth quarter of 2007 US revenue accounted for 48 percent of consolidated revenue, compared to 43 percent in 2006. The average number of active rigs in the fourth quarter of 2007 in the US increased by 12 percent to 789 rigs as compared to 704 rigs in 2006. (Source: Baker Hughes)



OPERATING COSTS AND EXPENSES
(stated in thousands
of dollars except Three-month period ended
percentages) December 31, Year ended December 31,
2007 2006 % Change 2007 2006 % Change
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Direct costs 19,830 17,225 15% 73,213 59,873 22%
Gross profit as
a percentage of
revenue 36% 40% 37% 40%
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Direct costs are comprised of field and shop expenses and include current period research & development ("R&D") expenditures. Direct costs for the year ended December 31, 2007 increased by 22 percent to $73.2 million and gross profit as a percentage of revenue declined by three percentage points to 37% as compared to 2006. For the three-month period ended December 31, 2007 direct costs increased by 15 percent to $19.8 million compared to $17.2 million in 2006. Gross profit as a percentage of revenue declined from 40 percent in 2006 to 36 percent in 2007. These percentage declines in gross profit were due to several factors:

Canada:

- Lower day rates were realized by the Fund in 2007 as compared to 2006 due predominantly to the slow-down in natural gas drilling activity within the industry. Canadian field labour costs on the other hand did not follow this trend and they increased in 2007 from 2006 due to a strong competitive labour market that existed throughout the year.

- Despite the downhole drilling motor service facility in Calgary generating cost savings in 2007 as compared to 2006, Phoenix, due to market pressures on day rates, could not re-bill certain motor servicing costs to customers to the same extent in 2007 as in the prior year.

- There was an increase in R&D projects and activities in the 2007-year.

United States:

- Customer day rates on average in 2007 were moderately higher than in 2006; however, field labour costs also increased at a greater rate due to labour shortages that were present in the US throughout the year.

SG&A costs for the year ended December 31, 2007 increased by 47 percent to $12.7 million from $8.6 million in 2006. For the three-month period ended December 31, 2007, SG&A costs increased by 36 percent to $3.3 million as compared to $2.4 million in 2006. The Fund took initiatives early in 2007 to add experienced sales, marketing and administrative personnel in Canada and the US to support past growth and, more importantly, obtain future growth. In the US this trend has continued early in 2008 where the Fund made several strategic placements that are expected to generate additional revenue in the current year. Marketing and promotional expenses also increased with the level of activity in 2007. In addition the Fund adopted a deferred share unit compensation program for its Directors that added to director compensation expenses during 2007.

It is anticipated that going forward into 2008 SG&A costs will be between 11 and 13 percent of revenue.

Bad debt expense increased to $1.7 million for the year ended December 31, 2007 from $0.3 million in the 2006-year. In the three-month period ended December 31, 2007 bad debt provisions were $0.7 million as compared to $0.4 million in the 2006 period. Significant portions of both years' expense amounts are represented by one large US client that went into chapter 11 bankruptcy late in 2006. Due to recent developments in the bankruptcy proceedings, additional 2007 loss provisions were required on the original 2006 receivable. A further $0.4 million bad debt provision was provided for at the end of the 2007-year for another US client that ran into cash flow problems during the year.

Depreciation and amortization has increased as a result of current and past period capital expenditures. For the year ended December 31, 2007 these costs increased to $7.2 million from $6.2 million in 2006. Amortization costs related to intangible assets that were recognized on a 2005 acquisition were $nil in 2007 and $37,500 in 2006. For the three-month period ended December 31, 2007 depreciation increased by 12 percent to $1.9 million from $1.7 million in the comparable 2006 period.

For the year ended December 31, 2007 stock-based compensation increased by 32 percent to $1.4 million as compared to $1.1 million in 2006. A portion of the increase was due to a charge of $0.1 million that resulted from the change in the option valuation model used by the Fund to calculate its compensation expense for its unit options. Due to the nature of the Fund's new 2007 option plan, the Lattice-Binomial model is regarded as a more accurate valuation model than the previously used Black-Scholes model. The balance of the 2007 increase is due to compensation expenses arising from options issued in previous periods.

