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Builders Energy Services Trust TSX: BET.UN 
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Mar 08, 2007 18:54 ET
Builders Energy Services Trust Reports 2006 Earnings
CALGARY, ALBERTA--(CCNMatthews - March 8, 2007) - Builders Energy Services Trust (TSX:BET.UN) ("Builders", or the "Trust") announced year end and fourth quarter results for 2006.
HIGHLIGHTS
For the Year Ended December 31, 2006
- Results from operations:
-- Net earnings of $27.6 million, an increase of 67% from $16.5 million for the 341-day period ended December 31, 2005. On a per unit basis, net earnings increased to $1.66 per unit diluted from $1.38 per unit diluted.
-- Funds flow from operations(1) of $43.9 million, an increase of 42% from $30.9 million for the 341-day period ended December 31, 2005.
-- EBITDA(1) of $47.0 million, an increase of 49% from $31.5 million for the 341-day period ended December 31, 2005.
- Four acquisitions totalling $54.2 million were completed and focused on expanding the depth and geographic presence of Builders' Service Rigs and Oilfield Transport divisions.
- Growth through capital spending with $36.5 million of growth capital and $2.0 million of net maintenance capital.
- A significant increase in the number of service rigs and oilfield transport trucks:
-- 39 service rigs at the end of 2006, up from 22 at the end of 2005
-- 155 oilfield transport trucks at the end of 2006, up from 113 at the end of 2005
- Increased financial flexibility with:
-- $30 million equity financing in August
-- Expansion of the credit facility to $100 million from $70 million
- Payout ratio(1) of 62% for 2006.
For the Fourth Quarter of 2006
- Results from operations:
-- Net earnings of $5.2 million, a decrease from $7.2 million in the fourth quarter of 2005
-- Funds flow from operations(1) of $9.4 million, a decrease from $12.5 million in the fourth quarter of 2005
-- EBITDA(1) of $10.2 million, a decrease from $13.5 million in the fourth quarter of 2005
- Continued growth through acquisitions and capital spending with:
-- The purchase of Murphy's Oilfield Services Ltd. for $11.7 million on October 3, 2006
-- $10.5 million of capital expenditures.
The year 2006 started out strong with high activity in the Western Canadian Sedimentary Basin ("WCSB") in the first quarter with most of Builders' equipment operating at high utilization levels. However, due to unseasonably warm weather in the 2005/06 winter, North American natural gas storage levels exited the first quarter of 2006 at very high levels causing a softening in the price of natural gas. Builders began to see the impact of this in the latter part of the third quarter and into the fourth quarter of 2006, as natural gas drilling activity in the WCSB did not reach the same level as the comparable period in 2005 and the demand for oilfield services was reduced. The impact was most pronounced in Builders' businesses that service shallow gas and coal bed methane drilling, affecting rig moving in southern Alberta, coil tubing and nitrogen services in central Alberta, and to a lesser extent, wireline services in northeastern Alberta. Other parts of the business, especially the Service Rigs segment, were very active in 2006, right through to the end of the fourth quarter.
Softness in the natural gas market continues into the first quarter of 2007 as storage levels remain high. Reduced drilling will, in time, work to correct the storage issue. In spite of current market conditions, Builders is well-positioned because of its:
- Balanced services mix: Builders provides services to support both crude oil and natural gas-related activity and production-related and drilling-related activity;
- Strong financial position: Builders was approximately 50% drawn on its credit facilities at December 31, 2006;
- Strategic growth focus: Builders can grow both organically and through acquisitions. The proposed tax on trust rules, announced in late 2006, allows a trust to double in size prior to 2011; and
- Stable distributions: Builders had a 62% payout ratio(1) in 2006 which allows significant flexibility and sustainability of the distribution.
"2006 has been both exciting and challenging," said Garnet Amundson, President and Chief Executive Officer of Builders. "Throughout the year we continued with our growth strategy, successfully increasing the size and breadth of our organization. While the energy sector is currently in the midst of a downturn, we have a very robust business within a solid business model, and we are well-positioned to continue execution of our strategy through to the upswing in the cycle, which the market is generally expecting in late 2007 or early 2008."
FINANCIAL SUMMARY
For the For the
year 341-days
Three months ended ended
(Thousands, except per unit ended Dec. 31, Dec. 31, Dec. 31,
amounts) 2006 2005 2006 2005
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Revenue
$ 51,799 $ 50,772 $199,565 $125,460
Gross margin(1) $ 15,945 $ 18,361 $ 66,224 $ 46,237
Funds flow from operations(1) $ 9,418 $ 12,544 $ 43,902 $ 30,898
Per unit - diluted $ 0.51 $ 0.90 $ 2.64 $ 2.58
Net earnings $ 5,242 $ 7,220 $ 27,644 $ 16,512
Per unit - diluted $ 0.28 $ 0.52 $ 1.66 $ 1.38
Distributions declared $ 7,750 $ 5,497 $ 27,307 $ 16,731
Per unit $ 0.42 $ 0.39 $ 1.64 $ 1.39
Payout ratio(1) 82% 44% 62% 54%
Gross margin as a percentage
of revenue(1) 31% 36% 33% 37%
Equipment expenditures $ 10,497 $ 11,915 $ 43,604 $ 28,948
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Trust units:
Outstanding, end of period 18,453 14,624 18,453 14,624
Weighted average, basic 18,445 13,557 16,436 11,788
Weighted average, diluted 18,520 13,880 16,638 11,994
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(1) Funds flow from operations, EBITDA, payout ratio, gross margin and
gross margin as a percentage of revenue are non-GAAP financial
measures. The attached Management's Discussion and Analysis outlines
the definition and usefulness of these measures.
The 2006 annual report will be available on-line at www.buildersenergy.com
in late March.
Based in Calgary, Alberta, Builders Energy Services Trust is an open-end, unincorporated investment trust providing oilfield services in western Canada through skilled staff and specialized equipment. Builders provides services to the oil and gas industry related to the ongoing servicing of producing wells and new drilling activity.
This press release may contain forward-looking statements including expectations of future cash flow and earnings. These statements are based on current expectations that involve a number of risks and uncertainties which could cause actual results to differ from those anticipated. These risks include, but are not limited to: risks associated with the oilfield services industry (e.g. demand, pricing and terms for oilfield services; current and expected oil and gas prices; exploration and development costs and delays; reserves discovery rates; pipeline and transportation capacity; weather, health, safety and environmental risks), integration of acquisitions, competition, and uncertainties resulting from potential delays or changes in plans with respect to acquisitions, development projects or capital expenditures. Additional information on these and other factors that could affect the Trust's operations or financial results are included in the Trust's documentation and filings with Canadian securities regulatory authorities. Should one or more of these risks or uncertainties materialize, or should assumptions underlying forward-looking statements prove incorrect, actual results may vary materially from those described in this press release. The Trust does not assume any obligation to update these forward-looking statements, except as required by law.
MANAGEMENT'S DISCUSSION AND ANALYSIS
The following Management's Discussion and Analysis ("MD&A") of Builders Energy Services Trust ("Builders" or the "Trust") for the year ended December 31, 2006, should be read in conjunction with the Trust's audited consolidated financial statements as at and for the year ended December 31, 2006 and 341-days ended December 31, 2005 and the notes contained therein. This MD&A was prepared effective March 8, 2007.
Additional Information
Additional information regarding Builders, including the Annual Information Form, can be found on SEDAR at www.sedar.com.
Forward-Looking Statements
This MD&A may contain forward-looking statements including expectations of future cash flow and earnings. These statements are based on current expectations that involve a number of risks and uncertainties which could cause actual results to differ from those anticipated. These risks include, but are not limited to: risks associated with the oilfield services industry (e.g. demand, pricing and terms for oilfield services; current and expected oil and gas prices; exploration and development costs and delays; reserves discovery rates; pipeline and transportation capacity; weather, health, safety and environmental risks), integration of acquisitions, competition, and uncertainties resulting from potential delays or changes in plans with respect to acquisitions, development projects or equipment expenditures. Additional information on these and other factors that could affect the Trust's operations or financial results are included in the Trust's documentation and filings with Canadian securities regulatory authorities. Should one or more of these risks or uncertainties materialize, or should assumptions underlying forward-looking statements prove incorrect, actual results may vary materially from those described in this MD&A. The Trust does not assume any obligation to update these forward-looking statements, except as required by law.
Non-GAAP Measures
Throughout this MD&A, certain terms that are not specifically defined in Canadian Generally Accepted Accounting Principles ("GAAP") are used to analyze the operations. In addition to the primary measures of net earnings and net earnings per unit in accordance with GAAP, Management believes that certain measures not recognized under GAAP assist Management and the reader in assessing the performance and understanding the Trust's results. Each of these measures provides the reader with additional insight into the Trust's ability to fund future distributions, principal debt repayments and capital programs. These non-GAAP measures are not recognized measures under GAAP. As a result, the method of calculation may not be comparable with other companies or Trusts. These measures should not be considered alternatives to net earnings and net earnings per unit as calculated in accordance with GAAP.
- Gross margin(1) - This measure is considered a primary indicator of operating performance as calculated by revenue less operating expenses.
- Gross margin as a percentage of revenue(1) - This measure is considered a primary indicator of operating performance as calculated by gross margin divided by revenue.
- EBITDA(2) (Earnings before interest, income taxes, depreciation, amortization and losses or gains on disposal of equipment) - This measure is considered an indicator of the Trust's ability to generate funds flow in order to meet distributions, fund required working capital, service debt, pay current income taxes and fund capital programs.
- EBITDA as a percentage of revenue(2) - This measure is considered an indicator of the Trust's ability to generate funds flow as calculated by EBITDA divided by revenue.
- Funds flow or funds flow from operations(3) - This measure is an indicator of the Trust's ability to generate funds flow in order to make distributions, fund required working capital, principal debt repayments and fund capital programs. Funds flow or funds flow from operations is defined as cash flow from operations before changes in non-cash working capital. Management uses this measure in assessing the Trust's operational cash flow as it provides cash generated in the period excluding the timing of non-cash working capital. This reflects the ability of the operations of the Trust to meet the above noted funding requirements. The most significant non-cash working capital component affecting cash flow is accounts receivable.
- Maintenance capital(4) - Equipment additions that are incurred in order to refurbish or replace previously acquired equipment. Such additions do not provide incremental increases in revenue. Maintenance capital is a key component in understanding the sustainability of the Trust as cash resources retained within the Trust must be sufficient to meet maintenance capital needs to replenish the assets for future cash generation.
- Growth capital(4) - Growth capital is capital spending which is intended to result in incremental increases in revenue. Growth capital is considered a key measure by management as it represents the total expenditures on equipment expected to add incremental revenues and funds flow to the Trust.
