Horn River
Oil Sands
Montney
HEAVy OIL Cardium CALGARY Bakken
powder river Marcellus dj TULSA Woodford
fayetteville
Barnett Haynesville Eagle ford
THE MAIN PERFORMANCE Flint is delivering many critical services through its key customer relationships in every major unconventional oil and natural gas resource play in North America. Flint’s customers have been pushing aggressively into new shale gas and oil resource plays like the Marcellus and Bakken – to name just two of more than a dozen across North America. Last year, Flint responded quickly by setting up three new operating locations in West Virginia, Pennsylvania and North Dakota. We also acquired rig-moving assets in the southern United States to expand our services into the active shale gas plays in Texas and Louisiana.
2 010
A nnual
R epo rt
1
Strategically Positioned Flint’s operating locations are strategically layered overtop of North America’s major energy plays. In addition to this strong permanent presence, Flint can rapidly deploy its services producers are working. Flint
Encore Performance
established eight new locations
By consistently providing the
in the U.S. in 2010 to offer
highest safety excellence,
upstream and midstream
coupled with cost-efficient
Flint not only looks for ways to
services in emerging shale
execution and backed by
reduce its costs and capitalize
gas plays.
exceptional people, Flint gets
on operational synergies, it
the job done. Customers count
explores ways its customers can
on Flint to help them succeed,
realize further cost savings. A
and many of our largest
great example is Flint’s wear
customers have worked with
technologies, a patented internal
us for more than ten years.
protective coating that extends
anywhere oil and natural gas
Diversified, Integrated services
a component’s lifespan and is
Flint’s business strategy is about partnering with its customers for the long term. Flint offers full-cycle services to the energy sector, from transporting the rigs, through installing equipment, to future maintenance – every stage in its customers’ operations.
Innovative
Financially Strong
environmentally benign. That’s truly a win-win outcome.
Flint showcased its strong balance sheet at year-end 2010 with $164 million in cash, substantial undrawn credit lines and $229 million in long-term debt leveraging almost $1 billion in assets. Flint’s operations generated $93 million(1) in cash flow during the year.
(1)
ash flow from operations C before changes in non-cash working capital.
2 010
A nnual
R epo rt
3
Key Drivers of unconventional energy development Easy-To-Develop Resources are Tapped out
High crude Oil prices Make unconventional sources economicAL
Market Demand FOR OIL AND GAS
Technology enables access TO tough reservoirs
Conventional natural gas
In today’s oil price
World crude oil demand is
We have seen a paradigm
pools are generally in long-
environment, capital-intensive
increasing, keeping prices at
shift in drilling technology in
term decline. The stunning
unconventional sources such as
levels supporting development
the last five years. Not so long
commercial success of
Western Canada’s heavy oil and
of unconventional sources.
ago North American natural
horizontal drilling
oil sands resources are economic
While abundant natural gas
gas reserves were considered
combined with multi-stage
to develop, exploration risk is
production in North America
strictly finite and in irreversible
hydraulic fracturing has
low, and ample reserves make
is keeping natural gas prices
decline. The new extraction
shifted additional capital
long-term investments in these
low, a significant proportion of
technologies applied to current
investment by producers to
resources secure.
unconventional gas continues
unconventional reservoirs have
to provide satisfactory investment
added over 20 years’ supply
returns for producers.
at current rates of consumption
unconventional shale and
The horizontal drilling and
tight gas development.
multi-stage fracturing
across North America.
technologies developed for unconventional gas have been successfully transferred to tighter sands and shale oil reservoirs in the Bakken, Cardium, Lower Shaunavon and Viking formations, as well as several additional emerging plays.
(Source: BMO Capital Markets, January 2011)
E c o n omi c s o f u n c o n ve n t io n al oil a n d N A TUR A L g as basi n s
90
P r i c e re q u i re d fo r 10 % p re - ta x I R R
7 6
Current average 2 010 c r u d e o i l p r i c e
5 Current average 2 010 n a t u r a l g a s p r i c e
70
4 3
50
2
30
1
Oil Sands
Bakken
Cardium
Marcellus
Powder River
Fayetteville
Haynesville
Eagle Ford
Montney
Horn River
Barnett
2 010
A nnual
Woodford
R eport
15
Natural gas price ($/mcf)
Crude oil price ($/boe)
110
An Unconventional Play in Multiple Acts Flint’s Role in the Alberta Oil Sands
2008
Opti Nexen Long Lake SAGD, Gasifier, Utilities and Offsite Suncor Oil Sands Utilities and Offsite
FT Services awarded two year contract for turnaround management and execution services at Shell Canada’s Scotford Complex at Fort Saskatchewan, Alberta Award Shell Vice President Safety Award (Albian Sands Project)
Suncor Firebag 3
Suncor Firebag 4
Suncor Firebag Sulphur Recovery Unit
Suncor Firebag 3
Shell Albian Sands Froth Treatment and Tank Farm
FT Services Suncor maintenance contract renewed at upgrading operations, Firebag SAGD operations and Sarnia refinery over 5 years
Awarded maintenance contract on Canadian Natural Resources Limited Horizon Bitumen Project
Suncor Firebag 2 Suncor Oil Sands Millennium Vacuum Unit
Awarded electrical and instrumentation services and portion of mechanical services at Nexen Inc. Long Lake over 3 years
Awards Suncor President’s Operational Excellence Award (Firebag Project) Oil Sands Review Supplier of the Year Award
2007
2003
Suncor Oil Sands Facilities
FT Services awarded asset management services contract at Suncor’s Fort McMurray oil sands operations, Firebag SAGD and Sarnia refinery
2005
2001
Awards Suncor Safety Leadership Flag Award (Firebag Project)
Suncor Firebag Expansion
Suncor Firebag Co-gen, Oil Sands Sulphur and Suncor Oil Sands South Booster Pumphouse
Petro-Canada McKay River SAGD
Suncor Firebag 3
2010
Suncor Firebag 1
2006
2002
2009
2004
Statoil Canada Leismer Central Processing Facility and Wellpads
Suncor Safety Leadership Flag Awards (Firebag Project)
2 010
A nnual
R eport
17
Management’s Discussion and Analysis For the year ended December 31, 2010 (in millions of Canadian dollars except share data and per share amounts, unless otherwise stated)
This Management’s Discussion and Analysis (MD&A) for Flint Energy Services Ltd. (“Flint” or the “Company”) should be read in conjunction with the Company’s audited consolidated financial statements for the year ended December 31, 2010 and accompanying notes. The consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles (GAAP) and are reported in Canadian dollars. Flint Energy Services Ltd. is a market leader providing an expanding range of integrated products and services for the energy industry including: production services, infrastructure construction, oilfield transportation, and maintenance services. Flint has four reportable business segments: Production Services, Facility Infrastructure, Maintenance Services and Oilfield Services. Flint provides this unique breadth of products and services through over 60 strategic locations in the oil and natural gas producing areas of North America, from Inuvik in the Northwest Territories to Mission, Texas. Flint is a preferred provider of infrastructure construction management, module fabrication, and maintenance services for upgrading and production facilities in Alberta’s oil sands sector. The Company’s common stock is traded on the Toronto Stock Exchange under the symbol “FES”.
Advisory Regarding Forward Looking Statements This report dated as at March 15, 2011 contains forward-looking statements under the heading “Outlook” and elsewhere concerning future events or the Company’s future performance, including the Company’s projected operating results for 2011 and beyond, and anticipated capital expenditure trends and drilling activity in the oil and natural gas industry. Forward-looking statements are often, but not always, identified by the use of words such as “seek”, “anticipate”, “plan”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “predict”, “potential”, “targeting”, “intend”, “could”, “might”, “should”, “believe” and similar expressions. Actual events or results may differ materially from those reflected in the Company’s forward-looking statements due to a number of known and unknown risks, uncertainties and other factors affecting the Company’s business and the oil and natural gas industry generally. These factors include, but are not limited to, fluctuations in oil and natural gas prices, fluctuations in the level of oil and natural gas industry capital expenditures and expenditures on production and remedial work and other factors that affect demand for the Company’s services, industry competition, the need to effectively integrate acquired businesses, uncertainties as to the Company’s ability to implement its business strategy effectively in Canada and the United States, political and economic conditions, the Company’s ability to attract and retain key personnel, and other risks and uncertainties described under “Risk Factors” and elsewhere in the Company’s Annual Information Form for the year ended December 31, 2010 and other documents filed with Canadian provincial securities authorities and that are available to the public at www.sedar.com. The Company believes that the expectations reflected in these forward-looking statements are reasonable, but no assurance can be given that these expectations will prove to be correct and such forward-looking statements included in this report should not be unduly relied upon. These statements speak only as of the date of this report. The Company does not undertake to update any forward-looking statements, whether written or oral, that may be made from time to time by the Company or on the Company’s behalf, except as may be required under applicable securities laws. The forward-looking statements contained in this report are expressly qualified by this statement.
Description of Non-GAAP Measures Throughout this MD&A, management uses terms and ratios not found in the Handbook of the Canadian Institute of Chartered Accountants (CICA), which do not have a standardized meaning under Canadian GAAP; therefore the following definitions are provided: “EBITDA” is equal to earnings before interest, taxes, depreciation, amortization, impairment of intangible assets and goodwill, and share-based compensation. The Company presents EBITDA as a supplemental earnings measure as it is used by the chief operating decision makers of the Company to measure reportable segment profitability. Management uses EBITDA to establish performance benchmarks for incentive compensation for employees and to evaluate the performance of its reportable segments. 24
Flint
E n e r g y
S e r v i c es
L t d.
MANAGEMENT’S DISCUSSION AND ANALYSIS
For the year ended December 31, 2010 (in millions of Canadian dollars except share data and per share amounts, unless otherwise stated)
“Adjusted net earnings” is equal to net earnings (loss) excluding after-tax impairment charges related to goodwill, intangible assets, and property, plant and equipment. The Company uses adjusted net earnings as a measure of profitability excluding extraordinary items to evaluate the Company’s performance. Adjusted net earnings per share is equal to net earnings (loss) per share excluding impairment charges. “Gross margin” is calculated by subtracting direct costs from revenue. The Company believes gross margin is a measure of project profitability and is commonly used to evaluate the Company’s performance. “Gross margin percentage” is calculated by taking gross margin and dividing by revenue, expressing the result as a percentage. “Days Sales Outstanding” (DSO) is calculated by taking the accounts receivable, revenue in excess of billings, and inventories, and subtracting billings in excess of revenue for the period. The result is then converted into days using the revenue count-back method. Management uses DSO to evaluate the effectiveness of billing and collection of revenues. “Funds provided by operations before changes in non-cash working capital” is equal to net earnings adjusting for items not affecting cash. The Company presents funds provided by operations before changes in non-cash working capital to measure funds generated from operations. “Cash flow to interest-bearing debt” is a ratio that is equal to cash flow divided by interest-bearing debt at year-end, expressed as a percentage. Cash flow is equal to funds provided by operations before changes in non-cash working capital. Interest-bearing debt is equal to the sum of current and long-term debt. “Debt to total capitalization” is a ratio equal to debt divided by total capitalization, expressed as a percentage. Debt is equal to long-term debt at year-end, including the current portion. Total capitalization is equal to current and long-term debt plus shareholders’ equity. These non-GAAP financial measures and ratios may not be comparable to similar measures and statistics presented by other issuers. The ratios are presented because they are commonly referred to by lenders and other interested parties in evaluating the Company’s financial position. Certain comparative figures have been reclassified to conform to current-period presentation.
Highlights of the Year For the year ended December 31, 2010, revenues were $1,781.3 million, down from $1,876.5 million in 2009, representing a decrease of $95.2 million or 5.1%. While the Company’s maintenance businesses are relatively stable, a significant portion of the Company’s field services business is more directly tied to completions and tie in work which lags the drilling cycle and has not yet benefited fully from additional activity. In addition, the Facility Infrastructure bidding process involves substantial lead times in winning contracts. While revenue is down in this segment year over year the Company avoided taking on higher risk contracts during a period of low activity for the industry. EBITDA for the year ended December 31, 2010 was $131.3 million, down $17.9 million or 12.0% from $149.2 million in 2009. The decrease in EBITDA resulted from i) an overall decrease in revenues from 2009, ii) increased competition in the Oilfield Services segment creating downward pressure on prices in 2010, and iii) the Maintenance Services segment, which has primarily lower margins due to a lower risk profile, forming a larger percentage of total revenue compared to 2009. Diluted EPS for the year was $0.72 compared to $1.00 in the prior year.