Foreign exchange losses are shown net of any gains and result primarily from the translation of US and Canadian-denominated trade receivables and payable balances, and movements in US and Canadian dollar exchange rates. The foreign exchange loss of $0.6 million in the 2007 year was due primarily to the strengthening Canadian dollar and the loss on translation of the Canadian denominated inter-company loan between Phoenix and its US subsidiary. For the three-month period ended December 31, 2007 the foreign exchange loss was $0.1 million.

The Fund realized a gain on disposition of drilling equipment of $0.5 million in the 2007 quarter as compared to only $45,000 in 2006. This gain was related to the losses of several pieces of insured downhole equipment and its occurrence is uncontrollable in nature. For both the 2007 and 2006 years, the gain on disposition of drilling equipment was $0.6 million.



(stated in thousands of dollars except
percentages)
Years ended December, 2007 2006 % Change
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Income taxes 1,041 3,051 (66)
Effective tax rate 5% 13%
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The effective income tax rate for the year ended December 31, 2007 was 5 percent compared to an expected federal and provincial rate of 32 percent. The difference in the two rates of $5.2 million was primarily the result of the following:

- A reduction of $5.6 million due to the deductibility of declared cash distributions that are allowable in calculating taxable income of the Fund;

- A reduction of $0.6 million due to the benefit received from enacted federal and provincial income tax rate reductions;

- An increase of $0.7 million due to the non-deductibility of stock-based compensation and other expenses; and

- An increase of $0.3 million due to other miscellaneous items.

As an investment trust, the Fund is subject to income taxes under the Income Tax Act only on income not distributed to its unitholders. The Fund, unlike its subsidiaries, will not recognize any future tax assets or liabilities on differences between the accounting and tax basis of its assets and liabilities.

For the three-month period ended December 31, 2007 the Fund reported a provision for income taxes of $0.1 million as compared to $0.6 million in 2006. The lower effective tax rate in the 2007 quarter is due primarily to the recognition of reductions in future tax rates and adjustments arising from the estimation of income the Fund's income tax rates in prior periods.

INVESTMENT

The Fund did not make any business acquisitions in 2007, but Phoenix continued to invest in capital equipment, spending $14.6 million on drilling and other equipment compared to $12.7 million in 2006. These 2007 expenditures allowed Phoenix to expand its MWD fleet and support the increased level of the Fund's operations allowing it to minimize expensive third-party equipment rentals, thereby improving profitability. The Fund realized proceeds from the involuntary disposal of drilling equipment in well bores of $2.2 million in 2007, compared to $2.0 million in 2006.

Historically, the Fund has financed its capital expenditures and acquisitions through cash flows from operating activities, debt and equity. The 2008 capital budget has been set at $15.3 million and this includes the addition of 14 MWD systems. The planned capital expenditures will be financed from cash flows from operating activities and by the Fund's unused credit facilities or equity, if necessary. If future growth opportunities present themselves, the Fund would not hesitate to expand this planned capital expenditure amount.

CAPITAL RESOURCES

The Fund has access to a bank overdraft revolving facility of up to $5.0 million. This facility bears interest at the Fund's option at the bank's prime rate plus 0.375 percent or the bank's bankers' acceptance rate plus a stamping fee of 1.25 percent. As at December 31, 2007 the Fund had $2.8 million drawn on this facility.

On December 15, 2007 the Fund renewed its $20 million, 364-day extendible revolving facility with its bank. This bears interest at the Fund's option at the bank's prime rate plus 0.375 percent or the bank's bankers' acceptance rate plus a stamping fee of 1.25 percent. The facility is renewable at the option of the lender. Should this facility not be extended, outstanding amounts will be transferred to a four-year term facility repayable at 1/25 of the amount outstanding for fifteen quarters with the remaining balance paid on the sixteenth quarter. At December 31, 2007 $1.8 million was drawn on this facility.