- Distributable cash(5) - Distributable cash is a key measure of the Trust's ability to fund cash distributions to its Unitholders. Distributable cash is determined by subtracting maintenance capital and scheduled debt repayments from funds flow from operations and adding back proceeds on disposal of equipment replaced by maintenance capital.
- Payout ratio(6) - This ratio is defined as distributions declared expressed as a percentage of funds flow from operations. This ratio is an indicator of the Trust's ability to meet its distribution levels from the Trust's ongoing operations excluding changes in non-cash working capital.
(1) Gross margin and gross margin as a percentage of revenue are reconciled from the GAAP measure, revenue, in the table "Results of Operations".
(2) EBITDA and EBITDA as a percentage of revenue are reconciled from the GAAP measure, earnings before income taxes and non-controlling interest, in the table "Results of Operations".
(3) Funds flow is reconciled from the GAAP measure, cash flow from operations, in the table "Funds Flow from Operations".
(4) Maintenance and Growth capital are reconciled to the GAAP measure, equipment expenditures, in the table "Equipment Expenditures".
(5) Distributable cash is calculated from the non-GAAP measures, funds flow and maintenance capital and the GAAP measures, distributions declared and proceeds on the disposal of equipment, in the table "Distributable Cash".
(6) Payout ratio is calculated from the non-GAAP measure, funds flow, and the GAAP measure, distributions declared, in the table "Payout Ratio".
COMPARATIVE AND CURRENT PERIOD
Builders commenced active operations on January 25, 2005, through an Initial Public Offering ("IPO") which included the concurrent closing of the acquisitions of nine oilfield service companies (the "IPO Acquisitions" as defined in Note 3 of the Consolidated Financial Statements). The comparative period for the 341-days ended December 31, 2005 includes the operations of the IPO Acquisitions acquired January 25, 2005; the net assets of both Tryton Tool Services Ltd. ("Tryton") and Puma Well Service Ltd. ("Puma") acquired on June 1 and October 14, 2005 respectively; and the shares of Endeavor E-line Services Inc. ("Endeavor") acquired July 21, 2005. Readers should note that the 341-day comparative period does not represent a complete twelve months of operations.
Builders has continued in 2006 to acquire oilfield service companies that fit strategically and complement its existing services. Acquisitions include all of the shares of Leachman Enterprises Ltd. ("Leachman") acquired February 1, 2006; Kodiak Well Service Ltd. ("Kodiak") acquired May 8, 2006; Prime Oilfield Hauling Ltd. ("Prime") acquired August 1, 2006; and Murphy's Oilfield Services Ltd. ("Murphy's") acquired October 3, 2006.
The operations and financial results of acquisitions have been included in the December 31, 2006 and 2005 consolidated financial statements and MD&A of the Trust from the dates of acquisitions.
BUILDERS OVERVIEW
Based in Calgary, Alberta, Builders is an open-end, unincorporated investment trust providing oilfield services in western Canada through skilled staff and specialized equipment. We provide services to both producing and newly drilled conventional crude oil and natural gas wells in the petroleum industry.
Our services are offered through three operating segments: Service Rigs, Oilfield Transport and Downhole Services & Rentals. The Service Rigs segment provides production and completion services. The Oilfield Transport segment provides general oilfield hauling and rig relocation services. The Downhole Services & Rentals segment provides wireline, coil-tubing, nitrogen, downhole tools and equipment rentals.
A fourth non-operating segment, Corporate, includes general and administrative costs and interest.
Strategy
Builders is committed to building value for our Unitholders through superior customer service, disciplined operations and the implementation of a focused long-term strategy. The key aspects of our strategy are:
- Growth: Our strategic plan includes growth with a specified target of increasing our enterprise value to at least $500 million by December 31, 2008. Growth can occur through internal expansion, acquisitions and mergers. While the "Tax Fairness Plan" and current industry conditions are expected to constrain organic growth and acquisitions, we plan to continue to grow in the right way, at the right time. We believe the oilfield services industry is ripe for consolidation and we will consider and evaluate merger opportunities.
- Cash flow management: We will remain persistent in our focus on effective management of our cost structure to achieve an aggregate EBITDA margin of greater than 25 percent. Despite the 2007 industry conditions, our expected cash flows will allow us to continue our current level of distributions to our Unitholders.
- Balanced services mix: We will continue to offer services that support crude oil and natural gas-related activity and drilling-related and production-related activity across the Western Canadian Sedimentary Basin ("WCSB"). A balanced services mix combined with geographic diversity can temper the seasonality and cyclicality of the oilfield services sector which is critical to the success of a distribution paying organization.
- Entrepreneurial spirit: Our operating philosophy includes preserving the local branding, culture and spirit of the businesses we have acquired within a framework of effective control and governance. Business in the oilfield service sector is largely based upon local relationships and we believe these relationships are best supported if the local culture remains intact.
- People: The oilfield services sector is people intensive. We will continue to assess and refine our programs and creative working arrangements to ensure attraction and retention of skilled personnel.
THE INDUSTRY
General
The WCSB is one of the largest crude oil and natural gas exploration and producing regions in North America, with the majority of Canadian crude oil and natural gas production occurring in this area. There are approximately 200,000 producing wells in the WCSB which is a maturing basin with estimates of annual decline rates for natural gas, in the absence of additional production from new drilling, of approximately 20 to 25 percent per year. This rate of decline, coupled with the fact that the average production rates per well have been declining for the past decade, has resulted in an increase in drilling activity over the same period in order to maintain current production levels. These factors, combined with the increasing demand for crude oil and natural gas and higher commodity prices, has seen the number of wells drilled annually in the WCSB increase significantly. The Canadian Association of Oilwell Drilling Contractors ("CAODC") has estimated the annual wells drilled in the WCSB have increased from approximately 10,600 in 1999 to 22,100 in 2006. Concurrently there has also been an increase in activity to preserve the productivity of existing wells and to improve recovery rates.
Drilling activity influences equipment utilization levels for oilfield services. In the WCSB, in the past number of years, drilling activity has been directed at approximately 70% for natural gas and 30% for conventional crude oil.
The oilfield services sector offers specialized staff and equipment to crude oil and natural gas exploration, development and production entities. Oilfield service operations provide services to support drilling activity as well as oilfield services to maintain existing wells that are already on production. Producing wells generally require regular service activities to maintain their productive capabilities. Production-related activities are generally regarded as less cyclical than drilling-related service activities, as they tend not to be directly impacted by the level of drilling activity. At certain commodity pricing levels, drilling may become less economic, which in turn, can affect the level of drilling activity.
Successful oilfield service firms are those that offer availability, reliability and performance of equipment, as well as technical knowledge, experience, competitive pricing, and a focus on safety.
Commodity pricing
Commodity prices for both crude oil and natural gas are driven by supply/demand fundamentals. The natural gas market is a North American market while crude oil prices fluctuate in response to global supply and demand fundamentals.
Natural gas prices are directly affected by natural gas storage levels and demand. A key demand factor for natural gas is the weather. Natural gas consumption and storage are dependent on the impact that weather patterns have on North American heating and electricity consumption. Drilling activity generally increases as prices rise in response to insufficient natural gas storage levels, and will generally decrease as prices decline.
Crude oil prices are less dependent on weather and more dependent on global economic activity and geopolitical stability. Supply is driven by many factors and is influenced by instability in many oil producing regions of the world that contain significant reserves to meet world demand. The WCSB is a relatively stable supply source for crude oil for North America, and particularly the U.S.
2006 Industry in Review
With respect to natural gas, warm winter weather in North America in 2005/2006, combined with continued U.S. natural gas drilling activity and minimal disruptions to the U.S. offshore natural gas supply, has caused natural gas storage levels to increase and natural gas prices to decline from an average of approximately U.S.$11.58 per mmbtu in January 2006 to approximately U.S.$8.01 per mmbtu in December 2006. As a result of the decline in prices, the Canadian industry responded with decreased drilling activity in the second half of 2006.
The political instability in many oil producing regions of the world, combined with normal supply/demand factors, caused crude oil prices to continue to escalate and reach all time highs in the summer of 2006. However, with no significant disruptions and relatively stable world economic activity, crude oil prices have fallen from their high of U.S.$77.03 in July 2006 to an average of U.S.$62.09 per barrel in December 2006. At these price levels, crude oil drilling remained relatively strong in the WCSB in 2006.
As a result of these pricing factors, a total of 22,100 wells were completed in the WCSB in 2006, a marginal increase from 21,900 completed wells in 2005. This additional activity was mostly driven by the development of conventional crude oil wells. Natural gas well drilling during this same period, declined. In particular, coal-bed methane activity declined during 2006 due to lower production volumes associated with these types of wells. The impact of reduced natural gas drilling was particularly prominent in the last half of the year.
Not only is drilling activity a key factor, but so is drilling rig utilization, in oilfield services activity. According to the CAODC, drilling rig utilization rates were down from 69 percent in 2005 to 63 percent in 2006, despite the modest increase in western Canadian drilling activity during 2006. The decline in utilization, mainly during the last quarter of 2006, resulted from curtailed shallow gas well drilling programs, a wet September which restricted the moving of equipment, combined with an increase in the industry's drilling rig fleet. This resulted in declining utilization rates throughout the oilfield services industry, particularly in the fourth quarter, which historically tends to be one of the most active quarters of the year.
Part of the reason for the declining rig utilization rate and an additional factor impacting the oilfield service sector in the WCSB is the significant increase in oilfield services equipment that is available. With the high utilization levels in the past number of years, many entities undertook significant expansion programs to get new equipment in the field to meet escalating demand. However, the reduction in drilling activity in the latter half of 2006 resulted in declining utilization rates and lower earnings for the oilfield services sector.
SELECTED FINANCIAL INFORMATION
As at As at
and for the and for the
year ended 341-days ended
December 31, December 31,
(Thousands, except per unit amounts) 2006 2005
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Revenue $ 199,565 $ 125,460
Gross margin $ 66,224 $ 46,237
Gross margin as a percentage of revenue 33% 37%
EBITDA $ 47,026 $ 31,510
EBITDA as a percentage of revenue 24% 25%
Net earnings: $ 27,644 $ 16,512
Per unit - basic $ 1.68 $ 1.40
Per unit - diluted $ 1.66 $ 1.38
Funds flow from operations: $ 43,902 $ 30,898
Per unit - basic $ 2.67 $ 2.62
Per unit - diluted $ 2.64 $ 2.58
Payout ratio 62% 54%
Cash distributions to Unitholders: $ 27,307 $ 16,731
Per unit $ 1.64 $ 1.39
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Total assets $ 323,033 $ 232,369
Operating line of credit and total long-term debt $ 54,872 $ 27,628
Unitholders' equity $ 213,546 $ 152,171
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OVERVIEW
2006 was a year of continued growth for Builders. From a financial perspective, we were able to achieve the following:
- Net earnings increased by $11.1 million (to $27.6 million from $16.5 million) as a result of strong results from our Service Rigs and Downhole Services & Rentals segments, strategic acquisitions made in the year, and a full year of operations;
- An increase in our funds flow from operations of $13.0 million (to $43.9 million from $30.9 million);
- Increased distributions by $0.01 per unit per month commencing May 2006 (to $0.14 per unit per month from $0.13 per unit per month) which resulted in a payout ratio as a percentage of funds flow from operations of 62% for the year ended December 31, 2006;
- Completion of an equity financing for gross proceeds of $30.0 million in August 2006 that strengthened our financial position; and
- Expansion of our credit facility from $70.0 million to $100.0 million.