2 0 1 0
A n n ua l
Rep o r t
25
MANAGEMENT’S DISCUSSION AND ANALYSIS
For the year ended December 31, 2010 (in millions of Canadian dollars except share data and per share amounts, unless otherwise stated)
Cash balances remained steady, $163.6 million as at December 31, 2010, compared to $163.9 million at the end of 2009. Accounts receivable increased by $13.9 million and revenue in excess of billings decreased by $5.9 million, representing a collective increase of $8.0 million or 2.6% from the prior year. DSO increased by 14 days to 83 days as at December 31, 2010 from 69 days last year. As a result of sufficient cash flow from operations, the Company did not have to draw on its short-term borrowing facilities.
Recent Events Module Fabrication Contract On November 2, 2010, the Company announced that it was awarded a contract to fabricate production modules for Suncor Energy’s Firebag steam-assisted gravity drainage (SAGD) bitumen extraction projects near Fort McMurray, Alberta. Work on the fixed-price contract valued at $18.5 million will continue into the second quarter of 2011, employing up to 200 workers at Flint’s fabrication facilities in Sherwood Park, Alberta. Extension of Suncor Maintenance Agreement On November 15, 2010, the Company reported its subsidiary company, Flint Transfield Services Limited (FT Services), negotiated an extension to its Suncor Energy Inc. maintenance agreement which will run until 2016. The maintenance agreement, which has been in place since 2007, is a five-year rolling, performance-based relationship that delivers base maintenance services to Suncor Energy’s upgrading operations in Fort McMurray, Alberta, the Firebag SAGD operations north of Fort McMurray, Alberta, and the Sarnia refinery in Ontario. The maintenance agreement covers asset management services and other service agreements (turnarounds, sustaining project construction and general contractor) which have a potential value in excess of $2.2 billion ($450 million per year) over the five-year period. Expansion of Oilfield Hauling Services in the United States On November 22, 2010, the Company announced a US$36 million asset acquisition of Stallion Heavy Haulers (“Stallion”), including property and equipment in five locations in the United States: three in East Texas, one in Louisiana and one in Oklahoma. This acquisition furthers the expansion of Flint’s operations into the busy shale gas fields in the United States. Flint began with fluid hauling services in Vernal, Utah, and recently expanded into the Marcellus shale gas basin, moving underutilized equipment from western Canada to its new Williamsport, Pennsylvania location. With the addition of the five new locations, approximately 170 new employees and 450 pieces of equipment, Flint became one of the largest oilfield haulers in the U.S. shale basins. In addition, this new acquisition will provide equipment, personnel, and management for a new location that Flint is constructing in Williston, North Dakota, to provide oilfield hauling services in the active Bakken shale oil play in North Dakota. This brings the total to eight locations for Flint’s U.S. Oilfield Services business segment.
26
Flint
E n e r g y
S e r v i c es
L t d.
MANAGEMENT’S DISCUSSION AND ANALYSIS
For the year ended December 31, 2010 (in millions of Canadian dollars except share data and per share amounts, unless otherwise stated)
Consolidated Annual Financial Results The following table summarizes key financial data to be read in conjunction with the audited financial statements of the Company as at and for the year ended December 31, 2010.
2010-2009
2010 2009 2008
Increase (Decrease)
% Change
$ 1,781.3
$ 1,876.5
(95.2)
(5.1%)
1,504.7
1,578.4
1,949.2
(73.7)
(4.7%)
276.6
298.1
365.4
(21.5)
(7.2%)
General and administrative expenses
148.3
151.6
166.2
(3.3)
(2.2%)
58.3
57.8
66.5
0.5
0.9%
8.5
4.9
4.6
3.6
73.5%
Interest expense, net of interest income
12.0
17.0
19.9
(5.0)
(29.4%)
Gain on disposal of property, plant, and equipment
(0.4)
(1.4)
(0.8)
1.0
(71.4%)
Revenue Direct costs
Amortization Share based compensation expense
$ 2,314.6
Gain on business combination
(1.1)
–
–
(1.1)
–
Adjusted earnings before income taxes
51.0
68.2
109.0
(17.2)
(25.2%)
Income taxes, current and future
17.9
22.5
34.3
(4.6)
(20.7%)
Adjusted net earnings per common share – basic
$
33.0 0.72
45.8 1.00
$
74.7 1.57
$
(12.7) (27.7%) (0.28) (28.0%)
per common share – diluted
$ 0.72
$ 1.00
$
1.57
$
(0.27) (27.5%)
–
–
Impairment charge
$
442.5 (26.4)
$
(341.4) $ (7.20)
$
(12.7) (27.7%) (0.28) –
$
0.72
$
0.99
$
$
(0.27)
131.3
EBITDA
149.2
Reconciliation of EBITDA
Earnings (loss) before income taxes Amortization of property, plant, and equipment and intangible assets
EBITDA
–
– 45.7 1.00
per common share – diluted
Interest expense, net of interest income
–
– $
Share based compensation expense
–
33.0 0.72
Future income taxes related to impairment Net earnings (loss) per common share – basic
Impairment charge
–
$
(7.20)
–
201.7
(17.9) (12.0%)
2010
2009
51.0
$
68.3
2008
$ (333.5)
59.8
59.1
68.2
–
–
442.5
8.5
4.9
4.6
12.0
16.9
19.9
$ 131.3
$ 149.2
$ 201.7
2 0 1 0
A n n ua l
Rep o r t
27
MANAGEMENT’S DISCUSSION AND ANALYSIS
For the year ended December 31, 2010 (in millions of Canadian dollars except share data and per share amounts, unless otherwise stated)
Revenue 2010
(in thousands of Canadian dollars)
2009
Increase (Decrease)
Revenue by reportable segment Production Services $ 783,940 44% $ 795,344 42% $ (11,404)
% Change
(1.4%)
Facility Infrastructure
354,894
20%
595,714
32%
Oilfield Services
220,831
12%
206,671
11%
14,160
6.9%
Maintenance Services
421,675
24%
278,807
15%
142,868
51.2%
$ 1,876,536 100%
$ (95,196)
(5.1%)
$ 1,781,340 100%
Total
(240,820)
EBITDA by reportable segment Production Services $ 58,394 44% $ 45,620 31% $ 12,774
(40.4%)
28.0%
Facility Infrastructure
38,928
30%
70,619
47%
(31,691)
Oilfield Services
15,315
12%
16,477
11%
(1,162)
(7.1%)
Maintenance Services
18,710
14%
16,512
11%
2,198
13.3%
$ 149,228 100%
$ (17,881)
(12.0%)
$
Total
131,347 100%
(44.9%)
The Production Services segment’s revenues decreased by $11.4 million or 1.4% from $795.3 million in 2009 to $783.9 million in 2010. In Canada, revenues decreased to $491.7 million from $494.2 million in 2009, a decrease of $2.4 million or 0.5%. Although overall drilling activity increased in 2010, the proportion of natural gas wells declined, shifting the mix toward oil wells, which are less capital intensive relative to the Company’s service offering. In addition, a significant portion of the Company’s field services business is more directly tied to completions and tie in work which lags the drilling cycle and has not yet benefited fully from additional activity. In the United States, revenues decreased to $292.2 million from $301.2 million in 2009, a year-over-year reduction of $9.0 million or 3.0%. This decrease is due to foreign exchange differences, as U.S. revenues increased by 7.4% when measured in U.S. dollars. The unfavourable impact of foreign exchange on revenue was approximately $27.4 million or 10.7%. In the Facility Infrastructure segment, revenues decreased by $240.8 million or 40.4% to $354.9 million in 2010 from $595.7 million in 2009. The decrease in revenue was primarily due to the completion of work on the Shell Albian and Statoil Canada projects earlier in the year, and fewer projects being undertaken than in 2009. The Facility Infrastructure segment is focused on major facility project development services for large oil sands producers in the Fort McMurray region of Alberta and, therefore, is dependent on the expenditures of oil sands producers, which are primarily driven by the current and anticipated prices of oil and natural gas. Uncertainty relating to oil prices in 2008 and 2009 caused reductions and delays in capital expenditures in those years, which affected the Company in 2010 due to the fact that the Company’s business lags behind the industry’s capital investment decision-making cycle. The Oilfield Services segment’s revenues increased by $14.2 million or 6.9%, from $206.7 million in 2009 to $220.8 million in 2010. The Oilfield Services segment derives the majority of its revenues from transportation of drill rigs and fluid haul services throughout western Canada and is directly influenced by the level of capital spending by the Company’s customers. Increased rig counts and expansion into the U.S. drove the increase in revenue, despite depressed pricing caused by increased competition in the market. Revenues increased by $142.9 million or 51.2% to $421.7 million in 2010 from $278.8 million in 2009 in the Maintenance Services segment as a result of higher year-over-year volumes from FT Services for work performed under maintenance agreements for Suncor Energy Inc., Nexen Inc. and Canadian Natural Resources Limited.
28
Flint
E n e r g y
S e r v i c es
L t d.
MANAGEMENT’S DISCUSSION AND ANALYSIS
For the year ended December 31, 2010 (in millions of Canadian dollars except share data and per share amounts, unless otherwise stated)
Direct Costs and Gross Margin Direct costs for the year ended December 31, 2010 were $1,504.7 million compared to $1,578.4 million in 2009. Gross margin and gross margin percentage for the year ended December 31, 2010 were $276.6 million and 15.5%, respectively, representing a decrease of $21.5 million from $298.1 and 15.9%, respectively, in the prior year. The decreases in direct costs and gross margin are directly attributable to the decreases in revenues and overall activity level previously discussed. The increased gross margin percentage in the Production Services segment partially offset decreased margins in the Facility Infrastructure and Oilfield Services segments. The following table summarizes gross margin and percentage by reportable segment: (in thousands of Canadian dollars)
Gross 2010 Margin %
2009
Gross Margin %
Change in %
$ 141,944
18.1%
$ 130,886
16.5%
1.6%
– Canada
89,754
18.3%
87,079
17.6%
0.7%
– United States
52,190
17.9%
43,807
14.5%
3.4%
Facility Infrastructure
55,685
15.7%
94,154
15.8%
(0.1%)
Oilfield Services
38,816
17.6%
38,587
18.7%
(1.1%)
Production Services
Maintenance Services Total
41,748
9.9%
35,733
12.8%
(2.9%)
$ 278,193
15.5%
$ 299,360
15.9%
(0.4%)
The gross margin percentage in the Facility Infrastructure segment was 15.7% in 2010 compared to 15.8% for 2009, a decrease of 0.1%. The Production Services segment gross margin percentage of 18.1% in 2010 was an increase of 1.6% from 16.5% in 2009 as a result of improved margins in the tubular management business driven by an expanded product line and improved cost controls. Gross margin percentage in the Oilfield Services segment was 17.6% compared to 18.7% for 2009 as a result of an increasingly competitive environment causing margins to decline in the Fluid Hauling business, despite increased revenues. The gross margin percentage for the Maintenance Services segment decreased to 9.9% in 2010 from 12.8% in 2009 due to a decrease in earned performance incentives. General and Administrative Expenses General and administrative expenses for the year ended December 31, 2010 were $148.3 million compared to $151.6 million in 2009, representing a decrease of $3.3 million or 2.1% due to reductions in staffing levels and related occupancy costs. As a percentage of revenue, general and administrative expenses increased year-over-year to 8.3% from 8.1% due to lower revenue. In 2010, $9.8 million of general and administrative expenses were reclassified from cost of goods sold in the FT Services joint venture, which is included in the maintenance services segment, with a corresponding $9.9 million being reclassified in 2009. These costs, which were previously reimbursable, are now classified as general and administrative as they are no longer being reimbursed by the clients of FT Services. This adjustment was recorded in the fourth quarter.