TAXATION OF DISTRIBUTIONS

On June 22, 2007, Bill C-52 An Act to implement certain provisions of the budget tabled in Parliament on March 19, 2007 ("Bill C-52 Amendments"), was substantially enacted as legislation in Canada. Bill C-52 Amendments implement proposals originally announced on October 31, 2006 relating to the taxation of certain distributions from certain trusts and partnerships. Bill C-52 Amendments apply commencing January 1, 2007 to all "specified investment flow-through" ("SIFT") trusts that begin to be publicly traded after October 2006 and January 1, 2011 for all SIFT trusts that were already publicly traded before November 2006, subject to the possibility that a SIFT trust that was already publicly traded before November 2006 may become subject to the new rules before January 1, 2011 if the trust experiences growth, other than "normal growth", before then. Bill C-52 Amendments incorporate guidelines with respect to what is meant by "normal growth".

The Fund considers itself to be a SIFT trust under Bill C-52 Amendments. As a result, commencing in January 2011, provided that the Fund experiences only "normal growth" and no "undue expansion" before then, the Fund will be liable for tax at the "net corporate income tax rate" combined with the "provincial SIFT tax factor", effectively, the federal general corporate tax rate plus 13 percent on account of provincial corporate tax, on all income payable to Unitholders, which the Fund will not be able to deduct as a result of being characterized as a SIFT trust.

Given the three-year grace period before existing trusts will be taxed, Phoenix has an opportunity to examine its strategy and, if warranted, to modify its structure to provide the best possible return for its unitholders.

ALBERTA ROYALTY FRAMEWORK

On October 25, 2007, the Government of Alberta released its New Royalty Framework for Alberta's natural resources. Changes that were announced will affect the conventional oil, natural gas, and oils sands industries. The proposed changes will require new legislation and amendments to existing Acts but it is expected that the new rules will be in place for implementation on January 1, 2009. These changes will result in increases in royalty rates in Alberta with the implementation of sliding-scale formulas determined by commodity prices and well productivity. If the proposed changes are implemented in their current form, it may lead to a slow down in capital spending and oil and natural gas activity in Alberta that may negatively impact the Fund's operations in Alberta and its cash flow. It is not possible to predict at this time what the impact on Phoenix will be.

NON-GAAP MEASURES

1) EBITDA

EBITDA, defined as earnings before interest, taxes, depreciation and amortization, is not a financial measure that is recognized under Canadian GAAP. However, management believes that EBITDA provides supplemental information to net earnings that is useful in evaluating the Fund's operations before considering how it was financed or taxed in various countries. Investors should be cautioned, however, that EBITDA should not be construed as an alternative measure to net earnings determined in accordance with GAAP. Phoenix's method of calculating EBITDA may differ from that of other organizations and, accordingly, its EBITDA may not be comparable to that of other companies.



The following is a reconciliation of net earnings to EBITDA:

Three-month periods Years
(Stated in thousands of ended December 31, ended December 31,
dollars) 2007 2006 2007 2006
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Net earnings 5,281 6,273 18,214 20,638
Add:
Depreciation and
amortization 1,876 1,661 7,165 6,190
Interest on long-term debt 31 30 110 141
Provision for income taxes 82 631 1,041 3,051
Other interest 9 13 3 (70)
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EBITDA as reported 7,279 8,608 26,533 29,950
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Diluted EBITDA per unit is calculated using the treasury stock method whereby deemed proceeds on the exercise of the unit options are used to reacquire Fund units at an average unit price. The calculation of EBITDA on a dilutive basis does not include anti-dilutive options.

2) DISTRIBUTABLE CASH

Distributable cash is defined as cash flow generated from operating activities before net changes in non-cash working capital, excluding bad debt provisions, and is not a measure recognized under Canadian GAAP. However, management believes that distributable cash provides supplemental information to cash flow from operating activities that is useful in evaluating the Fund's operating cash flow before considering changes in working capital balances. Management uses this measure to calculate its cash payout ratio to show what percentage of its distributable cash is paid out to its unitholders. Investors should be cautioned, however, that distributable cash should not be construed as an alternative measure to cash flow from operating activities determined in accordance with GAAP. Phoenix's method of calculating distributable cash may differ from that of other organizations and, accordingly, its distributable cash may not be comparable to that of other companies.