In addition to our financial achievements and more significant to the realization of our long-term strategy, we had the following operational highlights during the year:
- Organized our businesses into three distinct operating segments and put in place Divisional Directors to oversee these segments;
- Continued growth through acquisitions and investment in existing operations. The addition of Kodiak and Murphy's to our Service Rigs segment and Leachman and Prime to our Oilfield Transport segment, expanded our customer base and geographic presence in the WCSB;
- The fabrication of three service rigs at our rig fabrication facility in Brooks, Alberta allowed us to add to our service rig fleet and meet customer demand in a period where extended lead times for new equipment made it difficult for our competitors to deploy new equipment into the field on a timely basis; and
- Began implementation of a common financial system and information technology infrastructure across all segments which will allow us to leverage this infrastructure for future growth upon completion in 2007.
RESULTS OF OPERATIONS
For the For the
year 341-days
ended ended
December 31, December 31,
(Thousands, except per unit amounts) 2006 2005
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Revenue by segment:
Service Rigs $ 56,885 $ 30,827
Oilfield Transport 61,058 42,337
Downhole Services & Rentals 81,622 52,296
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Revenue 199,565 125,460
Operating expenses 133,341 79,223
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Gross Margin 66,224 46,237
Gross margin as a percentage of revenue 33% 37%
General and administrative and other 19,198 14,727
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EBITDA 47,026 31,510
EBITDA as a percentage of revenue 24% 25%
Depreciation and amortization 18,461 10,247
Interest 3,092 1,225
Loss on disposal of equipment 189 262
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Earnings before income taxes and non-
controlling interest 25,284 19,776
Income tax (recovery) expense (3,681) 1,882
Non-controlling interest 1,321 1,382
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Net earnings $ 27,644 $ 16,512
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Per unit - basic $ 1.68 $ 1.40
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Per unit - diluted $ 1.66 $ 1.38
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Net earnings increased $11.1 million for the year ended December 31, 2006 relative to the 341-days ended December 31, 2005 of $16.5 million. The increase was driven from the Service Rigs and Downhole Services & Rentals segments as a result of acquisitions and new equipment, combined with a full twelve months of operations. Additionally, a future tax recovery of $3.1 million was recognized related to Alberta and Federal corporate tax rate reductions enacted during 2006.
Increases in gross margin, EBITDA and earnings before income taxes and non-controlling interest for the year reflects higher service utilization levels in the first quarter of 2006 versus 2005 as a result of strong industry fundamentals. In addition, acquisitions, investment in equipment and a full twelve months of operations versus 341 days for 2005 led to year-over-year improvements. The annual results in all segments were impacted by a downturn in activity levels in the fourth quarter resulting from wet weather that delayed equipment moves and a reduction in natural gas drilling activity attributed to weakening prices for natural gas.
Gross margin and EBITDA percentages have declined from 2005 due to a year-over-year change in our services mix and lower utilization rates in the Oilfield Transport segment. The 2005 and 2006 acquired businesses had lower gross margins on average resulting in a reduced gross margin and EBITDA percentage for the year ended December 31, 2006 as compared to the 341-days ended December 31, 2005. A full year of operations from the 2005 Tryton and Endeavor acquisitions increased the weighting of our Downhole Services & Rentals segment which has a relatively lower gross margin and EBITDA as a percentage of revenue. In addition, in 2006, lower profitability from our Oilfield Transport segment caused by reduced utilization rates reduced overall percentages.
General and administrative expenses, excluding non-cash unit-based compensation, was nine percent of revenues for the year ended December 31, 2006 as compared to ten percent of revenues for the 341-days ended December 31, 2005. This percentage has declined as a result of efficiencies in relation to operational size.
Service Rigs
This segment provides well completion and production/workover services in northeastern British Columbia and western, central, northern and southeastern Alberta. Our Service Rigs segment is comprised of a fleet of 36 service rigs, two Flushby Units and one Rod Rig. From a strategic perspective, the Service Rigs segment has taken the lead integrating into a segment structure by sharing equipment and resources across business units in order to meet customer demand and improve equipment utilization rates. The additions of Kodiak in Fort St. John, British Columbia and Murphy's in Slave Lake, Alberta expanded our geographic presence across the entire WCSB and added depth to our Service Rig fleet.
This segment performed extremely well in 2006, exceeding our 2005 results for existing operations. Overall, revenue was $56.9 million and net earnings before taxes and non-controlling interest was $15.5 million, increases of $26.1 million (85 percent) and $6.5 million respectively (71 percent) from 2005. Our revenue increased by $10.5 million for existing operations as a result of equipment expenditures of $9.6 million in 2006 and $5.2 million in 2005 combined with a full operating year. The Puma, Kodiak and Murphy's acquisitions increased our 2006 revenue by $15.6 million.
The 2006 growth was partially mitigated by slightly lower service rig utilization rates relative to 2005. Service rig utilization rates were very strong during the first half of the year but slowed starting in mid-September due to a reduction in completion services attributed to falling natural gas prices. Completion services related to natural gas represent approximately 25 percent of our Service Rigs' activity. Additionally, an unseasonably warm start to the 2006/2007 winter prevented sufficient ground freezing to allow access to certain remote crude oil and natural gas well sites.
Oilfield Transport
The Oilfield Transport segment is comprised of rig relocation and general oilfield transportation operations in southeastern Alberta and southwestern Saskatchewan, and pipe hauling and general oilfield hauling in central, eastern and northwestern Alberta. The services offered in this segment are from a fleet of 155 trucks and tractors using specialized equipment and highly skilled operators. Leachman and Prime were acquired in 2006, expanding our customer base and geographic presence in this segment across the WCSB. These operations added a presence in crude oil areas in Alberta. Leachman provides pipe and general oilfield hauling to the heavy oil area in the Provost, Alberta area. Prime provides general oilfield hauling in the Grande Prairie, Alberta region.
Strong revenues from the acquisitions of Leachman and Prime, acquired on February 1, 2006 and August 1, 2006 respectively, contributed to revenue growth in the segment. Leachman had strong revenues as general oilfield transportation related to heavy oil activity in eastern Alberta was less impacted by the downturn in natural gas activity in the latter half of 2006. Prime also demonstrated strong revenues through general oilfield transportation related to conventional crude oil activity in northwestern Alberta. Revenue for the segment was $61.1 million, an increase of $18.8 million (44 percent) from $42.3 million in 2005. Net earnings before taxes and non-controlling interest was $5.8 million, a decrease of $3.2 million (36 percent) from $9.0 million during 2005. Including equipment expenditures of $18.0 million in 2006 and $15.5 million in 2005 combined with a full operating year, our revenue increased by $3.9 million for existing operations and approximately $14.9 million as a result of the Leachman and Prime acquisitions.
Coming off a strong year in 2005 that saw results exceed internal expectations, this segment was expected to have strong operating results in 2006. Significant investments made in both equipment and people in 2005 and 2006 were expected to meet strong demand in southeastern Alberta. These expectations did not materialize and minimal revenue increases of $3.9 million were offset by higher operating costs and depreciation charges resulting from the investment in equipment and staff. Two primary factors impacted expectations. The first factor was the impact of wet spring weather in southeastern Alberta which reduced activity levels associated with moving conventional drilling rigs from site-to-site. The opposite was true in 2005, where strong first half results from favourable weather in the area had allowed drilling activity to exceed expected levels. The second factor was the curtailment of drilling programs in the latter half of the year, as natural gas prices began to soften. This slowdown in natural gas drilling activity impacted both our pipe hauling operation in central Alberta and the rig moving business in southeastern Alberta.
Downhole Services & Rentals
The Downhole Services & Rentals segment is comprised of below ground oilfield services and equipment rentals. We offer wireline, coil-tubing, nitrogen and downhole tools services and equipment rentals located in central and eastern Alberta. These services are delivered from a fleet of 20 wireline units, including electric and slickline, 9 coil tubing units and 6 nitrogen units as well as a variety of downhole tools and drilling-related rental equipment.
Our Downhole Services & Rentals segment performed well in 2006, exceeding 2005 levels. Overall, revenue for the Downhole Services & Rentals segment was $81.6 million and net earnings before taxes and non-controlling interest was $19.2 million, increases of $29.3 million (56 percent) and $7.5 million (64 percent) respectively from 2005. The 2005 acquisitions of Tryton and Endeavor, equipment expenditures of $14.9 million in 2006 and $7.7 million in 2005, combined with a full operating year, all contributed to the increases.
Our mix of oil and gas related services contributed towards 2006 growth in profitability despite weaker industry fundamentals relative to 2005. Heavy oil drilling activity in eastern Alberta was strong throughout 2006, relative to 2005, which contributed to our downhole tools profitability. Our rentals business also delivered stronger results during the first half of 2006, relative to 2005, as natural gas drilling rig utilization rates remained high. Rental activities declined in the latter half of 2006 as drilling programs were curtailed due to lower natural gas prices attributed to historically high natural gas inventories, a wet September, and a mild start to the 2006/2007 winter that restricted access to certain well-sites. Finally, our wireline, nitrogen and coil-tubing services contributed to profitability mainly due to strong first quarter shallow natural gas well production-related services but did not meet our expectations due to a severe reduction in shallow natural gas activity later in the year.
Corporate
Corporate is our non-operating segment and includes interest expenses from our operating line of credit and term acquisition loan facility and general and administrative expenses related to Calgary personnel, including unit-based compensation. General and administrative expenses related to certain administrative personnel in the field offices are included within the earnings of the operating segments.
Interest expense in 2006 has increased as a result of higher average debt outstanding combined with an increase in the prime lending rate. Interest rates on our term acquisition loan facility averaged 6.50 percent for 2006, compared with 5.29 percent for 2005.
The general and administrative expense increase over the previous period reflects the increased administrative functions to support our growth and a full year of operations, as compared to the 341-day period in 2005. Recognized through general and administrative expenses, unit-based compensation, which includes the unit option plan ("Option Plan"), increased $0.3 million during 2006 due to an additional 279,714 options granted to certain new employees.