2 0 1 0
A n n ua l
Rep o r t
29
MANAGEMENT’S DISCUSSION AND ANALYSIS
For the year ended December 31, 2010 (in millions of Canadian dollars except share data and per share amounts, unless otherwise stated)
EBITDA The following table summarizes EBITDA by reportable segment and geographic location: 2010 EBITDA %
(in thousands of Canadian dollars)
2009
EBITDA %
Change in %
$ 58,394
7.4%
$ 45,620
5.7%
1.7%
– Canada
37,928
7.7%
33,401
6.8%
0.9%
– United States
Production Services
20,466
7.0%
12,219
4.1%
2.9%
Facility Infrastructure
38,928
11.0%
70,619
11.9%
(0.9%)
Oilfield Services
15,315
6.9%
16,477
8.0%
(1.1%)
Maintenance Services
18,710
4.4%
16,512
5.9%
(1.5%)
$ 131,347
7.4%
$ 149,228
7.9%
(0.5%)
Total
Overall, EBITDA margins declined by 0.5% from 7.9% in 2009 to 7.4% in 2010. The decrease was the result of lower proportion of EBITDA generated by the Facility Infrastructure segment, offset partially by increased EBITDA margins in the Production Services segment. The Facility Infrastructure and Oilfield Services segments were directly impacted by reduced natural gas drilling activity levels and delays and reductions in capital spending by producers in Canada and the United States in 2008/2009 which affect the Company’s business in 2010. Amortization Amortization of property, plant and equipment and intangible assets for the year ended December 31, 2010 increased by $0.5 million or 0.9% to $58.3 million from $57.8 million in 2009. Amortization expense on property, plant and equipment was down by $1.4 million from the prior year as a result of optimizing fleet levels. Amortization expense of intangible assets for 2010 was $2.0 million, an increase of $1.9 million from 2009. Share-Based Compensation Expense Share-based compensation expense increased by $3.6 million or 73.5% year-over-year to $8.5 million in 2010 from $4.9 million in the prior year. The increase was due to the increase in the market value of the Company’s shares over the prior year, affecting the values of the Deferred Share Unit Plan, Restricted Share Unit Plan and the Performance Share Unit Plan. These plans are valued using the intrinsic method, which is driven by the market value of the Company’s common shares. Interest Expense Net interest expense decreased by $5.0 million or 29.0% to $12.0 million for the fiscal year ending December 31, 2010 from $17.0 million in the prior year, as a result of reductions in the average long-term debt balance during the year. Income Taxes Income tax expense for the year ended December 31, 2010 was $17.9 million compared to $22.5 million in 2009. The tax rate was 35.2% of earnings before taxes, which is an increase of 2.3% from the prior year’s rate of 32.9%. The increased tax rate is due to a change in estimate of the timing of the reversal of temporary differences. In addition, income tax expense as a percentage of earnings before taxes differs from the statutory rate primarily due to the impact of changes in enacted tax rates, the benefit from changes in the timing of the reversal of temporary differences, and permanent differences.
30
Flint
E n e r g y
S e r v i c es
L t d.
MANAGEMENT’S DISCUSSION AND ANALYSIS
For the year ended December 31, 2010 (in millions of Canadian dollars except share data and per share amounts, unless otherwise stated)
Net Earnings The Company realized net earnings of $33.0 million ($0.72 per common share – diluted) during the year ended December 31, 2010 compared to $45.8 million ($1.00 per common share – diluted) in 2009, for a net decrease of $12.7 million.
Consolidated Financial Position The following table summarizes key consolidated financial position data:
2010-2009
2010 2009 2008
$ 568.1
Current assets
$ 546.9
$ 633.5
Increase (Decrease)
$
% Change
21.2
3.9%
Current liabilities
325.6
192.4
319.7
133.2
69.2%
Net working capital
242.5
354.5
313.8
(112.0)
(31.6%)
Long-term debt
229.3
239.1
310.5
(9.8)
(4.1%)
Current
136.9
16.7
60.3
120.2
719.8%
92.4
222.4
250.2
(130.0)
(58.5%)
983.6
961.5
1,088.9
22.1
2.3%
Non-current Total assets Total liabilities
440.2
449.7
606.7
(9.5)
(2.1%)
Total equity
543.4
511.8
482.2
31.6
6.2%
14
20.3%
Days sales outstanding (DSO)
83
69
79
As at December 31, 2010, the Company’s net working capital was $242.5 million compared to $354.5 million at December 31, 2009, a year-over-year reduction of $112.0 million or 31.6%. The reduction was primarily attributed to the change in the current portion of long-term debt, which increased by $120.2 million over the prior year due to the maturing of term loans which will become payable in 2011. The Company is considering various refinancing options, including use of cash available on hand, to pay down the debt. Revenue in excess of billings at December 31, 2010 was $57.0 million, a decrease of $5.9 million or 9.4% from $62.9 million at the end of 2009. Accounts receivable increased by $13.9 million or 5.7% to $258.2 million at year-end 2010 from $244.3 million at the end of 2009. However, the aging of accounts receivable as at December 31, 2010 showed improvement, with 10.1% of trade receivables outstanding greater than 60 days, down from 12.3% at the end of fiscal 2009. The Company anticipates continued improvements in the billing and collection processes and continues to monitor credit very closely. DSO for the year ended December 31, 2010 was 83 days compared to 69 days at the end of December 31, 2009. DSO fluctuated throughout the year due to the timing of client milestone billings and pre-payments from clients, but overall there was an increase because the proportion of accounts receivable attributable to the Facility Infrastructure segment, which has very low average DSO, declined from the previous year as the revenues decreased. Long-term debt, including operating facilities, was $229.3 million at December 31, 2010, representing a decrease of $9.8 or 4.1% from the prior year due to repayments.
2 0 1 0
A n n ua l
Rep o r t
31
MANAGEMENT’S DISCUSSION AND ANALYSIS
For the year ended December 31, 2010 (in millions of Canadian dollars except share data and per share amounts, unless otherwise stated)
Assets Consolidated total assets increased by $22.1 million or 2.3% to $983.6 million at December 31, 2010 from $961.5 million at December 31, 2009. The increase in total assets was due primarily to the increase in property, plant and equipment, accounts receivable, and future tax assets. Cash decreased by $0.3 million to $163.6 million at December 31, 2010 from $163.9 million at the end of 2009. Revenue in excess of billings decreased by $5.9 million and accounts receivable increased by $13.9 million from year-end 2009. Inventory levels remained relatively flat, increasing by $0.1 million or 0.2% to $51.2 million at December 31, 2010 from $51.1 million at the end of the prior year. Property, plant and equipment increased by $7.8 million or 2.0% to $389.7 million at December 31, 2010 from $381.9 million at the end of the prior year. Capital asset purchases during 2010 increased to $40.6 million from $28.1 million, offset by amortization of $57.9 million during the year. Intangible assets increased by $2.5 million from year-end 2009 due to expenditures relating to the JD Edwards implementation project, and the acquisitions of PES Surface Inc. (PSI) and Stallion Heavy Haulers (Stallion) as discussed in note 3 to the December 31, 2010 consolidated financial statements, as well as software purchases throughout the year that met the criteria for capitalization. Liabilities Consolidated total liabilities decreased by $9.5 million to $440.2 million at December 31, 2010 from $449.7 million at December 31, 2009 as a result of a decrease in future income tax liability. Long-term debt, including the current portion, decreased by $9.8 million or 4.1% to $229.3 million at December 31, 2010 from $239.1 million at the end of 2009, due to repayments. The Company provided a first charge over all assets under a General Security Agreement as security for the revolving operating loans and the term loans. Also the Company provided a general assignment of book debts and a first charge over all real property assets, pledged all shares of its subsidiaries, and made an assignment of insurance for security. The credit facilities require the Company to meet certain covenants. The Company was in compliance with these covenants at December 31, 2010 and 2009. Equity Consolidated total equity increased by $31.6 million to $543.4 at December 31, 2010 from $511.8 at December 31, 2009 due to net earnings in 2010 of $33.1 million.
32
Flint
E n e r g y
S e r v i c es
L t d.
MANAGEMENT’S DISCUSSION AND ANALYSIS
For the year ended December 31, 2010 (in millions of Canadian dollars except share data and per share amounts, unless otherwise stated)
Annual Results of Operations Selected financial information for each reportable business segment is as follows: 2010
(in thousands of Canadian dollars)
Revenue by reportable segment Production Services
$
2009
783,940 44%
Increase (Decrease)
% Change
$ 795,344 42% $ (11,404)
(1.4%)
Facility Infrastructure
354,894
20%
595,714
32%
Oilfield Services
220,831
12%
206,671
11%
14,160
6.9%
Maintenance Services
421,675
24%
278,807
15%
142,868
51.2%
$ 1,876,536 100%
$ (95,196)
(5.1%)
45,620 31% $ 12,774
28.0%
Total
$ 1,781,340 100%
EBITDA by reportable segment Production Services
$
58,394 44%
$
(240,820)
(40.4%)
Facility Infrastructure
38,928
30%
70,619
47%
(31,691)
(44.9%)
Oilfield Services
15,315
12%
16,477
11%
(1,162)
(7.1%)
18,710
14%
16,512
11%
2,198
13.3%
$ 149,228 100%
$ (17,881)
(12.0%)
Maintenance Services Total
$
131,347 100%
Production Services The Production Services segment provides pipeline work, day-to-day field facility installation and maintenance services, as well as electrical, instrumentation, mechanical, safety, plant shutdown and turnaround services, and tubular management and manufacturing. Selected financial information for each geographic location in this segment is as follows: 2010
2009
Revenue by geographic location
Canada
$ 491,744
$ 494,160
292,196
301,184
$ 783,940
$ 795,344
(in thousands of Canadian dollars)
United States Total
Increase (Decrease)
$
% Change
(2,416)
(0.5%)
(8,988)
(3.0%)
$ (11,404)
(1.4%)
$
4,527
13.6%
8,247
67.5%
$ 12,774
28.0%
EBITDA by geographic location Canada United States Total
$ 37,928
$ 33,401
20,466
12,219
$ 58,394
$ 45,620
2 0 1 0
A n n ua l
Rep o r t
33
MANAGEMENT’S DISCUSSION AND ANALYSIS
For the year ended December 31, 2010 (in millions of Canadian dollars except share data and per share amounts, unless otherwise stated)
Revenue Revenue from the Production Services segment for the year ended December 31, 2010 decreased by 1.4% to $783.9 million from $795.3 million in 2009. In Canada, revenues decreased to $491.7 million from $494.2 million in 2009, a decrease of $2.4 million or 0.5%. In the United States, revenues decreased to $292.2 million in 2010 from $301.2 million in 2009, a year-over-year reduction of $9.0 million or 3.0%. Lower natural gas drilling activity throughout 2010, in Canada and the United States, reduced demand for field production and created increased competition in the market. Revenue, measured in U.S. dollars, increased 5.9% year over year, but due to the effect of foreign exchange differences there was a decrease of 3.0% when measured in Canadian dollars. EBITDA Production Services’ EBITDA for the year ended December 31, 2010 increased by 28.0% to $58.4 million from $45.6 million in 2009. In Canada, EBITDA increased by $4.5 million or 13.6% to $37.9 million in 2010 from $33.4 million in the prior year as a result of improved margins and cost controls in the tubular management business. In the United States, EBITDA increased by $8.3 million or 67.5% to $20.5 million in 2010 from $12.2 million in the prior year. EBITDA as a percentage of revenue increased to 7.4% in 2010 from 5.7% in 2009 as a result of improved gross margins.
Facility Infrastructure The Facility Infrastructure segment provides major facility project construction services to the energy and natural resources sector, providing a full-cycle approach to all phases of project development from concept and design to fabrication and installation. Revenue Revenue from the Facility Infrastructure segment for the year ended December 31, 2010 decreased to $354.9 million from $595.7 million in 2009, a year-over-year decrease of $240.8 million or 40.4%. The decrease in revenue was primarily due to completion of work on the Shell Albian Sands and Statoil Canada projects earlier in the year, and fewer projects overall than in 2009. EBITDA Facility Infrastructure’s EBITDA for the year ended December 31, 2010 decreased by $31.7 million or 44.9% to $38.9 million in 2010 from $70.6 million in 2009. EBITDA as a percentage of revenue was 11.0% in 2010 compared to 11.9% in the prior year.
34
Flint
E n e r g y
S e r v i c es
L t d.
MANAGEMENT’S DISCUSSION AND ANALYSIS
For the year ended December 31, 2010 (in millions of Canadian dollars except share data and per share amounts, unless otherwise stated)
Oilfield Services The Oilfield Services segment includes activities focused on energy-related transportation and hauling such as drilling rig moving, pressure and vacuum services, fluid hauling, specialized hauling, service rig moving and light hauling. Revenue Revenue for the year ended December 31, 2010 increased by $14.1 million or 6.9% to $220.8 million from $206.7 million in 2009. Despite lower prices caused by increased competition there was increased volume due to increased activity and expansion into the U.S. market. EBITDA Oilfield Services’ EBITDA for the year ended December 31, 2010 decreased by $1.2 million or 7.1% to $15.3 million from $16.5 million in 2009. The decrease in EBITDA was a result of a more competitive environment than in the prior year, as well as one-time startup costs for operations in the U.S. EBITDA as a percentage of revenue was 6.9% in 2010, down from 8.0% in the prior year.