The Fund considers its maintenance capital expenditures to be minimal. Maintenance capital would only be relevant to the Fund's retirement of tubular equipment that is subsequently replaced. Typically, lost-in-hole equipment is replaced but these losses are typically funded by the proceeds from insurance or customers. In addition, due to the nature of the industry, the Fund's drilling equipment is frequently re-conditioned to an "as new" state with the associated costs expensed and included in the Fund's direct costs. Consequently, the Fund will not make an adjustment to distributable cash for capital maintenance expenditures. The Fund's assumptions used with respect to maintenance capital are believed to be reasonable at the time of preparation; however, no assurance can be given that these assumptions will prove to be correct and, consequently, the Fund's distributable cash could differ materially in the future.



The following is a reconciliation of cash flow provided from operating
activities to distributable cash:

Three-month periods Years
(Stated in thousands of ended December 31, ended December 31,
dollars) 2007 2006 2007 2006
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Cash flows from operating
activities 9,608 8,797 26,103 25,941
Changes in non-cash
working capital (1,704) (395) 3,318 2,968
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Distributable cash 7,904 8,402 29,421 28,909
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Diluted distributable cash per unit is calculated using the treasury stock method whereby deemed proceeds on the exercise of the unit options are used to reacquire Fund units at an average unit price. The calculation of distributable cash per unit on a dilutive basis does not include anti-dilutive options.

3) CASH PAYOUT RATIO

The cash payout ratio is defined as cash distributions made by the Fund in the period divided by its distributable cash for the same period. The cash payout ratio is not a measure recognized under Canadian GAAP. However, management believes the cash payout ratio provides supplemental information that is useful in evaluating the level of cash distributions in relation to the Fund's distributable cash. Investors should be cautioned, however, that the cash payout ratio should not be construed as an alternative measure to other GAAP measures. Phoenix's method of calculating its cash payout ratio may differ from other organizations, and accordingly the cash payout ratio may not be comparable to other companies.

OUTLOOK

Phoenix has experienced modest growth and has produced solid financial results for many of its quarters in 2007. At this time the outlook for future oil and natural gas commodity prices appear to be much more encouraging. World oil prices have hit record levels, and in recent months natural gas prices have been increasing. These commodity prices should create a further demand for the Fund's services and, if these trends continue, natural gas drilling activity within Canada in 2008 should increase beyond current levels.

Phoenix is currently operating at record activity levels, and has seen additional growth in the first quarter of 2008 in both its Canadian and US operations. With its US operations, oil well drilling and growth in shallow gas applications using the RADD system, the Fund will remain active through the expected seasonal break-up in Canada. The outlook for the remainder of the year for the demand of the Fund's services is forecasted to be strong.

In 2008 US expansion will continue. The Fund has already secured additional key individuals in several strategic locations throughout the US that will generate more growth during the year. The industry in the US is expected to continue to be robust in 2008.

The Fund plans to continue to invest in capital to allow for expansion and improved margins in 2008. A capital expenditure budget of $15.3 million has been approved and management will monitor the adequacy of this budget as the year progresses. This will increase the Fund's job capacity to 108 concurrent jobs by year end 2008 through the addition of eight CLT EM-MWD systems, six positive pulse MWD systems, and required downhole performance drilling motors. With low debt levels and a strong balance sheet the Fund is in a good position to expand its operations through further capital expenditures or acquisitions.

Research and development efforts will again intensify in 2008 to enable Phoenix to continue to provide leading-edge technology to its customers in the future. The Fund has since year end added several staff members to help assist with its current and future projects and expedite the efforts of the department. The Fund fully expects to capitalize on several projects in 2008 that will allow Phoenix to further gain market share and enter lucrative unconventional drilling markets.