During the fourth quarter, a long-term incentive plan ("LTIP") was implemented to retain and motivate certain key personnel. The LTIP differs from the Option Plan as it does not require the issuance of additional Trust units.
LTIP units entitle the participant to receive a cash payment equal to the excess of the market price of Builders' Trust units at the time of exercise over the exercise price of the LTIP unit. Paid cash distributions per Trust unit between the date of grant and exercise reduce each LTIP unit's exercise price, provided a minimum cost of capital return is achieved. LTIP units granted vest evenly over three years from the grant date and expire after five years.
Builders granted 1,400,425 LTIP units at an exercise price of $10.59 per unit on January 8, 2007.
On March 8, 2007 there were 1,400,425 LTIP units outstanding of which nil were exercisable.
Income Taxes
Current income tax expense increased $1.0 million from 2005 as a result of the growth in profitability from 2005 and 2006 acquisitions and a full year of operations. Our trust structure includes certain subsidiaries which are subject to the payment of corporate income taxes. Builders expects to pay a nominal amount of corporate income taxes in respect of its 2007 operations.
The 2006 future tax recovery relates to the Alberta and Federal corporate tax rate reductions totalling $3.1 million, with the remaining $2.6 million attributed to the reversal of temporary differences of taxable losses in certain Trust subsidiaries.
FINANCIAL RESOURCES AND LIQUIDITY
We manage the financial resources and liquidity of the Trust by balancing distributions to Unitholders, repayment of debt, funding for equipment and business acquisitions. Distributions to Unitholders and maintenance capital is funded through funds flow from operations. Growth capital and business acquisitions are primarily financed through funds flow from operations, debt and equity. We use funds flow from operations and EBITDA as measures to ensure that resources are sufficient to meet anticipated cash distributions, maintenance capital and scheduled debt repayments. Non-cash working capital is not included as part of these measures as the most significant component of non-cash working capital is accounts receivable and we assess the ability of the Trust to meet funding commitments based on the ability of the operations to generate cash.
Funds Flow from Operations
For the For the
year 341-days
ended ended
December 31, December 31,
(Thousands, except per unit amounts) 2006 2005
---------------------------------------------------------------------------
Cash flow from operations $ 41,117 $ 17,913
Add back:
Changes in non-cash operating working
capital 2,785 12,985
---------------------------------------------------------------------------
Funds flow from operations $ 43,902 $ 30,898
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Per unit - basic $ 2.67 $ 2.62
Per unit - diluted $ 2.64 $ 2.58
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Funds flow from operations for the year ended December 31, 2006 increased by $13.0 million from the 341-days ended December 31, 2005 of $30.9 million. The year-over-year growth reflects strong operational performance supplemented by growth from acquisitions and equipment expenditures.
Payout Ratio
A key metric used in ensuring that distribution levels are in-line with funds flow from operations is the payout ratio. Unlike a more traditional corporate structure, trusts are structured to make distribution payments to unitholders.
For the For the
year 341-days
ended ended
December 31, December 31,
(Thousands, except per unit amounts) 2006 2005
---------------------------------------------------------------------------
Funds flow from operations(1) $ 43,902 $ 30,898
Distributions:
Paid 24,724 14,830
Payable 2,583 1,901
---------------------------------------------------------------------------
Distributions declared $ 27,307 $ 16,731
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Total distributions per unit $ 1.64 $ 1.39
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Payout ratio 62% 54%
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(1) Funds flow from operations is a non-GAAP measure and is reconciled
from the most relevant GAAP measure, cash flow from operations, in
the "Funds Flow from Operations" table.
Since the commencement of operations on January 25, 2005, we have increased distributions by 17 percent, while maintaining a conservative payout ratio. Despite deteriorating industry conditions in late 2006 and early 2007, we expect distributions to continue unchanged throughout 2007, which reflects our expectations of solid operational performance. Commencing with the May 2006 distribution, we increased our monthly cash distribution by eight percent to $0.14 per Trust unit ($1.68 per annum). As at December 31, 2005, our monthly cash distribution was $0.13 per Trust unit ($1.56 per annum), reflecting an increase of eight percent, from $0.12 per Trust unit ($1.44 per annum) as announced in September, 2005.
Distributions declared have increased significantly, reflecting the aforementioned distribution increases combined with the Trust unit issuances for the June and November 2005 private placements, the August 2006 Trust unit prospectus offering and Trust unit consideration for the 2006 acquisitions of Leachman, Kodiak, Prime and Murphy's and the 2005 acquisitions of Tryton, Endeavor and Puma. On a per unit basis, 2006 distributions have increased greater than funds flow, leading to an increase in the payout ratio.
Distributions declared during the 2006 and 2005 periods were entirely funded through cash flow from operations. During 2006, cash flows from operations in excess of distributions contributed $13.8 million (2005 - $1.2 million) for scheduled debt repayments and to partially finance equipment expenditures.
Distributable Cash
For the For the
year 341-days
ended ended
December 31, December 31,
(Thousands, unless otherwise stated) 2006 2005
---------------------------------------------------------------------------
Funds flow from operations(1) $ 43,902 $ 30,898
Scheduled principal repayments on long-term
debt(2) (2,692) (2,568)
Maintenance capital(3) less proceeds on the
disposal of equipment (1,978) (1,617)
---------------------------------------------------------------------------
Distributable cash $ 39,232 $ 26,713
---------------------------------------------------------------------------
Total distributions $ 27,307 $ 16,731
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Total distributions as a percentage of
distributable cash 70% 63%
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(1) Funds flow from operations is a non-GAAP measure and is reconciled from
the most relevant GAAP measure, cash flow from operations, in the
"Funds Flow from Operations" table.
(2) Total repayments of long-term debt were $21.5 million (2005 - $36.5
million) of which $2.7 million (2005 - $2.6 million) were scheduled
principal repayments on long-term debt. Of the remaining $3.7 million
of term debt and capital leases, $2.0 million is scheduled to be repaid
in 2007.
(3) Maintenance capital is a non-GAAP measure and is reconciled to the GAAP
measure, equipment expenditures, in the table "Equipment Expenditures".
At establishment of the Trust, we targeted long term distributions as a percentage of distributable cash of 65 to 70 percent. During slower periods of the sector, higher distributions as a percentage of distributable cash are considered acceptable to management and in line with this long-term target. This target rate was established to accommodate the cyclical nature of the industry. We continue to be disciplined in setting the distribution level, and evaluating whether funds flow allow for sustainable distributions. We plan to continue distributions at $0.14 per Trust unit per month ($1.68 per annum) but will carefully monitor industry and market conditions.
Returns on capital are generally taxed as ordinary income to a Unitholder resident in Canada. Returns of capital are generally non-taxable to a Unitholder resident in Canada, but reduce the holder's adjusted cost base of the Trust units for tax purposes. The portion of a Unitholder's 2006 cash distribution taxable as a return on capital was 93.4 percent (2005 - 83.2 percent) and the portion taxable as a return of capital was 6.6 percent (2005 - 16.8 percent).
2006 Acquisitions
(Thousands) Leachman Kodiak Prime Murphy's Total
---------------------------------------------------------------------------
Consideration:
Cash and direct costs $ 5,144 $ 9,592 $ 7,320 $ 6,300 $ 28,356
Trust units 2,450 8,250 8,660 5,413 24,773
Series B Exchangeable
shares 1,050 - - - 1,050
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$ 8,644 $ 17,842 $ 15,980 $ 11,713 $ 54,179
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Issued:
Trust units 150 499 536 344 1,529
Series B Exchangeable
shares 64 - - - 64
---------------------------------------------------------------------------
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On October 3, 2006, we acquired Murphy's, a Service Rig operation located in Slave Lake, Alberta; on August 1, 2006, Builders acquired Prime, an Oilfield Transport operation located in Grande Prairie, Alberta; on May 8, 2006, we acquired Kodiak, a Service Rig operation located in Fort St. John, British Columbia; and on February 1, 2006, we acquired Leachman, an Oilfield Transport operation located in Provost, Alberta. These acquisitions are key to achieving our strategy as they expanded our equipment fleet, customer base and geographic presence in key, high activity areas in the WCSB.
Equipment Expenditures
For the For the
year 341-days
ended ended
December 31, December 31,
(Thousands) 2006 2005
---------------------------------------------------------------------------
Growth capital expenditures:
Service Rigs $ 8,795 $ 4,358
Oilfield Transport 13,669 13,550
Downhole Services & Rentals 12,927 6,650
Corporate 1,100 552
---------------------------------------------------------------------------
$ 36,491 $ 25,110
Maintenance capital expenditures 7,113 3,838
---------------------------------------------------------------------------
Investment in equipment 43,604 28,948
Proceeds on disposal of equipment (5,135) (2,221)
---------------------------------------------------------------------------
Net equipment expenditures $ 38,469 $ 26,727
---------------------------------------------------------------------------
---------------------------------------------------------------------------
We continued to add equipment in 2006 in areas where we have operational opportunities to meet industry activity levels. Geographical diversity of our segments allows deployment of our fleet to areas with strong demand. Of the $43.6 million in equipment expenditures incurred during 2006, $9.2 million was under construction as at December 31, 2006 and the majority is scheduled for deployment within the first-quarter of 2007.
The increase in growth capital of $11.4 million was due to incremental equipment additions of $4.4 million and $6.3 million in the Service Rigs and Downhole Services & Rentals segments, respectively. Our Service Rig Fabrication Facility ("Fabrication Facility") allowed for the internal fabrication of service rigs and service rig equipment resulting in significant cost savings and greater control over equipment delivery time.
Maintenance capital expenditures are equipment additions that are not expected to add incremental revenues. These expenditures are partially financed by proceeds from the disposal of older equipment that is periodically replaced with new equipment.
Non-controlling Interest
For the
For the year ended 341-days ended
December 31, 2006 December 31, 2005
---------------------------------------------------------------------------
(Thousands) Securities Amount Securities Amount
---------------------------------------------------------------------------
Series A and Series B
Exchangeable shares
Balance, beginning of period 946 $ 10,807 - $ -
Consideration for
Acquisition(s) 64 1,050 1,011 10,107
Conversion to Trust units (421) (5,297) (65) (682)
Earnings attributable to
non-controlling interest - 1,321 - 1,382
---------------------------------------------------------------------------
Balance, end of period 589 $ 7,881 946 $ 10,807
---------------------------------------------------------------------------
Exchange ratio, end of period 1.2054 1.0887
Trust units issuable upon
conversion, end of period 710 1,030
---------------------------------------------------------------------------
---------------------------------------------------------------------------
The Exchangeable shares are convertible into Trust units at the exchange ratio in effect on the conversion date. These shares are normally issued only in conjunction with private company acquisitions and generally are outstanding for a duration of less than three years. The exchange ratio, which was initially equal to one to one, is cumulatively adjusted each time a distribution is made to Unitholders using a specified exchange ratio calculation. As at December 31, 2006, the 588,988 (2005 - 945,691) Exchangeable shares outstanding would have converted into 709,966 (2005 - 1,029,574) Trust units. These shares have economic rights and voting attributes equivalent to those of the Trust units into which they are exchangeable.