Maintenance Services The Maintenance Services segment provides asset management services for all routine plant maintenance, coordination of third-party services, sustaining capital projects, and turnaround services for oil sands production facilities in Alberta, oil refineries and related chemical, energy, electrical and processing plants. This work is performed through a 50% owned joint venture company, FT Services. Also included in this business segment is the proportional share of two other joint venture companies: Mackenzie Valley Construction, with a base of operations in Inuvik, Northwest Territories, and SRP North Ventures, with a base of operations in Norman Wells, Northwest Territories. These joint venture companies provide a variety of services including construction, maintenance and logistical services. Revenue Revenue for the year ended December 31, 2010 increased by $142.9 million or 51.2% to $421.7 million from $278.8 million in 2009. Maintenance revenues increased in 2010 as a result of a higher proportion of major turnarounds in 2010 than in 2009. EBITDA Maintenance Services’ EBITDA for the year ended December 31, 2010 increased by $2.2 million to $18.7 million from $16.5 million in 2009. EBITDA as a percentage of revenue was 4.4%, down from 5.9% in the prior year due to a lesser amount of earned performance incentives than in the prior year.
2 0 1 0
A n n ua l
Rep o r t
35
MANAGEMENT’S DISCUSSION AND ANALYSIS
For the year ended December 31, 2010 (in millions of Canadian dollars except share data and per share amounts, unless otherwise stated)
Consolidated Fourth Quarter Financial Results The following tables summarize key financial data for the three months ended December 31, 2010: 2010
(for the three months ended December 31)
$
Revenue
394.3
2009
(68.2)
(14.7%)
371.8
(44.2)
(11.9%)
66.7
90.7
(24.0)
(26.5%)
General and administrative expenses
44.7
48.3
(3.6)
(7.4%)
Amortization
16.0
14.5
1.5
10.3%
2.8
2.4
0.4
16.7%
Share based compensation expense
462.5
$
% Change
327.6
Direct costs
$
Increase (Decrease)
Interest expense, net of interest income
1.7
4.1
(2.4)
(58.5%)
Gain on sale of assets
(1.0)
(0.8)
(0.2)
25.0%
Gain on business combination
(1.1)
–
(1.1)
–
Earnings before income taxes
3.6
22.2
(18.6)
(83.8%)
Income taxes, current and future
2.7
8.4
(5.7)
(67.9%)
(12.9)
(93.5%)
0.9
Net earnings
13.8
per common share – basic
$
0.02
$
0.32
$
(0.30)
per common share – diluted
$
0.02
$
0.32
$
(0.30)
–
EBITDA
24.9
43.4
(18.5)
(42.7%)
–
During the three months ended December 31, 2010, the Company’s net earnings were $0.9 million compared to net earnings of $13.8 million in the comparative quarter of 2009, representing a decrease of $12.9 million as a result of decreased revenues. Diluted earnings per share for the fourth quarter of 2010 were $0.02, a decrease of $0.30 from the comparative period of 2009. Revenues for the three months ended December 31, 2010 were $394.3 million compared to $462.5 million in the prior year’s comparative quarter, representing a decrease of $68.2 million or 14.7%. The decrease in revenues for the fourth quarter of fiscal 2010 was the result of declining activities in the Facility Infrastructure segment from the prior year’s quarter. General and administrative expenses for the three months ended December 31, 2010 were $44.7 million compared to $48.3 million in the fourth quarter of 2009, a decrease of $3.6 million or 7.4% due to staff reductions and related occupancy costs. $9.8 million of general and administrative expense was reclassified from cost of goods sold for the FT Services joint venture, included in the maintenance services segment, with a corresponding $9.9 million being reclassified in 2009. These costs, which were previously reimbursable, are now classified as general and administrative as they are no longer being reimbursed by the clients of FT Services. Amortization of property, plant and equipment and intangible assets of $16.0 million in the fourth quarter of 2010 was $1.5 million or 10.3% higher than in the same period in 2009 due to the acquisition of assets to expand the oilfield services segment in the U.S. Interest expense was $1.7 million in the fourth quarter of 2010, representing a decrease of $2.4 million or 58.5% from $4.1 million in the fourth quarter of 2009. A reduction in the average long-term debt balance for the quarter resulted in this decline.
36
Flint
E n e r g y
S e r v i c es
L t d.
MANAGEMENT’S DISCUSSION AND ANALYSIS
For the year ended December 31, 2010 (in millions of Canadian dollars except share data and per share amounts, unless otherwise stated)
Selected financial information for each reportable business segment for the fourth quarter is as follows: 2010
(in thousands of Canadian dollars)
2009
Increase (Decrease)
% Change
Revenue by reportable segment Production Services $ 188,803 48% $ 169,399 37% $ 19,404
11.5%
Facility Infrastructure
40,626
10%
161,821
35%
(121,195)
(74.9%)
Oilfield Services
65,322
17%
55,979
12%
9,343
16.7%
99,595
25%
75,256
16%
24,339
32.3%
$ 462,455 100%
$ (68,109)
(14.7%)
Maintenance Services Total
$
394,346 100%
EBITDA by reportable segment Production Services $ 10,324 41% $ 11,054 25% $ (730) 1,235
Facility Infrastructure
5%
23,903
(6.6%)
55%
(22,668)
(94.8%)
Oilfield Services
7,595
30%
3,003
7%
4,592
152.9%
Maintenance Services
5,753
24%
5,470
13%
283
5.2%
43,430 100%
$ (18,523)
(42.7%)
Q1
Q3
Total
$
24,907 100%
$
Quarterly Information 2010
Revenue
Q4
Q3
2009 Q2
Q4
Q2
Q1
$ 394.3 $ 406.5 $ 459.2 $ 521.4 $ 462.5 $ 459.7 $ 424.2 $ 530.2 0.9
6.2
8.2
17.7
13.8
9.7
3.8
18.5
per common share – basic
0.02
0.14
0.18
0.39
0.32
0.21
0.08
0.40
per common share – diluted
0.02
0.14
0.18
0.38
0.32
0.21
0.08
0.40
Net earnings
A number of factors contribute to variations in the Company’s results from period to period. These include but are not limited to weather, customer capital spending, as well as drilling programs which are affected by oil and natural gas prices, and seasonal behaviours in customer spending caused by activities such as plant shutdown work. The Company continues to create the optimum portfolio of services to meet customer needs and maximize shareholder returns. Certain business lines within the Company relate to the maintenance and operation of oilfield facilities, which generally produce consistent revenues, while other business lines relate to large projects, potentially resulting in fluctuating revenue streams over time. While a significant amount of the business activity related to the maintenance and operation of oilfield facilities is under long-term contract, the work is still primarily call-out related and is provided on an as-needed basis and, therefore, may not generate a consistent revenue stream over periods. The Oilfield Services segment’s primary business drivers are related to the drilling cycle in the Western Canada Sedimentary Basin, while the specialized heavy haul operation, included as part of the Oilfield Services segment, will have more specific business drivers related to the movement of large pieces of equipment and module components of construction projects. As the Company has United States operations, its consolidated financial results may vary over periods due to the effect of foreign exchange fluctuations in translating the revenues and expenses of its United States operations to Canadian dollars. During the year ended December 31, 2010, 17.4% (2009 – 16.7%) of the Company’s business activity was in the United States.
2 0 1 0
A n n ua l
Rep o r t
37
MANAGEMENT’S DISCUSSION AND ANALYSIS
For the year ended December 31, 2010 (in millions of Canadian dollars except share data and per share amounts, unless otherwise stated)
Liquidity and Capital Resources At December 31, 2010, the Company had $163.6 million in cash and cash equivalents. The Company’s principal sources of capital are cash flows from operations and borrowings under its senior credit facility. The Company’s principal uses of cash are for the financing of working capital and capital expenditures. Selected cash flow and capitalization data is as follows: 2010
Funds provided by operations before changes in non-cash working capital
$
Cash provided by operating activities Cash flow to interest bearing debt (annualized)
Target > 16%
Long-term debt (including current portion) Debt to total capitalization
Target < 50%
97.9
2009
$
102.5
92.9
256.5
42.7%
42.9%
229.3
239.1
29.7%
31.8%
Cash Flow and Liquidity Cash provided by operating activities for the year ended December 31, 2010 was $92.9 million compared to $256.5 million for 2009. The decrease in cash provided by operating activities was the result of fluctuations in non-cash balances related to operations during the year. In 2009 management made a concerted effort to improve DSO from the prior year, causing accounts receivable and revenues in excess balances to decline significantly. The cash provided from operating activities was at more normal levels in 2010. Cash flows used in investing activities for the year ended December 31, 2010 increased to $76.3 million from $23.1 million in 2009. The increase of $53.2 million (230.3%) over the prior year was due to the acquisition of PES Surface Inc. and Stallion for $42.9 million and net capital expenditures of $26.6 million, compared to $15.8 million in 2009. Cash flows used in financing activities for the year ended December 31, 2010 were $15.2 million compared to $65.7 million used for 2009. The Company repaid $11.7 million of long-term debt in 2010 compared to $56.3 million repaid in 2009. In addition, there was no repurchase of common shares under the Company’s Normal Course Issuer Bid in the year, compared to $5.5 million for 2009. The Company uses the ratios of cash flow to interest bearing debt, and of debt to total capitalization as key indicators of leverage and to monitor the strength of its balance sheet. Cash flow to interest bearing debt decreased to 42.7% at year-end 2010 from 42.9% at the prior year-end, exceeding the Company’s target of greater than 16% for the year. Debt to total capitalization improved to 29.7% from 31.8% in the prior year, which was primarily the result of reductions in long-term debt from the prior year. This ratio was also well ahead of the target of less than 50%. The Company closely monitors its cash-generating ability and continues to focus efforts upon improving billing and collection processes, in addition to reducing long-term debt.
38
Flint
E n e r g y
S e r v i c es
L t d.
MANAGEMENT’S DISCUSSION AND ANALYSIS
For the year ended December 31, 2010 (in millions of Canadian dollars except share data and per share amounts, unless otherwise stated)
Capital Requirements and Capitalization At December 31, 2010 the Company had obligations to repay within one year $136.7 million (December 31, 2009 – $17.0 million) of long-term debt, which included $1.2 million (December 31, 2009 – $2.4 million) of capital lease payments for vehicles, office equipment, premises and construction equipment. In addition, the Company had operating lease obligations of $38.4 million as at December 31, 2010, down from $48.3 million at year-end 2009. The Company projects capital expenditures in 2011 to be similar to the levels in 2010. Capital expenditures are necessary to replace construction equipment, heavy trucks and vehicles as they near the end of their useful lives and when it becomes less economical to continue operating the units due to increasing maintenance costs. Although these capital expenditures may be necessary to achieve operating efficiencies, the Company has no obligation to incur them. Commitments and Contingencies The following table presents the Company’s future payment obligations: Maturity
Long-term debt
< 1 year
$
Operating leases Total contractual obligations
136.7
1 – 3 years
3 – 5 years
> 5 years
$
$
$
38.4 $
175.1
84.5 48.7
$
133.2
0.2 21.0
$
–
Total
$
6.5
21.2
$
6.5
221.4 114.6
$
336.0
On January 29, 2010, a customer filed an action in the Court of Queen’s Bench of Alberta against a number of defendants, including Flint, alleging that the negligent provision of a pipe coating and insulation system, engineering services, design services and other work caused damage to the customer’s pipeline in Canada. The customer alleges that it has suffered damages in the amount of $85 million. While Flint was the construction contractor on the project and did construct the pipeline, it was constructed to a design specified and with materials supplied by others. The customer served the Statement of Claim against Flint in late January 2011, prior to the first anniversary of the filing of the claim. Although the claim has been served, the Plaintiff has advised that Flint is not required to file a Statement of Defence or to take any other steps at this time. Based on management’s current understanding of the facts of this claim, management believes Flint has meritorious defences to this action and, as such, does not believe that this litigation will materially affect the Company’s consolidated financial position or results of its operations. Accordingly, no provision for losses has been reflected in the accounts of the Company for this matter. The Company is also involved in various other claims and legal actions arising in the ordinary course of business. In the opinion of management, the ultimate disposition of these matters will not have a material adverse effect on the Company’s consolidated financial position, results of operations, or liquidity.