PHOENIX TECHNOLOGY INCOME FUND

Phoenix is in the business of providing horizontal and directional technology and drilling services in western Canada and the United States. In addition to this core business, the Fund also rents downhole, high-performance drilling motors, drilling jars, and other ancillary equipment in western Canada. CLT technology which was developed in Phoenix's research and development center is used to manufacture CLT guidance systems for use in the Fund's internal operations, and for short-term leases to other horizontal and directional service providers within North America. The Fund maintains its corporate head office, research & development, Canadian sales, service and operational centers in Calgary, Alberta. The Fund's US operations, conducted through the Fund's wholly owned subsidiary, Nevis Energy Services Inc. ("Nevis"), is headquartered in Houston Texas. Nevis has sales and service facilities in Houston, Texas; Traverse City, Michigan; and Casper, Wyoming. In addition sales offices are located in Oklahoma City, Oklahoma, Denver, Colorado and Dallas, Texas.

Forward-Looking Statements

Certain information set forth in this document including a discussion of future plans and operations, contains forward-looking statements that involve substantial known and unknown risks and uncertainties. These forward-looking statements include statements relating to Phoenix's plans, strategies, objectives, expectations, intentions, resources and business activities, which are not guarantees as to future results since there are inherent difficulties in predicting these future results. The use of any of the words: "anticipate", "expect", "project", "may", "will", "should", "believe", "estimate", "forecast", "intends" and similar expressions identify forward-looking statements. Such statements are subject to known and unknown risks and uncertainties, many of which are beyond the Fund's control. These would include the impact of the general state of the economy, oil and natural gas energy price fluctuations, industry conditions, competition from other organizations, weather conditions and the seasonal nature of business, access to third-party suppliers and contractors, changes in government regulation, access to competent employees including senior management, and currency and interest rate fluctuations. In particular, if there is a material downturn in activity levels in the oil and gas industry, there may also be a sudden impact to the Fund's level of cash flow and distributions. The Fund's assumptions used in these forward-looking statements are believed to be reasonable at the time of preparation; however, no assurance can be given that these assumptions will prove to be correct and consequently, the Fund's actual results could differ materially from those implied by or contained in any forward-looking statement. As a result, readers should be cautioned about placing any undue reliance on any forward-looking statement included in this report.



Consolidated Balance Sheets

December 31, 2007 December 31, 2006
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ASSETS (audited) (audited)

Current assets:
Cash and cash equivalents $ 3,008,797 $ 1,763,191
Accounts receivable 29,943,706 30,355,422
Inventory 3,254,756 1,189,254
Prepaid expenses 574,853 1,075,697
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36,782,112 34,383,564

Drilling and other equipment 39,694,148 35,208,134
Goodwill 8,876,351 8,876,351
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$ 85,352,611 $ 78,468,049
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LIABILITIES AND UNITHOLDERS'
EQUITY

Current liabilities:
Bank Indebtedness 2,827,355 -
Accounts payable and accrued
liabilities 16,631,330 12,130,147
Distributions payable 1,458,187 1,447,861
Income taxes payable 65,000 1,195,000
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20,981,872 14,773,008

Long-term debt 1,775,000 1,775,000
Future income taxes 2,736,000 3,012,000
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25,492,872 19,560,008

Unitholders' equity:
Unitholders' capital 44,812,574 43,509,547
Contributed surplus 3,103,536 2,042,311

Retained earnings 15,741,760 14,972,076
Accumulated other comprehensive
income (3,798,131) (1,615,893)
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11,943,629 13,356,183
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59,859,739 58,908,041

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$ 85,352,611 $ 78,468,049
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Consolidated Statements of Earnings

Three- month period ended
December 31 Year ended December 31
2007 2006 2007 2006
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(unaudited) (unaudited) (audited) (audited)

Revenue $ 31,018,490 $ 28,881,813 $ 115,547,848 $ 99,346,209
Direct costs 19,830,209 17,224,710 $ 73,213,428 $ 59,873,380
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Gross profit 11,188,281 11,657,103 42,334,420 39,472,829
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Expenses
Selling, general
and administrative 3,299,042 2,433,139 12,681,482 8,632,248
Provision for bad
debts 661,882 447,269 1,748,169 297,498
Depreciation and
amortization 1,875,874 1,661,020 7,165,115 6,190,325
Stock-based
compensation 391,955 297,632 1,419,466 1,078,050
Foreign exchange
loss (gain) 102,747 (84,658) 576,203 113,715
Interest on
long-term debt 31,430 30,861 110,547 140,747
Other interest 8,692 12,677 2,824 (70,649)
Gain on
disposition of
drilling equipment (546,743) (44,734) (623,980) (598,223)
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5,824,879 4,753,206 23,079,826 15,783,711