The 64,417 Series B Exchangeable shares issue were partial consideration for the February 1, 2006 Leachman acquisition. The entire outstanding Series B Exchangeable shares were converted at a ratio of 1.0398 per share during June, 2006, for 66,978 Trust units. As such, there are no outstanding Series B Exchangeable shares as at December 31, 2006.
The 1,010,691 Series A Exchangeable shares were partial consideration for the January 25, 2005 IPO Acquisitions. During 2005 there were 65,000 Series A Exchangeable shares converted at an average ratio of 1.0292 per share for 66,899 Trust units. During 2006 there were 356,703 Series A Exchangeable shares converted at an average ratio of 1.0981 per share for 391,706 Trust units.
As at March 8, 2007, there were 299,960 Series A Exchangeable shares outstanding that were convertible at a ratio of 1.2375 per share into 371,201 Trust units.
Trust and Subordinated Units
Issued and outstanding
------------------------------------------
For the
For the year ended 341-days ended
(Thousands) December 31, 2006 December 31, 2005
---------------------------------------------------------------------------
Units Amount Units Amount
---------------------------------------------------------------------------
Balance, beginning of period 13,624 $ 148,290 - $ -
Public offering, for cash 1,765 30,005 5,100 51,000
Consideration for acquisitions 1,529 24,773 5,669 63,055
Private placements - - 2,788 40,011
Conversion of Exchangeable
shares 459 5,297 67 682
Exercise of Trust unit options
for cash 76 740 - -
Fair value of exercised Trust
unit options - 203 - -
Issue costs - (1,725) - (6,458)
---------------------------------------------------------------------------
17,453 207,583 13,624 148,290
Subordinated units issued for
cash on January 25, 2005 1,000 2,500 1,000 2,500
---------------------------------------------------------------------------
Balance, end of period 18,453 $ 210,083 14,624 $ 150,790
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Trust units and Subordinated units have the same rights with respect to voting but distributions in respect of Subordinated units are, until December 31, 2007, subordinated to distributions to Trust units. During 2006 and 2005 there were no unpaid portions of cumulative distributions on Subordinated units as monthly distributions have exceeded twelve cents per unit per month throughout these periods. On January 1, 2008, the Subordinated units are eligible for conversion into 1,000,000 Trust units.
During the year ended December 31, 2006, in addition to the 1,528,961 Trust units issued as partial consideration for the acquisitions of Murphy's, Prime, Kodiak, and Leachman, the following transactions occurred:
- August 2006 public offering of 1,765,000 Trust units for $17.00 per Trust unit raised gross proceeds of $30.0 million. Net proceeds after issuance costs were $28.3 million. The proceeds were used for the repayment of indebtedness, to fund the equipment expenditure and acquisition programs and for working capital purposes.
- 391,706 Trust units were issued in exchange for 356,703 Series A Exchangeable shares and 66,978 Trust units were issued in exchange for 64,417 Series B Exchangeable shares.
- For the twelve months ended December 31, 2006, we issued 75,950 Trust units on exercise of Trust unit options.
During the 341-days ended December 31, 2005, in addition to the 1,834,246 Trust units issued as partial consideration for the acquisitions of Tryton, Endeavor and Puma, the following transactions occurred:
- On November 30, 2005 we closed a private placement of 1,588,000 Trust units at a price of $15.75 per Trust unit for total gross proceeds of $25.0 million. Net proceeds after issuance costs were $23.6 million. These funds were used to fund the ongoing equipment expenditure and acquisition programs and for general corporate purposes.
- On June 2, 2005 we closed a private placement of 1,200,000 Trust units at a price of $12.50 per Trust unit for total gross proceeds of $15.0 million. Net proceeds after issuance costs were $14.0 million. These funds were used for equipment expenditures and the Endeavor acquisition that closed on July 21, 2005.
- On January 25, 2005, we completed an IPO of 5,100,000 Trust units at $10 each, for total gross proceeds of $51.0 million less agents' commissions of $3.1 million and other expenses of $0.9 million. The net proceeds of $47.0 million were used for the IPO Acquisitions. An additional 3,835,226 units were issued as part of the purchase consideration for the IPO Acquisitions.
- On January 25, 2005 as part of the IPO, 1,000,000 Subordinated Trust units were issued to the founders of the Trust for proceeds of $2.5 million.
As at March 8, 2007, there were 18,818,742 Trust units and 1,428,326 Trust unit options outstanding. Of the 1,428,326 Trust unit options, 674,110 were exercisable of which 561,818 were "in-the-money".
Future Equity Offerings
On October 31, 2006 the federal government proposed a "Tax Fairness Plan" to tax income trusts, commencing January 1, 2011, at a proposed rate of 31.5 percent on cash distributions to unitholders. The ability to raise financing through trust unit issues is permitted, without conversion to a corporation, provided such financings occur within certain restrictions ("Safe Harbour").
Under the proposed "Tax Fairness Plan" legislation, as at March 8, 2007, Builders' available Safe Harbour through to December 31, 2007 was $102.4 million which represents 40 percent of the adjusted market capitalization (the "Benchmark") as at the date of announcement of the "Tax Fairness Plan". The Safe Harbour from 2008 through to 2010 for Builders is $51.2 million each year, which represents 20 percent per year of the Benchmark. Should any portion of the Safe Harbour not be utilized, this portion becomes available in a subsequent period. Income trust to income trust business combinations are expected to be permitted without affecting the Safe Harbour rules.
The ability to finance through public or private offerings of Trust units has been impacted by the proposed "Tax Fairness Plan" legislation combined with the temporary downturn in the oilfield services industry. Although we can still finance through a public or private offering of Trust units, the current market value, which translates into a relatively high distribution yield and an implied high cost of capital of our Trust units, makes this form of financing unattractive. As a result, our strategy of growth through acquisitions will likely be tempered during 2007. However, this will not hinder us from exploring merger opportunities with other oilfield services income trusts or acquisitions of oilfield service companies where accretive growth can be achieved for our Unitholders.
Credit Facilities and Other Long-term Debt
i) Credit facilities:
---------------------------------------------------------------------------
As at December 31, 2006
---------------------------------------------------------------------------
Total
credit
(Thousands) Outstanding Unutilized facility
---------------------------------------------------------------------------
Credit facilities:
Operating line of credit $ 2,650 $ 17,350 $ 20,000
Term acquisition loan facility 48,495 31,505 80,000
---------------------------------------------------------------------------
Total $ 51,145 $ 48,855 $ 100,000
---------------------------------------------------------------------------
---------------------------------------------------------------------------
---------------------------------------------------------------------------
As at December 31, 2005
---------------------------------------------------------------------------
Total
credit
(Thousands) Outstanding Unutilized facility
---------------------------------------------------------------------------
Credit facilities:
Operating line of credit $ 5,700 $ 14,300 $ 20,000
Term acquisition loan facility 14,895 35,105 50,000
---------------------------------------------------------------------------
Total $ 20,595 $ 49,405 $ 70,000
---------------------------------------------------------------------------
---------------------------------------------------------------------------
In August 2006, we amended our credit facility to include a fourth major Canadian chartered bank and increased the total available facility to $100.0 million (2005 - $70.0 million), comprised of an operating line of credit of $20.0 million (2005 - $20.0 million) and a term acquisition loan facility of $80.0 million (2005 - $50.0 million). The unutilized portions of the operating and acquisition facilities are expected to be sufficient to meet existing operating commitments and capital spending for the next year. As at December 31, 2006, all financial debt covenants were satisfied and all banking requirements were up to date. We do not anticipate any covenant issues will restrict our future operating, investing or financing activities.
The amount outstanding on the operating facility decreased as at December 31, 2006 relative to 2005 due to timing of changes for non-cash working capital.
During 2006, $14.0 million of the term acquisition loan facility was repaid through partial use of proceeds received from the issuance of Trust units pursuant to the public offering completed in August 2006.
During 2006, $47.6 million (2005 - $31.7 million) of the term acquisition loan facility was drawn. The debt was drawn to partially finance acquisitions and the growth capital program.
During 2005, $16.8 million of the term acquisition loan facility was repaid, of which $12.3 million was repaid related to the IPO Acquisitions. The remaining debt was repaid through partial use of proceeds received from the issuance of Trust units pursuant to the two private placements that were completed in 2005.
The term date of the operating line of credit and the term acquisition loan facility is May 30, 2007. At this time, it is our intention to renew the facilities for an additional 364 days. Since the term date occurs within one year, as at December 31, 2006, $9.4 million (2005 - $2.9 million) of the acquisition facility has been recognized as part of the current portion of long-term debt in current liabilities.
ii) Other long-term debt:
As at As at
December 31, December 31,
(Thousands) 2006 2005
---------------------------------------------------------------------------
Term debt and capital leases 3,727 7,033
---------------------------------------------------------------------------
---------------------------------------------------------------------------
The term debt and capital leases are repayable in monthly installments of $0.2 million, including interest, at a weighted average interest rate of 6.67 percent, and mature between January 2007 and December 2010. The contracts and leases are collateralized by specific equipment. Scheduled debt repayments during 2007 on term debt and capital leases is $2.0 million, with the remaining $1.7 million scheduled for repayment primarily in 2008 and 2009.
FINANCIAL INSTRUMENTS
Fair Values
The carrying values of accounts receivable, bank indebtedness, operating line of credit, accounts payable and accrued liabilities, distributions payable and long-term debt approximate their fair value due to the relatively short period of maturity of these instruments or because they are based on the prime lending rate. At December 31, 2006, the long-term debt had a carrying and fair value of $52.2 million (2005 - $21.9 million) due to the fact that interest associated with the term acquisition loan facility is directly tied to the prime rate.
Interest Rate Risk
Our operating line of credit and term acquisition loan facility bear interest at a floating interest rate. Therefore, to the extent we borrow under these facilities, we are at risk to rising interest rates.
Credit Risk
Our accounts receivable are with customers involved in the crude oil and natural gas industry, whose revenue is impacted by fluctuations in commodity prices. Although collection of these receivables could be influenced by the current economic factors affecting the industry, we consider the risk of significant loss to be minimal at this time.