Related Party Transactions During the years ended December 31, 2010 and 2009, the Company entered into the following related party transactions: 2010
2009
Expenses: $
Transportation and supply of materials reported in direct costs Information system support reported in general and administrative expenses Facility leases reported in general and administrative expenses
$
–
$
0.3
0.1
1.0
1.0
1.4
1.1
2 0 1 0
A n n ua l
$
2.7
Rep o r t
39
MANAGEMENT’S DISCUSSION AND ANALYSIS
For the year ended December 31, 2010 (in millions of Canadian dollars except share data and per share amounts, unless otherwise stated)
The related party transactions occur with parties related by equity investments, parties related by common directors and transactions with other private companies owned or controlled by officers or directors of the Company. The transactions with related parties occurred in the normal course of operations and are measured at the exchange amount, that is, the amount of consideration established and agreed to by the related parties.
Off-Balance Sheet Arrangements The Company has not entered into any off-balance sheet arrangements.
Outstanding Share Data The Company is authorized to issue an unlimited number of common shares and an unlimited number of preferred shares. As at December 31, 2010, 45,652,214 common shares were outstanding as compared to 45,501,214 as at December 31, 2009. No preferred shares were outstanding during or at the end of either of these periods. Certain employees, officers and directors of the Company have been granted options and/or units (Deferred Share Units, Restricted Share Units and Performance Share Units) to purchase common shares under the Company’s share-based payment plans. There were 2,683,583 stock options and 903,188 units outstanding at December 31, 2010. As of March 15, 2011 there were 45,656,214 common shares of the Company outstanding and 3,067,594 options to acquire common shares outstanding.
Changes in Accounting Policies (i) Business Combinations Effective January 1, 2010, the Company early-adopted CICA Handbook Section 1582, “Business Combinations”. Section 1582 establishes the standards for the accounting of business combinations, and requires that all assets and liabilities of an acquired business be recorded at fair value. Obligations for contingent consideration and contingencies shall also be recorded at fair value at the acquisition date. The standard also requires that acquisition-related costs be expensed as incurred and that restructuring charges be expensed in the periods after the acquisition date and that non-controlling interests would be measured at fair value at the date of acquisition. This standard has been applied prospectively to business combinations with acquisition dates on or after January 1, 2010. (ii) Consolidated Financial Statements Effective January 1, 2010, the Company early-adopted CICA Handbook Section 1601, “Consolidated Financial Statements”, as a result of adopting Section 1582. This section partly replaces the existing Section 1600. Section 1601 carries forward existing Canadian guidance for preparing consolidated financial statements other than non-controlling interests. The adoption of this standard did not have a significant impact on the Company’s consolidated financial statements.
40
Flint
E n e r g y
S e r v i c es
L t d.
MANAGEMENT’S DISCUSSION AND ANALYSIS
For the year ended December 31, 2010 (in millions of Canadian dollars except share data and per share amounts, unless otherwise stated)
(iii) Non-Controlling Interests Effective January 1, 2010, the Company early-adopted CICA Handbook Section 1602, “Non-controlling Interests”, as a result of adopting Section 1582. This section partly replaces the existing Section 1600. Section 1602 establishes standards for the accounting of non-controlling interests of a subsidiary in the preparation of consolidated financial statements subsequent to a business combination. The adoption of this standard did not have a significant impact on the Company’s consolidated financial statements. (iv) Equity Effective January 1, 2010, the Company adopted the amendments relating to presentation requirements of CICA Handbook Section 3251, “Equity” as a result of adopting Section 1602, “Non-controlling Interests”. The adoption of this standard did not have a significant impact on the Company’s consolidated financial statements.
Future Accounting Pronouncements The following are recent accounting pronouncements issued by various bodies but not yet adopted by the Company: (i) Convergence with International Financial Reporting Standards In February 2008, CICA’s Accounting Standards Board (AcSB) confirmed that Canadian publicly accountable enterprises will be required to adopt International Financial Reporting Standards (IFRS) as promulgated by the International Accounting Standards Board (IASB) for fiscal periods beginning on or after January 1, 2011. Flint’s first annual IFRS financial statements will be for the year ending December 31, 2011 and will include the comparative period of 2010. Beginning in the first quarter of 2011, the Company will provide unaudited consolidated financial information in accordance with IFRS including comparative figures for 2010. The Company commenced its IFRS conversion project during the second quarter of 2008. The IFRS conversion project is led by an IFRS steering committee, which includes senior management representing accounting, information technology (IT), treasury, human resources, and operations. This IFRS steering committee has provided senior management guidance and regular updates as to the status of the conversion project. The Company’s conversion plan ensures that the Audit Committee of the Board of Directors and other key stakeholders are adequately informed about the anticipated effects of the IFRS transition. The Audit Committee is provided with quarterly updates.
2 0 1 0
A n n ua l
Rep o r t
41
MANAGEMENT’S DISCUSSION AND ANALYSIS
For the year ended December 31, 2010 (in millions of Canadian dollars except share data and per share amounts, unless otherwise stated)
The table below gives a summary update of the project status. Phase Phase One:
Description The technical evaluation of significant
Assessment
differences between Canadian GAAP and IFRS as is relevant to the Company.
Status Complete. Beginning in the third quarter of 2008, the Company carried out high-level analysis to determine
In January 2009, the IASB released
differences specific to the Company relating to
its work plan and projected timetable
Canadian GAAP and IFRS. In the first quarter of 2009
for new standards and amendments on
a report on the high-level scoping exercise for the
various topics including consolidations,
project was produced.
financial instruments, income taxes, liabilities, revenue recognition and IFRS 1.
Results of the high-level analysis and scoping exercise were instrumental in prioritizing, resourcing and ultimately developing an updated IFRS conversion plan for the Company. The development plan includes an implementation timetable which identifies the key activities that will occur over the period leading up to
Phase Two:
The identification, evaluation, and
Design
selection of accounting policies necessary for the Company to change over to IFRS.
the changeover. Complete. The Company has completed the process of selecting and/or adopting IFRS accounting policy choices and has finalized IT solution development
In addition, this phase includes an
processes necessary for the changeover to IFRS.
assessment and selection of the
Although the accounting policy choices have
operational elements necessary to
been finalized the final quantitative impact on the
change over to IFRS such as training,
Company’s financial position and future results can
IT, internal controls over financial
not be reasonably determined until full understanding
reporting, and other business activities
of the implementation of the policies is known
that may be influenced by GAAP
under Phase Three. However, it is becoming clear
measures such as debt covenants,
to management that current analysis suggests that
hedging, sales practices, and
property, plant and equipment will likely have the
compensation arrangements.
greatest impact on the Company. The design and development of IT solutions necessary to effect the conversion to IFRS, including dual reporting under Canadian GAAP and IFRS during the 2010 transition period, have been completed. This work stream has now begun the implementation processes under Phase Three. Phase Two scheduled comprehensive training targeted at staff in the Company’s areas most affected by the conversion to IFRS was completed on schedule. Audit Committee and Board of Directors training was also completed.
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MANAGEMENT’S DISCUSSION AND ANALYSIS
For the year ended December 31, 2010 (in millions of Canadian dollars except share data and per share amounts, unless otherwise stated)
Phase Phase Three:
Description The integration of financial and
Implementation
operational processes necessary to change over to IFRS.
Status In Progress. Outcomes derived from Phase Two work streams were pivotal in moving Phase Three implementation work streams forward. Implementation of selected and/or adopted accounting policy choices has been completed. The focus has now shifted towards verifying the Company’s IFRS opening balance sheet and related 2010 quarterly comparative financial statements. The outcome of this work stream includes a finalized quantitative impact analysis of the Company’s conversion to IFRS. Implementation of the IT solutions developed under Phase Two is progressing well and is on schedule. The work stream is currently approaching the final stages of implementation, with the high-impact areas of the system that relate to property, plant and equipment having been substantially completed. Comprehensive training targeted at staff in the Company’s areas most affected by the conversion to IFRS is proceeding well and is on schedule. Training sessions are regular and ongoing through March 2011.
The project is progressing according to the conversion plan and is on schedule.
Preliminary Quantitative Impact Assessment While the final quantitative impact of converting to IFRS cannot be reasonably determined at this stage, the section below illustrates the preliminary quantitative assessment of the impact of adopting IFRS on the Company’s balance sheet as at January 1, 2010 (the Company’s “date of transition” to IFRS). An explanation of how the transition from Canadian GAAP to IFRS has affected the Company’s financial position is set out in the following table and the notes that accompany the table, and is based on the standards as published on the Company’s date of transition. Any revisions or changes to the standards issued by the IASB after this date may also contribute to a material change in the results and the impact discussed below. Consequently, the quantitative differences identified below should be regarded as preliminary and subject to change. There were no significant changes from the preliminary assessment included in the third quarter Management Discussion and Analysis.
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MANAGEMENT’S DISCUSSION AND ANALYSIS
For the year ended December 31, 2010 (in millions of Canadian dollars except share data and per share amounts, unless otherwise stated)
IFRS 1 Elections IFRS 1 First-time Adoption of International Financial Reporting Standards sets out the requirements that the Company must follow when it adopts IFRS for the first time as the basis for preparing its consolidated financial statements. The Company is required to establish its IFRS accounting policies for the 12 months ended December 31, 2011, and apply these retrospectively to determine the IFRS opening balance sheet at the date of transition of January 1, 2010. To assist companies in the transition process, the standard permits a number of specified exemptions from the general principle of retrospective restatement. The Company has based its estimates on the expected election of a number of specified exemptions from the general principle of retrospective application as follows: (i) Business Combinations The Company expects to apply the business combinations exemption in IFRS 1. It has not restated business combinations that took place prior to the Company’s date of transition to IFRS. As a result of this election, there are no significant adjustments expected in the Company’s IFRS opening balance sheet related to business combinations at the transition date. (ii) Fair Value as Deemed Cost The Company expects to elect to measure certain items of property, plant and equipment at fair value as at the Company’s date of transition to IFRS. The fair value of these assets is deemed to be the cost base for accounting purposes at the transition date. (iii) Cumulative Translation Account (CTA) The Company expects to elect to set the previously accumulated cumulative translation adjustments to zero at the Company’s date of transition to IFRS. This exemption has been applied to all subsidiaries in accordance with IFRS 1. As a result of this election, approximately $12.1 million is expected to be transferred from other comprehensive income to deficit at the transition date. (iv) Capitalization of Borrowing Costs The Company expects to apply the transitional provisions of IAS 23 Borrowing Costs prospectively from the Company’s date of transition to IFRS. This exemption applies to all qualifying assets measured at cost in the opening IFRS balance sheet. This policy decision is expected to have no significant impact on the Company’s balance sheet at the transition date. The remaining optional exemptions are not expected to be applicable to the Company. Estimates made under IFRS at January 1, 2010 are consistent with estimates made for the same date under Canadian GAAP. All other mandatory exceptions in IFRS 1 were not applicable because there were no significant differences in management’s application of Canadian GAAP in these areas.
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MANAGEMENT’S DISCUSSION AND ANALYSIS
For the year ended December 31, 2010 (in millions of Canadian dollars except share data and per share amounts, unless otherwise stated)
Property, Plant and Equipment The Company’s preliminary quantitative impact assessment indicates that the greatest impact to the Company as a result of adopting IFRS relates to items of property, plant and equipment (PPE). The impact may be categorized as follows: Componentization Under IFRS, when parts of an item of PPE have different useful lives, they are accounted for as separate items (major components) of PPE. This has resulted in a more detailed approach to determining the useful lives for certain asset components under IFRS than was used under previous Canadian GAAP. As at the date of transition, the Company retrospectively componentized certain items of property, plant and equipment under IFRS, which is expected to result in the Company recognizing an approximate $4.9 million reduction to the carrying value of PPE as at the date of transition. Impairment In accordance with IFRS, for purposes of assessing impairment of PPE, management has identified cash-generating units (CGUs) based on the smallest group of assets that are capable of generating largely independent cash inflows, which is a different treatment from Canadian GAAP. Further, under IFRS, the recoverable amount for impairment analysis is based on discounted cash flows, unlike previous Canadian GAAP, in which the recoverable amount was assessed on an undiscounted basis. Applying the IFRS-based impairment model is expected to result in the Company recognizing approximately $30.2 million in write-downs to the carrying value of PPE. These charges will be recorded directly in the Company’s deficit at the transition date. Deemed Cost Exemption The Company has applied the fair value as deemed cost exemption with respect to certain specified equipment, which is expected to result in approximately $9.7 million of write-downs to the carrying value of PPE.
Leases The Company’s preliminary quantitative impact assessment indicates that approximately $78.5 million in assets and $80.4 million in debt obligations will be recognized on the balance sheet due to the conversion of leases which met the definition of operating leases under Canadian GAAP, now being recognized as finance leases under IFRS.