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Earnings before
income taxes 5,363,402 6,903,897 19,254,594 23,689,118
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Provision for
(recovery of)
income taxes
Current 17,000 771,000 270,000 1,892,000
Future 65,000 (140,000) 771,000 1,159,000
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82,000 631,000 1,041,000 3,051,000
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Net earnings $ 5,281,402 6,272,897 $ 18,213,594 $ 20,638,118
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Earnings per unit -
basic $ 0.24 $ 0.28 $ 0.81 $ 0.93
Earnings per unit -
diluted $ 0.23 $ 0.28 $ 0.81 $ 0.92
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Consolidated Statements of Comprehensive Income

Three- month period ended
December 31 Year ended December 31
2007 2006 2007 2006
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----------------------------------------------------------------------------
(unaudited) (unaudited) (audited) (audited)

Net earnings 5,281,402 6,272,897 $ 18,213,594 $ 20,638,118
Foreign currency
adjustment (74,446) 505,563 (2,182,238) 247,279

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Comprehensive
income $ 5,206,956 $ 6,778,460 $ 16,031,356 $ 20,885,397
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Consolidated Statements of Cash Flows

Three- month period ended
December 31 Year ended December 31
2007 2006 2007 2006
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----------------------------------------------------------------------------
(unaudited) (unaudited) (audited) (audited)
Cash flows from
operating
activities:
Net earnings $ 5,281,402 $ 6,272,897 $ 18,213,594 $ 20,638,118
Add (deduct)
items not
affecting cash: -
Depreciation and
amortization 1,875,874 1,661,020 7,165,115 6,190,325
Future income
taxes 65,000 (140,000) 771,000 1,159,000
Unrealized
foreign exchange
loss(gain) 174,738 (91,991) 727,938 143,829
Gain on
disposition of
drilling equipment (546,743) (44,734) (623,980) (598,223)
Stock-based
compensation 391,955 297,632 1,419,466 1,078,050
Provision for bad
debts 661,882 447,269 1,748,169 297,498
Change in
non-cash working
capital 1,704,372 394,802 (3,318,132) (2,967,727)
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9,608,480 8,796,895 26,103,170 25,940,870
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Cash flows from
investing
activities:
Proceeds on
disposition of
drilling equipment 936,308 364,404 2,237,982 1,995,247
Acquisition of
drilling and other
equipment (3,449,078) (2,222,514) (14,610,124) (12,749,770)
Change in
non-cash working
capital (300,565) 495,986 1,176,007 (85,516)
Cash in trust - 50,000 - 50,000
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(2,813,335) (1,312,124) (11,196,135) (10,790,039)
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Cash flows from
financing
activities:
Proceeds on
issuance of units 127,910 11,695 944,789 473,418
Distributions to
unitholders' (4,371,753) (4,343,115) (17,433,573) (16,326,008)
Repayment of
long-term debt - (375,000) - (1,500,000)
Proceeds on bank
overdraft facility 2,827,355 - 2,827,355 -
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(1,416,488) (4,706,420) (13,661,429) (17,352,590)
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Increase(decrease)
in cash and cash
equivalents 5,378,657 2,778,351 1,245,606 (2,201,759)
Cash and cash
equivalents(bank
indebtedness),
beginning of
period (2,369,860) (1,015,160) 1,763,191 3,964,950
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Cash and cash
equivalents, end
of period $ 3,008,797 $ 1,763,191 $ 3,008,797 $ 1,763,191
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Contact Information

  • Phoenix Technology Services Inc.
    John Hooks
    President and CEO
    (403) 543-4466
    or
    Phoenix Technology Services Inc.
    Cameron Ritchie
    Senior Vice President Finance and CFO
    (403) 543-4466
    or
    Phoenix Technology Services Inc.
    Suite 630, 435 4th Avenue SW
    Calgary, Alberta T2P 3A8
    (403) 543-4466
    (403) 543-6025 (FAX)
    Website: www.phoenixcan.com