CONTRACTUAL OBLIGATIONS
(Thousands) 2007 2008 2009 2010 2011+
---------------------------------------------------------------------------
Operating leases $ 4,236 $ 4,433 $ 4,238 $ 3,528 $ 6,593
Term debt and capital leases 2,003 1,178 462 84 -
---------------------------------------------------------------------------
Total $ 6,239 $ 5,611 $ 4,700 $ 3,612 $ 6,593
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Operating leases relate to the leasing of equipment, property and buildings from both third parties and related parties. Term debt and capital leases were a component of the acquisitions completed during 2005 and 2006. These contracts primarily relate to the financing of vehicles and equipment.
Related Parties
During the normal course of operations, on commercial terms established and agreed to by the related parties, we rent land and buildings from certain former owners of businesses acquired. For the year ended December 31, 2006, $2.3 million (2005 - $1.3 million) has been included in operating expenses for these items.
OFF-BALANCE SHEET ARRANGEMENTS
As at December 31, 2006 and 2005, we have not entered into any off-balance sheet arrangements.
SUMMARY OF QUARTERLY DATA
For the For the For the For the
three three three three For the
months months months months year
ended ended ended ended ended
(Thousands, except Mar. 31, June 30, Sept. 30, Dec. 31, Dec. 31,
per unit amounts) 2006 2006 2006 2006 2006
---------------------------------------------------------------------------
Revenue $ 62,754 $ 34,590 $ 50,422 $ 51,799 $ 199,565
Net earnings 11,870 3,978 6,554 5,242 27,644
Per-unit - basic 0.79 0.26 0.39 0.28 1.68
Per-unit - diluted 0.78 0.25 0.38 0.28 1.66
Funds flow from
operations 16,913 5,719 11,852 9,418 43,902
Per-unit - basic 1.13 0.37 0.71 0.51 2.67
Per-unit - diluted 1.05 0.35 0.70 0.51 2.64
Distributions per
unit $ 0.39 $ 0.41 $ 0.42 $ 0.42 $ 1.64
Payout ratio 35% 112% 61% 82% 62%
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For the For the For the
For the three three three For the
66-days months months months 341-days
ended ended ended ended ended
(Thousands, except Mar. 31, June 30, Sept. 30, Dec. 31, Dec. 31,
per unit amounts) 2005 2005 2005 2005 2005
---------------------------------------------------------------------------
Revenue $ 20,221 $ 17,303 $ 37,164 $ 50,772 $ 125,460
Net earnings 4,249 83 4,960 7,220 16,512
Per-unit - basic 0.43 0.01 0.39 0.53 1.40
Per-unit - diluted 0.40 0.01 0.38 0.52 1.38
Funds flow from
operations 6,588 2,532 9,234 12,544 30,898
Per-unit - basic 0.66 0.24 0.73 0.93 2.62
Per-unit - diluted 0.57 0.20 0.71 0.90 2.58
Distributions per
unit $ 0.27 $ 0.36 $ 0.37 $ 0.39 $ 1.39
Payout ratio 41% 150% 51% 44% 54%
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Increases in the first, second and third quarter results of 2006 relative to the comparative quarters in 2005 are mainly due to strong oilfield services demand, and growth in our operations and cash flow from acquisitions and equipment expenditures. During the fourth quarter of 2006, our net earnings and funds flow were impacted by a downturn in activity levels resulting from wet weather and a reduction in drilling activity as a result of weakening prices for natural gas.
The second quarter of both 2006 and 2005 was impacted by the annual spring break-up, which leaves many secondary roads temporarily incapable of supporting the weight of heavy equipment and results in restrictions in the level of oilfield service activity. As a result of the seasonality of operations, funds flow in the first quarter has been substantially more than the distributions declared, which is expected. This excess funds flow was used to partially finance the distributions in the second quarter. As utilization levels increase during the third quarter, funds flow is primarily used to finance increases in non-cash working capital and distributions.
FOURTH QUARTER ANALYSIS
For the three For the three
months ended months ended
December 31, December 31,
(Thousands, except per unit amounts) 2006 2005
---------------------------------------------------------------------------
Revenue by segment:
Service Rigs $ 18,548 $ 11,905
Oilfield Transport 16,352 15,534
Downhole Services & Rentals 16,899 23,333
---------------------------------------------------------------------------
Revenue 51,799 50,772
Operating expenses 35,854 32,411
---------------------------------------------------------------------------
Gross Margin 15,945 18,361
Gross margin as a percentage of revenue 31% 36%
General and administrative and other 5,705 4,845
---------------------------------------------------------------------------
EBITDA 10,240 13,516
EBITDA as a percentage of revenue 20% 27%
Depreciation and amortization 5,646 3,314
Interest 1,105 520
Loss (gain) on disposal of equipment (364) 128
---------------------------------------------------------------------------
Earnings before income taxes and non-
controlling interest 3,853 9,554
Income tax (recovery) expense (1,587) 1,780
Non-controlling interest 198 554
---------------------------------------------------------------------------
Net earnings $ 5,242 $ 7,220
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Per unit - basic $ 0.28 $ 0.53
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Per unit - diluted $ 0.28 $ 0.52
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Overall net earnings for the fourth quarter of 2006 decreased $2.0 million from the fourth quarter of 2005, despite the acquisitions of Leachman, Prime, Kodiak, Murphy's and a full quarter for Puma, due to a significant reduction in industry activity levels caused by reduced drilling activity, customer pricing pressures on oilfield services as well as unseasonably warm weather limiting the ability to get into many remote lease sites. Natural gas drilling in the WCSB was curtailed mainly due to weakening natural gas prices. This resulted in lower equipment utilization rates, and correspondingly lower gross margin and EBITDA for the three months ended December 31, 2006 as compared to 2005.
The 2006 acquisitions related to our Service Rigs and Oilfield Transport segments impacted our services mix and partially contributed to a reduction of our gross margin as a percentage of revenue to 31 percent for the three months ended December 31, 2006 as compared to 36 percent for 2005. More significantly, our gross margin as a percentage of revenue was lower as a result of reduced utilization rates in our Oilfield Transport and Downhole Services & Rentals segments, attributed to weaker natural gas industry fundamentals and an unseasonably warm start to the 2006/2007 winter.
Service Rigs
Our Service Rigs segment results increased during the fourth quarter of 2006, relative to 2005, despite lower utilization rates, primarily as a result of the acquisitions of Kodiak and Murphy's, a full quarter of results for Puma which was acquired on October 14, 2005 and $8.8 million in growth capital. Revenue was $18.5 million and net earnings before taxes and non-controlling interest was $4.6 million, increases of $6.6 million (56 percent) and $0.7 million respectively (17 percent) from 2005.
Service rig utilization rates declined in September due to a reduction in shallow natural gas well drilling programs attributed to falling natural gas prices. Additionally, an unseasonably warm start to the 2006/2007 winter prevented sufficient ground freezing to allow access to certain remote well sites.
Oilfield Transport
The Oilfield Transport segment revenues increased year-over-year but lower drilling rig and oilfield hauling activity in our southeast and central operations resulted in lower earnings. Revenue for our Oilfield Transport segment was $16.4 million, an increase of $0.8 million (five percent) from 2005. Net earnings before income taxes and non-controlling interest was $1.1 million, a decrease of $2.2 million (67 percent) from 2005.
The increased revenues resulted from the Leachman and Prime acquisitions in 2006. However, revenue growth attributed to our acquisitions was tempered by lower earnings due to lower industry activity levels which resulted in lower utilization rates in our southeast and central operations combined with increased depreciation charges related to fleet expansion in the fourth quarter of 2005 and the twelve months ended December 31, 2006.
Downhole Services & Rentals
Lower fourth quarter revenues and earnings, relative to 2005, from our Downhole Services & Rentals segment are attributable to this segment's natural gas-related services. Overall, revenue for our Downhole Services & Rentals segment was $16.9 million and net earnings before taxes and non-controlling interest was $2.3 million for the three months ended December 31, 2006, decreases of $6.4 million (28 percent) and $3.0 million respectively (57 percent) from 2005.
The quarter-over-quarter decreases are attributable to unseasonably warm weather, which prevented sufficient freezing to allow access to certain well sites, and the slowdown in natural gas drilling in central Alberta where the majority of our Downhole Services & Rentals operations are located. Coil tubing and nitrogen services decreased significantly quarter-over-quarter primarily due to reduced activity in shallow natural gas wells.
Corporate
Our non-operating Corporate segment losses before income taxes and non-controlling interest of $4.1 million increased by $1.2 million (39 percent) relative to 2005. The increase in losses relates mainly to increases in Calgary general and administrative expenses reflecting the administrative functions to support our growth and allow an operating focus for our businesses. The Corporate interest expense increase is attributable to higher average draws on our operating line of credit and term acquisition loan facility at higher interest rates.
FINANCIAL RESOURCES
Funds Flow from Operations
For the For the
three three
months months
ended ended
December December
(Thousands, except per unit amounts) 31, 2006 31, 2005
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Cash flow from operations $ 9,129 $ 5,814
Add back:
Changes in non-cash operating working capital 289 6,730
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Funds flow from operations $ 9,418 $ 12,544
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Per unit - basic $ 0.51 $ 0.93
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Per unit - diluted $ 0.51 $ 0.90
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Funds flow from operations for the three months ended December 31, 2006 decreased by $3.1 million from the same quarter of 2005 mostly due to a fourth quarter slowdown in industry drilling activity as a result of customer spending reductions related to lower commodity prices. In addition, wet weather made it difficult to move equipment and access remote areas.
The minimal change in non-cash operating working capital for the three months ended December 31, 2006 relates to fourth quarter activity levels being comparable to those experienced in the third quarter of 2006 due to weaker industry fundamentals. Normally we would expect an increase in our non-cash working capital during the fourth quarter as activity levels rise, mainly through an increase in accounts receivable balances.
Payout Ratio
For the For the
three three
months months
ended ended
December December
(Thousands, except per unit amounts) 31, 2006 31, 2005
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Funds flow from operations(1) $ 9,418 $ 12,544
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Distributions declared $ 7,750 $ 5,497
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Total distributions per unit $ 0.42 $ 0.39
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Payout ratio 82% 44%
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(1) Funds flow from operations is a non-GAAP measure and is reconciled from
the most relevant GAAP measure, cash flow from operations, in the
"Funds Flow from Operations" table.
Commencing with the May 2006 distribution, we increased our monthly cash distribution by eight percent to $0.14 per Trust unit ($0.42 per quarter). As at December 31, 2005, our monthly cash distribution was $0.13 per Trust unit ($0.39 per quarter).
Distributions declared have increased significantly, reflecting the distribution increases combined with the Trust unit issuances for the August 2006 public offering, November 2005 private placement and unit consideration issued in conjunction with acquisitions. The fourth quarter 2006 payout ratio has increased over 2005 due to a reduction in industry activity caused by reduced customer drilling.