Joint Ventures The Company will apply IAS 31 Interests in Joint Ventures at the date of transition. The Company expects to use the equity method to recognize interests in joint ventures. Previous Canadian GAAP required that the Company proportionately consolidate its interests in joint ventures. The impact of the transition from proportionate consolidation to the equity method for the Company’s joint ventures is not expected to impact the Company’s net assets and consequently is presented as a reclassification difference. The expected effect of the adoption of the equity method is the reduction of Company liabilities by $40.3 million, the reduction of Company assets by $54.3 million, and the recognition of $14.0 million in non-current assets as the net investment in joint venture entities.
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MANAGEMENTâ&#x20AC;&#x2122;S DISCUSSION AND ANALYSIS
For the year ended December 31, 2010 (in millions of Canadian dollars except share data and per share amounts, unless otherwise stated)
Share-Based Payments
Cash-Settled Awards
Under Canadian GAAP, the Company had accounted for cash-settled share-based payment arrangements by reference
to their intrinsic value. Under IFRS, the related liability is recorded at the fair value of the outstanding cash-settled
share-based payment. This amount is not expected to be materially different from that determined under
Canadian GAAP.
Vesting
Under IFRS the Company will accrue the cost of share-based payments over the vesting period using the graded
method of amortization with each instalment accounted for as a separate arrangement. Under Canadian GAAP,
the Company treated share-based payments as a pool and determined fair value using an average life of the
instruments, provided that compensation was recognized on a straight-line basis, subject to at least the value of
the vested portion of the award being recognized at each reporting date. This is expected to result in an increase of
approximately $0.5 million to contributed surplus and a reduction of approximately $0.2 million to retained earnings
as at the date of transition.
IAS 1: Presentation of Financial Statements (IAS 1) Under IFRS, IAS 1 prescribes the basis for the presentation of general purpose financial statements to ensure comparability with the entityâ&#x20AC;&#x2122;s financial statements of previous periods and with the financial statements of other entities. Applying IAS 1 is expected to result in the reclassification of approximately $6.2 million of deferred tax assets from current assets to non-current assets, while approximately $5.1 million is expected to be reclassified from current liabilities to non-current liabilities.
Cumulative Translation Account (CTA) In accordance with IFRS 1, the Company expects to elect to deem all foreign currency translation differences that arose prior to the date of transition in respect of all foreign operations to be nil at the date of transition. As a result of this election, approximately $12.1 million is expected to be transferred from other comprehensive income to deficit at transition date.
Income Tax Adjustments
PPE-Related Tax Impact
The tax impact of IFRS adjustments related to items of PPE is expected to result in an approximate $12.0 million decrease in the net deferred tax liability at the date of transition.
Lease-Related Tax Impact
The conversion of operating leases to finance leases under IFRS is expected to result in an approximate $0.5 million decrease in the net deferred tax liability at the date of transition.
Share-Based Payments-Related Tax Impact
IFRS adjustments related to share-based payment arrangements are expected to result in an approximate $0.1 million increase in the net deferred tax liability at the date of transition.
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MANAGEMENT’S DISCUSSION AND ANALYSIS
For the year ended December 31, 2010 (in millions of Canadian dollars except share data and per share amounts, unless otherwise stated)
Use of Accounting Estimates In preparing the consolidated financial statements, various accounting estimates are made in applying the Company’s accounting policies. These estimates require significant judgment on the part of management and are considered critical as they are important to the Company’s financial condition and results. The following represents the estimates that management considers most critical to the application of the Company’s significant accounting policies. Revenue Recognition The Company’s principal sources of revenue and recognition of these revenues for financial statement purposes are as follows: (i)
The Company’s Production Services and Facility Infrastructure reporting segments perform the majority of their projects under the following types of contracts: time-and-materials; cost-plus-fixed-fee; unit-price; and fixed price or lump sum. For these contract types, revenue is recognized using the percentage-of-completion method, measured by the ratio of costs incurred and units produced to date relative to total estimated costs and units to be produced. The resulting ratio is applied to the approved contract value to determine the revenue recognized. The estimated total cost of the contract and percentage complete is determined based upon estimates made by management. The costs of items that do not relate to performance of contracted work, particularly in the early stages of the contract, are excluded from costs incurred to date. Contract costs include all direct materials, equipment, and labour costs and those indirect costs related to contract performance, such as indirect labour, supplies, and tools. General and administrative costs are charged to expense as incurred. Changes in project performance, project conditions, and estimated profitability, including those arising from contract penalty provisions and final contract settlements, may result in revisions to costs and income that are recognized in the period in which such adjustments are determined. Provisions for estimated losses on all uncompleted contracts are made in the period in which such losses are identified. Costs related to change orders and claims are recognized when they are incurred. Revenues related to change orders are included in total estimated contract revenue when they are approved. Once a project is underway, the Company may experience changes in conditions, client requirements, specifications, designs, materials, and work schedules. In these circumstances, a change order is generally negotiated with the customer to modify the terms of the original contract to approve the scope and price of the change. When a change order is unapproved in scope and price or becomes a point of dispute between the Company and a customer, the Company then considers it a claim. Claims are included in total estimated contract revenue only to the extent that contract costs related to the claim have been incurred and when it is probable that the claim will result in a bona fide addition to contract value and revenues can be reliably estimated. This can lead to a situation in which costs are recognized in one period and revenue is recognized when customer agreement is obtained or claim resolution occurs, which can be in subsequent periods. In Facility Infrastructure, the length of contracts varies from one year to several years, whereas in Production Services contracts are typically less than one year long. The Company’s long-term contracts typically allow the customer to unilaterally reduce, delay or eliminate the scope of the work as contracted without cause. As a result, these long-term contracts represent higher risk due to uncertainty of total contract value and estimated costs to complete potentially impacting revenue recognition in future periods. Revenue in excess of billings represents costs incurred and revenues earned in excess of amounts billed on uncompleted contracts. Billings in excess of revenue represent amounts invoiced in excess of revenue recognized.
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MANAGEMENT’S DISCUSSION AND ANALYSIS
For the year ended December 31, 2010 (in millions of Canadian dollars except share data and per share amounts, unless otherwise stated)
(ii) The Company recognizes revenue from the sale of its other products and services as follows: (a) Revenue from Oilfield Services is provided based upon orders and contracts with the customer that include fixed or determinable prices based upon daily, hourly or job rates and is recognized as the services are provided to the customer; (b) Revenue from manufacturing and product sales is recognized when the products are shipped to the customer; and revenue from inspections, threading, refurbishment and bucking of drill and line pipe is recognized as the services are performed; and (c) Revenue from Maintenance Services is recognized as services are rendered. Specific contracts include the provision of key performance indicators that provide additional revenue to the Company if it achieves certain performance-based measurements. This revenue is recognized only when the performance-based measure is fixed and determinable. The Company recognizes revenue from the foregoing activities once persuasive evidence of an arrangement exists, delivery has occurred or services have been rendered, fees are fixed and determinable and collectability is reasonably assured. Amortization of Property, Plant and Equipment The Company’s Production Services and Oilfield Services reportable segments require a significant investment in construction and hauling equipment. In accordance with the Company’s accounting policy related to the amortization of PPE, the cost of construction and hauling equipment is amortized over its estimated useful life. Judgment is involved in determining the useful life of the equipment, the estimated residual value and the appropriate method of amortization. Factors considered in estimating the useful life of an item of construction or hauling equipment include expected future usage, effects of technological or commercial obsolescence, expected wear and tear from use or the passage of time, the effectiveness of the Company’s maintenance program and historical information of similar items retired. The same factors are considered in estimating the residual value of an item of construction or hauling equipment. The accuracy in estimating the residual value of an item of construction or hauling equipment becomes increasingly difficult the further the estimated useful life extends. The Company’s investment in construction and hauling equipment results in amortization expense being a significant operating cost to the Company, and any misjudgement in estimating the useful life or the residual value of the equipment could result in a misstatement of consolidated amortization expense. Allowance for Doubtful Accounts Receivable The Company performs ongoing credit evaluations of its customers and grants credit based upon the customer’s payment history and financial condition, taking into consideration anticipated changes in industry and economic conditions. Customer payments are regularly monitored and estimates of the allowance for doubtful accounts are determined on a customer-by-customer evaluation of collectability at each reporting date, taking into consideration the following factors: the length of time the receivable has been outstanding, specific knowledge of each customer’s financial condition, and historical experience. The Company’s experience with respect to the incurrence of bad debt losses has been within expectations in 2010 and has generally been limited to a select number of specific customer situations. Given the cyclical nature of the North American oil and natural gas services industry and the risk associated with finding and producing hydrocarbons, a customer’s ability to fulfill its obligations can change without notice.
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MANAGEMENT’S DISCUSSION AND ANALYSIS
For the year ended December 31, 2010 (in millions of Canadian dollars except share data and per share amounts, unless otherwise stated)
Accounting for Impairment of Long-Lived Assets The Company reviews long-lived assets which include property, plant and equipment and identifiable intangible assets with finite lives, for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is assessed by a comparison of the carrying amount of assets to the sum of future undiscounted cash flows expected to be generated from the use and eventual disposition by the group of assets. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the group of assets exceeds the fair value of the assets and is charged to the consolidated statement of earnings (loss). Fair value is determined using prices for similar items or the results of discounted cash flows when quoted market prices are not available. The Company made assumptions about the future cash flows expected from the use of its long-lived assets, such as: applicable industry performance and prospects; general business and economic conditions that prevail and are expected to prevail; expected growth; maintaining its customer base; and achieving cost reductions. There can be no assurance that expected future cash flows will be realized, or will be sufficient to recover the carrying amount of long-lived assets. Furthermore, the process of determining fair values is subjective and requires management to exercise judgment in making assumptions about future results, including revenue and cash flow projections and discount rates.
Business Risks The Company’s results are affected by a number of external factors, including commodity prices, which drive producer capital spending levels and the demand for Flint’s project-related services, as well as foreign currency, interest rate, operational, credit and safety risks. Oil and Gas Producer Capital Spending Levels The Company’s business is directly affected by fluctuations in the levels of exploration, oil sands development and production activity carried on by its customers, which in turn is dictated by numerous factors, including world energy prices and government policies. Projected crude oil and natural gas prices drive oil and natural gas producers’ capital expenditures, including drilling, and production and exploration activity, which in turn impacts the Company’s activity levels. Producers’ capital spending levels have a significant impact on the results of the Company’s Facility Infrastructure and Oilfield Services segments, compared to the Production Services and Maintenance Services segments, as the latter perform services more related to the ongoing operation and maintenance of producers’ physical plants and production. As it is difficult for the Company to effectively anticipate the fluctuations in activity resulting from the peaks and troughs in producers’ spending related to large capital projects, the Company manages to operate its reportable segments in such a manner as to maximize their scalability relative to activity levels. A significant prolonged decline in commodity prices could have a material adverse effect on the Company’s results of operations and financial condition. Foreign Currency The Company minimizes its exposure to unrealized translation gains and losses on United States-denominated monetary items related to the translation of its net United States investment by financing the investment with United States dollardenominated debt. The Company may enter into derivative contracts to manage the exposure to foreign currency related to contracted purchases. The Company does not manage the exposure to fluctuations in the United States to Canadian currency exchange rate related to translating the results of its United States operations.
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MANAGEMENT’S DISCUSSION AND ANALYSIS
For the year ended December 31, 2010 (in millions of Canadian dollars except share data and per share amounts, unless otherwise stated)
Interest Rates In order to minimize the Company’s exposure to fluctuating interest rates, the Company has structured its senior credit facility such that a significant amount of its long-term debt has fixed interest rates, and by using interest rate swaps to fix the interest rate on a portion of the debt for longer periods. Operational Risk and Insurance The Company’s operations are subject to risks inherent in the oil and natural gas industry such as equipment defects, malfunctions, failures and natural disasters. These risks could expose the Company to substantial liability for personal injury, loss of life, business interruptions, property damages or destruction, pollution and other environmental damages. In addition, the Company’s operations are subject to risks normally inherent in the transportation industry, including potential liability which could result from, among other things, personal injury, loss of life or property damages arising from motor vehicle accidents. The Company minimizes its exposure to operational risk through comprehensive vehicle and equipment maintenance programs designed to prevent failure and maximize the useful life of the related assets. In addition, the Company follows a complete quality assurance and control program designed to maximize performance in its work and minimize deficiencies potentially leading to failures and remedial re-work. The Company maintains insurance against certain risks to which it is exposed. However, such insurance is subject to coverage limits and no assurance can be given that such insurance will be adequate to cover the Company’s liabilities or will be generally available in the future or, if available, that premiums will be commercially justifiable. If the Company were to incur substantial liability and such damages were not covered by insurance or were in excess of policy limits, or if the Company were to incur such liability at a time when it is not able to obtain liability insurance, its business, results of operations and financial condition could be materially adversely affected. Safety Risk Safety risks are managed through the application of safety policies and procedures conducive to promoting safe work practices to a standard either complying with or exceeding government regulations and industry requirements. The Company maintains a behaviour-based safety program, which uses positive reinforcement to create a culture of safety consciousness within its employees and contractors. Labour Supply Risk The Company requires a large number of trades personnel to conduct its operations. Recruiting and training these individuals is critical to the Company’s ability to continue to meet customer requirements and generate increasing levels of revenue. As there is very high demand for many of these skilled people, the Company devotes significant resources and planning to the recruitment, retention and training of people in order to secure the required level of staffing and skills necessary to support anticipated levels of work.