Distributions declared during the three months ended December 31, 2006 and 2005 were funded through cash flow from operations.
We target distributions as a percentage of distributable cash of 65 to 70 percent on an annualized basis and expect to maintain current distribution levels in 2007.
CRITICAL ACCOUNTING ESTIMATES
In preparing the Trust's consolidated financial statements, we are required to make estimates and assumptions based on information available as of the date of the consolidated financial statements that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements, and revenues and expenses for the periods reported. The most significant of these estimates, as described below, are allowance for bad debts, depreciation and amortization, the valuation of goodwill and long-lived assets, income taxes and unit-based compensation. Actual results could differ from these amounts.
Although estimates and assumptions based on information available at the time are required to be made, it is our opinion that none of the above items identified or other items in Builders' financial statements involve assumptions or estimates that are highly uncertain at the time they were made and that different estimates that the Trust could have used or changes in the accounting estimate that are reasonably likely to occur would have a material impact on the Trust's financial condition, changes in financial condition or results of operations.
Allowance for Bad Debts
We perform credit evaluations of our customers and grant 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. Our 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. As at December 31, 2006 and 2005, we did not have any individual accounts receivable that represented 10 percent or more of the total accounts receivable balance.
Depreciation and Amortization
Equipment is recorded at cost less accumulated depreciation. Intangible assets are recorded at cost less accumulated amortization. Depreciation and amortization are computed based upon our depreciation and amortization policies (see note 2 to consolidated financial statements). The depreciation policies selected are intended to depreciate the related equipment over their useful life. The amortization policies selected are intended to amortize the intangible assets over their expected lives or contracted terms. The use of different assumptions with regard to the useful life could result in different carrying amounts for these assets as well as for depreciation and amortization expense.
Goodwill
The carrying values of reporting units are compared to their fair values at least on an annual basis to determine if there is an indication of impairment. If the carrying value of the reporting unit exceeds its fair value, a determination is conducted of the fair value of the reporting unit's goodwill. If the carrying value of goodwill exceeds its fair value, an impairment would be recognized in earnings. Valuations are inherently subjective and necessarily involve judgments and estimates regarding future cash flows and other operational variables.
Impairment of Long-lived Assets
Equipment and intangible assets are reviewed for impairment when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. In the assessment process, we are required to make certain judgments, assumptions and estimates in identifying such events and changes in circumstances, and in assessing their impact on the valuations and economic lives of these assets. Impairments are recognized when the carrying values exceed our estimate of the fair values of the affected assets.
Income Taxes
We use the liability method of accounting for future income taxes whereby future income tax liabilities are determined based on temporary differences between the accounting and tax bases of the assets and liabilities, and are measured using substantively enacted tax rates and laws expected to apply when these differences reverse. As a result, a projection of taxable income is required for those years, as well as an assumption of the ultimate recovery or settlement period for the temporary differences. The projection of future taxable income is based on our best estimate and may vary from actual taxable income.
In addition, Canadian tax rules and regulations are subject to interpretation and require judgment that may be challenged by the taxation authorities. We believe that our provisions for taxes are adequate.
Unit-based Compensation
Unit-based compensation is comprised of the unit option plan ("Option Plan"). The Option Plan is recognized through general and administrative expenses and is calculated using the fair value method based upon the Black-Scholes model. In order to establish fair value, we use estimates and assumptions to determine risk-free interest rate, expected term, anticipated volatility and distribution yield.
ACCOUNTING POLICIES
During the year ended December 31, 2006, there were no changes made to our accounting policies.
Recent Accounting Pronouncements
The following new accounting standards issued by the Canadian Institute of Chartered Accountants ("CICA") are applicable to us but have not been implemented and are not expected to have a significant impact on the Trust:
CICA Handbook Section 1530 - Comprehensive Income
This standard will be effective for our 2007 reporting period. The standard creates a separate financial statement item that captures items included in other comprehensive income but excluded from income in accordance with GAAP.
CICA Handbook Section 3855 and Section 3861 - Financial Instruments
These standards will be effective for our 2007 reporting period. These standards address the requirement to record financial instruments at fair value in the financial statements unless certain criteria are met allowing them to be recorded at cost or amortized cost.
CICA Handbook Section 1506 - Changes in Accounting Policies and Estimates, and Errors
This standard will be effective for our 2007 reporting period. The standard addresses the acceptability and disclosure requirements for changes in accounting policies, estimates and disclosures of issued standards that have not been adopted but have come into effect.
DISCLOSURE CONTROLS AND PROCEDURES & INTERNAL CONTROLS OVER FINANCIAL REPORTING
We have designed disclosure controls and procedures to provide reasonable assurance that material information relating to the Trust, including its consolidated subsidiaries, is made known to the President and Chief Executive Officer and the Vice President, Finance and Chief Financial Officer by others within those entities, particularly during the period in which the annual filings of the Trust are being prepared, in an accurate and timely manner in order for the Trust to comply with its continuous disclosure and financial reporting obligations and in order to safeguard assets. We have concluded that the Trust's disclosure controls and procedures, as of the end of the period covered by the annual filings, are effective in providing reasonable assurance that material information is accumulated and disclosed accurately.
In addition to disclosure controls and procedures, the President and Chief Executive Officer and the Vice President, Finance and Chief Financial Officer are responsible for designing internal controls over financial reporting or causing them to be designed under their supervision to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with Canadian GAAP. We have concluded that the Trust's internal controls over financial reporting, as of the end of the period covered by the annual filings, 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.
Consistent with the concept of reasonable assurance, the Trust recognizes that the relative cost of maintaining these controls and procedures should not exceed their expected benefits. As such, the Trust's disclosure controls and procedures and internal controls over financial reporting can only provide reasonable assurance, and not absolute assurance.
BUSINESS RISKS
Industry Activity
The demand, pricing and terms for oilfield services largely depend upon the level of industry activity for Canadian natural gas and, to a lesser extent, oil exploration and development. Industry conditions are influenced by numerous factors over which we have no control, including: the level of oil and gas prices; expectations about future oil and gas prices; the cost of exploring for, producing and delivering oil and gas; the expected rates of declining current production; the discovery rates of new oil and gas reserves; available pipeline and other oil and gas transportation capacity; worldwide weather conditions; global political, military, regulatory and economic conditions; and the ability of oil and gas companies to raise equity capital or debt financing.
The level of activity in the Canadian oil and gas exploration and production industry is volatile. No assurance can be given that expected trends in oil and gas production activities will continue or that demand for oilfield services will reflect the level of activity in the industry. Any prolonged substantial reduction in oil and natural gas prices would likely affect oil and gas production levels and therefore affect the demand for services to oil and gas customers. A material decline in oil or gas prices or Canadian industry activity could have a material adverse effect on our business, financial condition, results of operations and cash flows and therefore on the distributions to holders of Trust units.
Environmental Legislation
Canada is a signatory to the United Nations Framework Convention on Climate Change and has ratified the Kyoto Protocol established thereunder to set legally binding targets to reduce nation-wide emissions of carbon dioxide, methane, nitrous oxide and other so-called "greenhouse gases". The Government of Canada has put forward a Climate Change Plan for Canada which suggests further legislation will set greenhouse gases emission reduction requirements for various industrial activities, including oil and gas exploration and production. Future federal legislation, together with provincial emission reduction requirements may require the reduction of emissions or emissions intensity from our operations and facilities.
Mandatory emissions reductions may result in increased operating costs and equipment expenditures for oil and gas producers, thereby potentially decreasing the demand for our services. Management is unable to predict the impact of the Kyoto Protocol on Builders and it is possible that it will adversely affect our business, financial condition, results of operations and cash flows and therefore, the cash to be distributed to Unitholders.
Realization of Anticipated Benefits of Acquisitions
Achieving the benefits of the acquisitions and any future acquisitions will depend in part on successfully consolidating functions and integrating operations, procedures and personnel of all of our acquisitions in a timely and efficient manner.
Seasonality
In the WCSB, the level of activity in the oilfield services industry is influenced by seasonal weather patterns. Spring break-up during the second quarter leaves many secondary roads temporarily incapable of supporting the weight of heavy equipment, which results in restrictions in the level of oilfield services. The duration of this period has a direct impact on the level of our activities. Spring breakup typically occurs earlier in the year in southeastern Alberta than it does in northern Alberta and British Columbia. The timing and duration of spring breakup are dependent on weather patterns but generally occur in April and May. Additionally, if unseasonably warm winter prevents sufficient freezing, we may not be able to access certain well sites and our operating results and financial condition may therefore be adversely affected.
The demand for oilfield services may also be affected by the severity of the Canadian winters. In addition, during excessively rainy periods, equipment moves may be delayed, thereby adversely affecting revenues. The volatility in the weather and temperature can therefore create unpredictability in activity and utilization rates, which can have a material adverse effect on our business, financial condition, results of operations and cash flows, and therefore on the cash to be distributed to Unitholders.
Alternatives to and Changing Demand for Petroleum Products
Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and gas, and technological advances in fuel economy and energy generation devices could reduce the demand for crude oil and other liquid hydrocarbons. We cannot predict the impact of changing demand for oil and gas products, and any major changes may have a material adverse effect on our business, financial condition, results of operations and cash flows and therefore on the cash to be distributed to Unitholders.
Sources, Pricing and Availability of Equipment and Equipment Parts
We source our equipment and equipment parts from a variety of suppliers. Should any of our suppliers be unable to provide the necessary equipment or parts or otherwise fail to deliver products in the quantities required, any resulting delays in the provision of services or in the time required to find new suppliers could have a material adverse effect on our business, financial condition, results of operations and cash flows, and therefore on the cash to be distributed to Unitholders.
Government Regulation
Our operations are subject to a variety of federal, provincial and local laws, regulations, and guidelines, including laws and regulations relating to health and safety, the conduct of operations, the protection of the environment, the operation of equipment used in our operations and the transportation of materials and equipment we provide for our customers. We believe that our operations are currently in compliance with such laws and regulations.
It is impossible for us to predict the cost or impact of such laws and regulations on our future operations.
Operating Risks and Insurance
Our operations are subject to hazards inherent in the oil and gas industry, such as equipment defects, malfunction and failures, and natural disasters which may result in fires, vehicle accidents, explosions and uncontrollable flows of natural gas or well fluids that can cause personal injury, loss of life, suspension of operations, damage to formations, damage to facilities, business interruption and damage to or destruction of property, equipment and the environment. These risks could expose us to substantial liability for personal injury, wrongful death, property damage, loss of oil and gas production, pollution, and other environmental damages. The frequency and severity of such incidents will affect operating costs, insurability and relationships with customers, employees and regulators.