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MANAGEMENT’S DISCUSSION AND ANALYSIS
For the year ended December 31, 2010 (in millions of Canadian dollars except share data and per share amounts, unless otherwise stated)
Credit Risk and Reliance on Major Customers The risk of losses from customer non-payment is minimized through the Company’s credit granting policies and other procedures designed to limit the exposure to credit risk. As a result of such practices, the Company’s bad debt expense has historically been minimal. Substantial portions of the Company’s accounts receivable are with customers involved in the oil and natural gas industry whose revenues may be impacted by fluctuations in crude oil and natural gas prices. Management currently considers the risk of a significant loss to be remote. The Company’s top ten customers are all well-known, publicly traded companies and accounted for approximately 55.0% of the Company’s revenue for the year ended December 31, 2010. The largest customer accounted for approximately 13.3% of this revenue. There can be no assurance that the Company’s current customers will continue their relationships with the Company. The loss of one or more major customers, or any significant decrease in services provided to a customer, prices paid, or any other changes to the terms of service with customers, could have a material adverse effect on the Company’s profitability. Fuel Prices Fuel is one of the Company’s major costs and, as such, higher fuel prices could materially affect the Company’s results. The Company manages exposure to rising fuel costs through inclusion of fuel surcharge provisions in customer agreements and contracts. Legislation and Regulation Income tax, environmental and other applicable legislation may change in a manner which adversely affects the Company. Transportation regulations governing the Oilfield Services segment require licensing from or registration with provincial and territorial authorities in order to carry goods extra-provincially or to transport goods within any province or territory. Changes in regulations applicable to the Company could increase operating costs and have a material adverse effect on the Company’s operations and financial condition. The right to continue to hold applicable licences and permits is generally subject to maintaining compliance with regulatory and safety guidelines, policies and regulations. Although the Company is committed to compliance and safety, there is no assurance that the Company will be in full compliance at all times with such policies, guidelines and regulations. Consequently, at some future time, the Company could be required to incur significant costs to maintain or improve its compliance record. Environmental Liability Risks Certain of the Company’s reportable segments routinely deal with natural gas, oil and other petroleum products. The Company has programs to address compliance with current environmental standards and monitors its practices concerning the handling of environmentally hazardous materials. There can be no assurance that the Company’s procedures will prevent environmental damage occurring from spills of materials handled by the Company or that such damage has not already occurred. Although the Company is not aware of any contamination which, if remediation or cleanup were required, would have a material adverse effect on the Company, there can be no assurance that the Company will not be required at some future date to incur significant costs to comply with current or future environmental laws.
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MANAGEMENT’S DISCUSSION AND ANALYSIS
For the year ended December 31, 2010 (in millions of Canadian dollars except share data and per share amounts, unless otherwise stated)
Weather and Seasonality Weather conditions can restrict or impede the Company’s ability to deliver its services. Municipalities and provincial transportation departments enforce road bans during certain times of the year which restrict the movement of the Company’s equipment or those of the customer, thereby reducing the Company’s activity levels during these periods. Additionally, certain oil and natural gas producing areas are only accessible in the winter months due to ground conditions. Seasonal factors and unexpected weather may lead to declines in activity levels of exploration and production companies and corresponding declines in the demand for the goods and services of the Company. The Company’s operations are geographically dispersed throughout the major oil and natural gas producing areas of North America and therefore the risk associated with seasonal and inclement weather is mitigated. Refer to the Annual Information Form for further information on risks.
Disclosure Controls and Procedures and Internal Controls over Financial Reporting The Chief Executive Officer (CEO) and Chief Financial Officer (CFO) are responsible for designing disclosure controls and procedures to ensure that material information is made known to the appropriate individuals. In addition, the CEO and CFO are responsible to design internal controls over financial reporting or cause them to be designed under their supervision in order to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with Canadian GAAP. Disclosure Controls and Procedures An evaluation of the effectiveness of the Company’s disclosure controls and procedures was conducted as of December 31, 2010, by and under the supervision of the Company’s management, including the CEO and CFO. Based on this evaluation, the CEO and CFO concluded that the disclosure controls and procedures were effective as at December 31, 2010. Internal Controls over Financial Reporting The CEO and CFO evaluated the design and operating effectiveness of the Company’s ICFR for the year ended December 31, 2010. Based on that evaluation, they concluded that the design and operation of ICFR were effective as at December 31, 2010 to provide reasonable assurance regarding the reliability and the preparation of financial statements for external purposes in accordance with Canadian GAAP. There were no changes in the Company’s ICFR in the fourth quarter of 2010 that have materially affected, or are reasonably likely to materially affect, the Company’s ICFR. Limitations on the Effectiveness of Disclosure Controls and Procedures and Internal Control over Financial Reporting Management does not expect that the Company’s disclosure controls and procedures and ICFR will prevent all error or fraud. A control system, no matter how well designed and implemented, can provide only reasonable, not absolute, assurance regarding the prevention and detection of errors or fraud. The inherent limitations include: judgments in decision-making can be faulty; breakdowns can occur because of simple errors or mistakes; controls can be circumvented by individual acts or collusion; and management can override controls. Due to the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected.
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MANAGEMENT’S DISCUSSION AND ANALYSIS
For the year ended December 31, 2010 (in millions of Canadian dollars except share data and per share amounts, unless otherwise stated)
Outlook In Canada approximately 12,500 wells were drilled in 2010, up 47% from 2009.(1) Industry forecasts for 2011 call for an 18% increase in drilling in western Canada.(2) This will be primarily driven by crude oil production, especially unconventional crude oil sources such as bitumen, heavy oil and shale oil, as well as certain liquids-rich natural gas projects that remain economic at current commodity prices. United States drilling activity was also up by 47% year-over-year with 52,000 wells drilled in 2010. Industry forecasts(2) in the United States are calling for a 17% increase in drilling in 2011, primarily related to new shale oil plays such as the North Dakota Bakken, as well as continued growth in shale gas areas such as the Marcellus and the Eagle Ford. Production Services activity, which typically lags drilling by approximately two quarters, was up modestly in 2010 from 2009 and is expected to increase as 2011 progresses as a result of work from increased drilling activity and projects that were delayed in late 2010, which are proceeding in 2011. The Oilfield Services segment, which is levered to drilling, was also up modestly in the United States in 2010. The Company has increased its service delivery capacity in the United States through the acquisition of equipment in late 2010, along with the construction of the new Williston, North Dakota office to service the Bakken shale oil play, and a new office in Victoria, Texas to service the Eagle Ford liquids-rich shale gas play. Maintenance Services revenues in 2010 reached a record $421 million due to new contracts and increased scope on existing contracts. Last year, revenue gains were from planned turnarounds and unplanned shutdowns. There is less planned turnaround activity in 2011 and although management expects revenues to trend down slightly from 2010, growth is expected in the maintenance business as additional production from new and existing projects continues to drive maintenance spending levels. Facility Infrastructure experienced reduced revenues in the second half of 2010 with the completion of the Shell Albian Sands project and the Statoil Canada Leismer project in July, combined with delays in new project contract awards. Current backlog in this segment is approximately $105 million and includes contract work on Suncor’s Firebag SAGD projects near Fort McMurray. The Company is also pursuing additional contract work with several oil sands operators, but because of the delays in awarding construction work on a number of projects in the first quarter of 2011, expected revenues in this segment will be much lower in the first half of 2011 than in the first half of 2010, and full-year revenues will ramp up more slowly than previously expected. Management expects revenues to climb late in 2011 and remain high from 2012 through 2014. Overall, management believes the gains in activity in other segments in 2011 will partially offset the lower activity in Facility Infrastructure and, accordingly, 2011 revenues from organic sources are expected to be close to 2010 levels. The Company continues to actively pursue accretive acquisitions, as well as green-field expansions in new basins where customers are increasing their unconventional drilling and production activities. Management expects that 2011 will be a year of continued strategic positioning of assets, rebuilding backlog and acquisition activities to prepare the Company for expected growth over the next five years.
1 JuneWarren – Nickles Energy Group 2 Spears and Associates, December, 2010 Drilling and Production Outlook
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MANAGEMENT’S DISCUSSION AND ANALYSIS
For the year ended December 31, 2010 (in millions of Canadian dollars except share data and per share amounts, unless otherwise stated)
Management is strategically capitalizing on the Flint business model and has several initiatives commencing in the first quarter of 2011. The Facility Infrastructure group has positioned key personnel in Houston to begin bidding and executing larger energy infrastructure projects in the U.S. market and expects to have some contract awards in place by the second half of 2011. Oilfield Services has several U.S. expansion initiatives underway with committed contracts already in place as well as fluid hauling services being added to the Eagle Ford shale operations. These operations are expected to commence in the second quarter of 2011. The Oilfield Services segment’s expansion into North Dakota has been accelerated with two clients committing to the Company’s rig moving services for the spring of 2011. Production Services continues to expand the Wear Technology business, and Flint InnerArmor’s first plasma machine, located in Calgary, Alberta, commenced applying internal wear coating to pipe spools in February 2011 on a pilot basis. The test was successful and orders are in place for additional product from Flint’s first clients.
Additional Information Additional information related to the Company is available on the System for Electronic Document Analysis and Retrieval (SEDAR) at www.sedar.com, including a copy of the Company’s latest Annual Information Form. March 15, 2011
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Management’s Responsibility for the Financial Statements The management of Flint Energy Services Ltd. is responsible for the preparation of all the information included in these consolidated financial statements. The consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles and, where necessary, include amounts based on management’s informed judgments and estimates. Management maintains an appropriate system of accounting and administrative controls to provide reasonable assurance that transactions are appropriately authorized, assets are safeguarded and financial records are properly maintained to provide reliable consolidated financial statements. In addition, programs of proper business conduct and risk management have been implemented to protect the Company’s assets and operations. KPMG LLP, whose report follows, were appointed as independent auditors by a vote of the Company’s shareholders to audit the consolidated financial statements. The Board of Directors, through its Audit Committee, is responsible for ensuring that management fulfills its financial reporting responsibilities. The Audit Committee reviews the consolidated financial statements and meets regularly with management, internal auditors and KPMG LLP to discuss internal controls, accounting and auditing and financial matters. The independent auditors and internal auditors have unrestricted access to the Audit Committee. The Audit Committee reports its findings to the Board of Directors for its consideration in approving the consolidated financial statements.
W. J. (Bill) Lingard
Paul M. Boechler
President and Chief Executive Officer
Executive Vice President and Chief Financial Officer
March 15, 2011
2 0 1 0
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Independent Auditors’ Report
TO THE SHAREHOLDERS We have audited the accompanying consolidated financial statements of Flint Energy Services Ltd., which comprise the consolidated balance sheets as at December 31, 2010 and December 31, 2009 and the consolidated statements of earnings, comprehensive earnings, shareholders’ equity and cash flows for the years then ended, and notes, comprising a summary of significant accounting policies and other explanatory information.
Management’s Responsibility for the Consolidated Financial Statements Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with Canadian generally accepted accounting principles, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.
AuditorS’ Responsibility Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we comply with ethical requirements and plan and perform an audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement. An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditors’ judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.
Opinion In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of Flint Energy Services Ltd. as at December 31, 2010 and December 31, 2009, and its consolidated results of operations and its consolidated cash flows for the years then ended in accordance with Canadian generally accepted accounting principles.