We will continuously monitor activities for quality control and safety. However, there are no assurances that our safety procedures will always prevent such incidents. Although we will maintain insurance coverage that we believe to be adequate and customary in the industry, there can be no assurance that such insurance will be adequate to cover our liabilities. In addition, there can be no assurance that we will be able to maintain adequate insurance in the future at rates we consider reasonable and commercially justifiable.
The occurrence of a significant uninsured claim, a claim in excess of the insurance coverage limits maintained by us, or a claim at a time when we are not able to obtain liability insurance, could have a material adverse effect on our ability to conduct normal business operations and on our financial condition, results of operations and cash flows, and therefore on the cash to be distributed to Unitholders.
Agreements and Contracts
Our business operations depend on verbal agreements with our customer base that are cancelable at any time by either us or our customers. The key factors that will determine whether a customer continues to use us are service quality and equipment availability, reliability and performance of equipment used to perform our services, technical knowledge and experience, reputation for safety and competitive price.
There can be no assurance that our relationship with our customers will continue, and a significant reduction or total loss of the business from these customers, if not offset by sales to new or existing customers, could have a material adverse effect on our business, financial condition, results of operations and cash flows, and therefore on the cash to be distributed to Unitholders.
Qualified Personnel
The successful operation of our business depends upon the abilities, expertise, judgment, discretion, integrity and good faith of our executive officers, general managers, employees and consultants. In addition, our ability to expand our services depends upon the ability to attract qualified personnel as needed. The demand for skilled employees is high, and the supply is limited.
The unexpected loss of our qualified personnel, including the general managers of the businesses, or the inability to retain or recruit skilled personnel, could have a material adverse effect on our business, financial condition, results of operations and cash flows and therefore on the cash to be distributed to Unitholders.
Competition
The oilfield services business in which we operate is highly competitive. To be successful, we must provide services that meet the specific needs of our customers at competitive prices. The principal competitive factors in the markets in which we operate are service quality and availability, reliability and performance of equipment used to perform our services, technical knowledge and experience and reputation for safety and price.
We compete with several competitors that are both smaller and larger than us. These competitors offer similar services in all geographic regions in which we operate. As a result of competition, we may be unable to continue to provide our present services or to acquire additional business opportunities, which may affect our business, financial condition, results of operations and cash flows and therefore on the cash to be distributed to Unitholders.
Credit Risk
A substantial portion of our accounts receivable is with customers involved in the oil and gas industry whose revenues may be impacted by fluctuations in commodity prices. Collection of these receivables could be influenced by economic factors affecting the oil and gas industry.
Distributions not Guaranteed
The distributions to be paid to our Unitholders are determined by the Board of Directors of Builders Energy Services Limited ("the Administrator") on an on-going basis after considering our financial and strategic situation, including, cash flow, capital requirements, revenue levels and debt levels. Our historical distribution payments may not be reflective of future distribution payments. Distributions are not guaranteed and may be reduced or suspended entirely at the discretion of the Board of Directors of the Administrator.
We have not obtained a stability rating from an independent rating agency regarding the relative stability and sustainability of our cash distribution stream. We may consider obtaining a stability rating from an independent rating agency in the future.
If the Board of Directors determines to reduce or suspend the payment of distributions, this could lead to a material decline in the market value of the Trust units.
Debt Service
The Trust is indebted to certain banks under the credit facility it maintains with a syndicate of lenders. Principal and interest payable under the credit facility have priority over distributions to Unitholders. Accordingly, we may have to reduce or suspend distributions in order to ensure debt amounts are paid. In addition, the terms of the credit facility impose certain restrictive covenants on the Trust and its subsidiaries that may affect the payment of distributions.
Variations in interest rates and scheduled principal repayments, or the need to refinance the credit facility upon expiration, could result in significant changes in the amount required to be applied to service the debt under the credit facility before the distribution or payment of any amounts by the Trust.
There can be no assurance that the amounts available under the credit facility will be adequate for the financial obligations of the Trust and the Administrator or, upon expiration, the credit facility can be refinanced on terms acceptable to the Trust and the Administrator and to the applicable lenders.
Dependence on the Administrator
The Trust is an open-end, limited purpose trust that is entirely dependent upon the operations and assets of its direct and indirect subsidiaries. Accordingly, any cash distributions to the Unitholders are dependent upon the ability of the Administrator to meet its interest and principal repayment obligations and to declare and pay distributions or dividends on its common shares. Income is received from the oil and gas service operations of the Trust and is susceptible to the risks and uncertainties associated with the oil and gas service industry generally. If the Trust is unsuccessful in these operations, its ability to meet its obligations may be adversely affected.
Net Asset Value
The net asset value of the assets of the Trust from time to time will vary dependent upon a number of factors beyond the control of management, including activity in the oil and gas sector. The trading prices of the Trust units from time to time is also determined by a number of factors which are beyond the control of management and such trading prices may be greater than the net asset value of the Trust's assets.
Tax Fairness Plan
The federal Minister of Finance announced proposed changes to the Income Tax Act affecting the taxation of income trusts on October 31, 2006 and released draft legislation for public comment on December 21, 2006. The effect of the "Tax Fairness Plan", if implemented, would be to reduce the cash flow from operations of trusts after January 1, 2011 to the extent of the new tax payable on trusts. There is no certainty that the "Tax Fairness Plan" will be enacted in the form proposed or at all.
The announcement of the "Tax Fairness Plan" created substantial uncertainty concerning the market valuation of income trusts and the ultimate impact of the "Tax Fairness Plan" on the operations and prospects of such entities, which uncertainty may affect the price and market for trust units or increase the volatility of trading in trust units.
In the October 31, 2006 announcement, the Minister of Finance indicated that, while there is now no intention to prevent "normal growth" of existing income trusts until the January 1, 2011 implementation date, any undue expansion of an income trust, such as might be attempted through the insertion of a disproportionately large amount of additional capital, could cause the implementation date for existing income trusts to be revisited.
On December 15, 2006, the Minister of Finance announced further guidance respecting the amount of expansion that would be permitted to an income trust without accelerating the January 1, 2011 implementation date. More particularly, the Minister of Finance has advised that, in general, "normal growth" means the issuance of new equity capital in an aggregate amount that does not exceed the greater of $50 million annually and an objective Safe Harbour. The Safe Harbour will be measured by reference to the trust's market capitalization at the close of trading on October 31, 2006. For the period from November 1, 2006 to December 31, 2007, the trust's Safe Harbour will be 40% of its Benchmark. For each of the calendar years from 2008 to 2010, the Safe Harbour will be 20% of the Benchmark. The annual Safe Harbour is cumulative, but the $50 million annual growth amount is not cumulative. New equity will include trust units and other instruments (such as debt) that are convertible into trust units. Replacing debt that was outstanding at October 31, 2006 with new equity will not be considered to be growth. New, non-convertible debt will not be considered growth, although the replacement of new debt with new equity will be considered growth. To the extent that any person had a right, prior to October 31, 2006, to exchange a share or partnership interest for a trust unit, the issuance of trust units on the exercise of such a right will not be considered to be growth. The guidelines regarding "normal growth" were not incorporated into the draft legislation concerning the "Tax Fairness Plan" released on December 21, 2006 and it is not clear at this time what legislative form those guidelines may take.
The need for the Trust to continue to conduct its operations within the restrictions on equity growth established under the "Tax Fairness Plan" in order to avoid the accelerated application of the "Tax Fairness Plan" may restrict the Trust's ability to raise capital or conduct acquisitions in certain circumstances. This may limit the Trust's ability to execute its business plan or fully capitalize on opportunities for accretive expansion, which may in turn impair the market value of the Trust units.
The change in the tax treatment of distributions on the Trust units that would occur if the "Tax Fairness Plan" is implemented may reduce the attractiveness of the Trust units as an investment to certain Unitholders, including holders not resident in Canada or holders who hold their units within a Registered Retirement Savings Plan. This may reduce the market demand for the Trust units and affect the market value of the Trust units.
Under the "Tax Fairness Plan", the federal tax rate applicable to non-portfolio income includes an amount intended to be charged in lieu of provincial tax. However, provincial tax may also apply to such non-portfolio earnings unless the applicable provincial tax legislation is amended to conform with the "Tax Fairness Plan".
Investment Eligibility; Mutual Fund Trust Status
If the Trust ceases to qualify as a mutual fund trust, our Trust units may cease to be qualified investments for Exempt Plans (as such term is defined in the Canadian Income Tax Act). Where at the end of any month an Exempt Plan holds Trust units that are not qualified investments, the Exempt Plan must, in respect of that month, pay a tax under Part Xl. 1 of the Tax Act equal to 1% of the fair market value of the Trust units at the time such Trust units were acquired by the Exempt Plan. In addition, where a trust governed by a registered retirement savings plan or registered retirement income fund holds Trust units that are not qualified investments, the Trust will become taxable on its income attributable to the Trust units while they are not qualified investments, including the full amount of any capital gain realized on a disposition of Trust units while they are not qualified investments. Where a trust governed by a registered education savings plan holds Trust units that are not qualified investments, the plan's registration may be revoked.
In addition, if the Trust were to cease to qualify as a mutual fund trust, Trust units may become foreign property for Exempt Plans and registered pension plans. Trust units held by Unitholders that are not residents of Canada would become taxable Canadian property. These non-resident holders would be subject to Canadian income tax on any gains realized on a disposition of Trust units held by them, subject to the application of any exemption under an income tax convention.
Redemption of Trust Units
It is anticipated that the redemption right associated with Trust units will not be the primary mechanism for holders of Trust units to dispose of their Trust units. The unsecured, subordinated notes issued from time to time by Builders Holding Trust to the Trust ("BHT Notes"), which may be distributed in specie to Unitholders in connection with redemptions, will not be listed on any stock exchange and no market is expected to develop in such BHT Notes. BHT Notes will not be qualified investments for trusts governed by Exempt Plans.
Nature of Trust Units
The Trust units do not represent a traditional investment in the oilfield services sector and should not be viewed by investors as shares in a corporation or as a direct investment in a corporation's business or assets. The Trust units represent a fractional interest in the Trust. As holders of Trust units, Unitholders do not have the statutory rights normally associated with ownership of shares of a corporation including, for example, the right to bring "oppression" or "derivative" actions.
The Trust's primary assets are the trust units of Builders Holding Trust and the BHT Notes. The price per Trust unit is a function of the anticipated distributable cash, the underlying assets of the Trust and its ability to effect long-term growth in the value of the Trust. The market price of Trust units will be sensitive to a variety of market conditions including, but not limited to, interest rates, commodity prices and the ability of the Trust to acquire additional assets. Changes in market conditions may adversely affect the trading price of Trust units.
The Trust units are not "deposits" within the meaning of the Canadian Deposit Insurance Corporation Act (Canada) and are not insured under the provisions of that Act or any