Chartered Accountants Edmonton, Canada March 15, 2011
58
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E n e r g y
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Consolidated Balance Sheets
(in thousands of Canadian dollars) 2010
As at December 31
2009
ASSETS Current assets: Cash and cash equivalents (Note 4) $ 163,629 Accounts receivable (Note 20(d)(i)) 258,152 Revenue in excess of billings 56,958 Inventories (Note 5) 51,249 Prepaid expenses and deposits 13,977 Income taxes receivable 21,597 Future income tax assets (Note 10(a)) 2,534 568,096 Long-term investment (Note 7) 1,989 Property, plant and equipment (Note 6) 389,674 Goodwill (Note 8) 84 Intangible assets (Note 9) 9,614 Other long-term assets 1,159 Future income tax assets (Note 10(a)) 13,006
$ 163,929 244,296 62,879 51,148 11,449 7,416 5,786 546,903 – 381,924 – 7,198 934 24,509
$ 983,622
$ 961,468
$
$
LIABILITIES AND SHAREHOLDERS’ EQUITY Current liabilities: Bank indebtedness (Note 11) Accounts payable and accrued liabilities Billings in excess of revenue Income taxes payable Future income tax liabilities (Note 10(a)) Current portion of long-term debt (Note 12)
12,915 159,501 6,056 3,854 6,346 136,902 325,574
Derivative financial instruments (Note 20(b)) 1,259 Long-term debt (Note 12) 92,390 Future income tax liabilities (Note 10(a)) 20,966 440,189 Shareholders’ equity: Accumulated other comprehensive loss (15,838) Deficit (19,122) (34,960) Capital stock (Note 13(a)) 554,015 Contributed surplus (Note 14) 24,378 543,433 $ 983,622
– 160,701 4,654 5,187 5,133 16,714 192,389 1,287 222,418 33,566 449,660
(12,106) (52,125) (64,231) 553,018 23,021 511,808 $ 961,468
Commitments and contingencies (Note 18)
See accompanying notes to the consolidated financial statements.
On behalf of the Board:
Stuart O’Connor, Director
William Lingard, Director 2 0 1 0
A n n ua l
Rep o r t
59
Consolidated statements of earnings
(in thousands of Canadian dollars, except share data) Years ended December 31 2010
2009
$ 1,781,340
$ 1,876,536
1,504,737
1,578,495
276,603
298,041
General and administrative expenses
148,329
151,546
Revenue Direct costs
56,300
57,655
Amortization on intangible assets
2,008
95
Share based compensation expense
8,540
4,915
(395)
(1,413)
Gain on business combination (Note 3 (b))
(1,083)
–
Earnings before other expense (income) and income taxes
62,904
85,243
Amortization on property, plant and equipment
Gain on disposal of property, plant, and equipment
Other expense (income): Interest expense
15,569
17,256
Interest income
(3,593)
(297)
Earnings before income taxes
50,928
68,284
Income taxes (Note 10): Current
19,788
28,935
Future reduction
(1,863)
(6,462)
17,925
$
Net earnings
33,003
22,473 $
45,811
Earnings per share: Basic (Note 15)
$
0.72
$
1.00
Diluted (Note 15)
$
0.72
$
1.00
Weighted average common shares: 45,594,986
Basic (Note 15)
45,988,428 46,032,422
Diluted (Note 15) See accompanying notes to the consolidated financial statements.
60
Flint
E n e r g y
45,722,973
S e r v i c es
L t d.
Consolidated Statements of COmprehensive Earnings (in thousands of Canadian dollars) Years ended December 31
2010
2009
$ 33,003
Net earnings
$ 45,811
Other comprehensive loss: Unrealized loss on foreign currency translation of self-sustaining foreign operations
(3,732)
(11,033)
Other comprehensive loss
(3,732)
(11,033)
$ 29,271
$ 34,778
Comprehensive earnings See accompanying notes to the consolidated financial statements.
Consolidated statements of Shareholders’ Equity
(in thousands of Canadian dollars)
Accumulated Other Comprehensive Loss
Balance, December 31, 2008 (Note 1(p))
$ (1,073)
Capital Stock
$ 561,376
Net earnings (Note 1 (p))
–
–
Exercised employee stock options
–
6
Transfer for stock options exercised
–
2
Employee stock option expense
–
–
Purchases under normal course issuer bid (Note 13(a)(ii))
–
Contributed Surplus
$ 17,015
$
– –
Deficit
Total
(97,936)
$ 479,382
45,811
45,811
–
6
(2)
–
–
3,107
–
3,107
2,901
–
(5,465)
Unrealized loss on foreign currency translation of self-sustaining foreign operations (11,033) – – –
(11,033)
Balance, December 31, 2009
$ (12,106)
(8,366)
$ 553,018
Net earnings
–
Exercised employee stock options
–
741
Transfer for stock options exercised
–
256
Employee stock option expense
–
Unrealized loss on foreign currency translation of self-sustaining foreign operations Balance, December 31, 2010
(3,732) $ (15,838)
–
–
$ 23,021
$
– –
(52,125)
$ 511,808
33,003
33,003
–
741
(256)
–
–
1,613
–
1,613
– $ 554,015
– $ 24,378
– $ (19,122)
(3,732) $ 543,433
See accompanying notes to the consolidated financial statements.
2 0 1 0
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Consolidated Statements of cash flow
(in thousands of Canadian dollars) Years ended December 31
2010
2009
Cash provided by (used in): Operating activities: $
Net earnings
33,003
$
45,811
Items not affecting cash: 57,895
Amortization on property, plant and equipment
58,975
2,008
95
Amortization on finance costs (Note 12)
300
1,318
Gain on disposal of property, plant and equipment
(395)
(1,413)
Amortization on intangible assets
Gain on business combination (Note 3 (b))
(1,083)
–
Share based compensation expense
8,540
4,915
Unrealized (gain) loss on derivative financial instruments (Note 20(d)(iii)) Unrealized foreign exchange gain on long-term debt (Note 20(d)(iii))
(28)
579
(451)
(1,336)
Future income taxes reduction
(1,863)
(6,462)
97,926
102,482
Changes in non-cash balances relating to operations (Note 22)
(5,075)
154,058
Net cash provided by operating activities
92,851
256,540
Investing activities: Business combination (Note 3)
(42,928)
–
Purchase of property, plant and equipment
(40,635)
(28,132)
Proceeds from disposal of property, plant and equipment
14,045
12,287
Long-term investment (Note 7)
(1,989)
–
Purchase of intangible assets (Note 9)
(4,838)
(7,293)
(76,345)
(23,138)
Net cash used in investing activities
Financing activities: –
Decrease in revolving operating loan
(40,900)
Proceeds from long-term debt
743
15,371
Repayments of long-term debt
(12,474)
(30,735)
(4,181)
(3,152)
Repayment of obligations under capital lease
–
Finance costs
(777)
741
Proceeds from issue of capital stock on exercise of options (Note 13(a)(i))
6
–
Share repurchase via normal course issuer bid (Note 13(a)(ii))
(5,465)
(15,171)
Net cash used in financing activities Effect of foreign exchange rate changes on cash balances (Decrease) increase in cash
(1,635)
(5,229)
(300)
162,521
163,929
Cash and cash equivalents, beginning of period
$ 163,629
Cash and cash equivalents, end of period
(65,652)
1,408 $
163,929
$
(17,833)
$
(27,320)
Supplemental cash flow information: Net cash (paid) received during the period for: Interest paid
$
(16,500)
$
(35,349)
3,593
Interest received Income taxes paid (net of income taxes received) See accompanying notes to the consolidated financial statements.
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Notes to the consolidated financial statements December 31, 2010 and 2009 (in thousands of Canadian dollars except share data, unless otherwise specified)
General Flint Energy Services Ltd. (the “Company” or “Flint”) is incorporated in Canada under the Business Corporations Act (Alberta). The Company provides a full range of integrated products and services for the oil and gas industry including: production services, infrastructure construction, oilfield transportation, and maintenance services. The Company provides these services from over 60 centers in the oil and gas producing regions of western North America from Inuvik in the Northwest Territories to Mission, Texas. The Company’s common stock is traded on the Toronto Stock Exchange under the symbol “FES”.
1. Summary of Significant Accounting Policies and Practices (a) Basis of Presentation These consolidated financial statements are expressed in Canadian dollars and have been prepared in accordance with accounting principles generally accepted in Canada. The consolidated financial statements include the accounts of Flint Energy Services Ltd. and all subsidiary companies, collectively referred to as the “Company” or “Flint”. All subsidiary companies are wholly-owned and all material intercompany balances and transactions have been eliminated upon consolidation. The Company proportionately consolidates its interests in joint ventures, whereby the Company’s proportionate share of revenues, expenses, assets and liabilities are included in the accounts.
(b) Measurement Uncertainty The timely preparation of the consolidated financial statements in conformity with Canadian generally accepted accounting principles requires that management make estimates and assumptions and use judgment regarding reported amounts of assets and liabilities, and disclosures of contingent assets and liabilities at the dates of the consolidated financial statements and the reported amounts of revenue and expenses during the years then ended. Significant estimates used in the preparation of these consolidated financial statements include the assessment of the percentage completion on time-and-materials, unit-price, cost-plus-fixed fee, fixed price or lump sum contracts (including estimated total costs and provisions for estimated losses) and the recognition of claims and change orders on contracts; assumptions used in periodic impairment testing of long-lived assets; assumptions used to value financial instruments; estimates and assumptions used in the determination of the allowance for doubtful accounts; and useful lives of property, plant and equipment. Accordingly, actual results may differ materially from these estimates and assumptions. The accuracy of the Company’s revenue and profit recognition in a given period is dependent, in part, on the accuracy of its estimates of the cost to complete each time-and-materials, unit-price, cost-plus-fixed fee, fixed price or lump sum contract. The Company’s cost estimates are based upon a detailed approach, using inputs such as labor and equipment hours, detailed drawings and material lists. These estimates are reviewed and updated monthly. However, major changes in cost estimates can have a significant effect on revenue and profit recognition. The Company’s experience allows it to produce materially reliable estimates. However, the Company’s projects can be highly complex. Profit margin estimates for a project may either increase or decrease to some extent from the amount that was originally estimated at the time of the related bid. With many projects of varying levels of complexity and size in process at any given time, changes in estimates can offset each other without materially impacting its profitability. Major changes in cost estimates, particularly in larger, more complex projects, can have a significant effect on profitability.
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NOtes to the consolidated financial statements
December 31, 2010 and 2009 (in thousands of Canadian dollars except share data, unless otherwise specified)
(c) Cash and Cash Equivalents Cash and cash equivalents is comprised of cash on hand less cheques issued at year-end that have not been processed by the Companyâ&#x20AC;&#x2122;s financial institution, as well as short-term investments with maturities of three months or less when purchased.
(d) Inventories Inventories are measured at the lower of cost and net realizable value. The cost of inventories are assigned using weighted average cost, with the exception of certain items of work in progress and finished goods that are not interchangeable, where cost is assigned by using specific identification of their individual costs. Net realizable value represents the estimated selling price for inventories in the ordinary course of business less the estimated costs of completion and the estimate costs necessary to make the sale.
(e) Property, Plant and Equipment Property, plant and equipment are recorded at original cost less accumulated amortization. Equipment under capital lease is recorded at the present value of the minimum lease payments at the inception of the lease and is amortized according to the table below over the shorter of the lease term and the estimated useful life of the asset. Amortization is calculated based upon cost using the straight-line method over the estimated useful lives of the various assets as described below. Leasehold improvements are amortized using the straight-line method over the shorter of the lease term and the estimated useful life of the asset. Amortization is not calculated on assets under construction until the asset is available for use. Repairs and maintenance, which do not enhance the service potential or extend the useful life of the property, plant, and equipment, are charged against direct costs when incurred. The estimated useful life and amortization method for each category of property, plant and equipment are reviewed annually. The estimated useful lives of the various assets are as follows:
Buildings and improvements
20 years
Vehicles and automotive equipment
3-18 years
Construction and other equipment
3-15 years
Office furniture and equipment
3-5 years
(f) Goodwill Goodwill is an asset representing the future economic benefits arising from other assets acquired in a business combination that are not individually identified and separately recognized. Goodwill is reviewed for impairment at least annually. Goodwill is allocated as of the date of the business combination to the Companyâ&#x20AC;&#x2122;s reporting units that are expected to benefit from the business combination.
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NOtes to the consolidated financial statements
December 31, 2010 and 2009 (in thousands of Canadian dollars except share data, unless otherwise specified)
Goodwill is not amortized and is tested for impairment annually on October 1 of each year, or more frequently if events or changes in circumstances indicate it may be impaired. The impairment test is carried out in two steps. In the first step, the carrying amount of the reporting unit is compared to its fair value. When the fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting segment is considered not to be impaired and the second step of the impairment test is unnecessary. The second step is carried out when the carrying amount of a reporting unit exceeds its fair value, in which case the implied fair value of the reporting unit’s goodwill is compared with its carrying amount to measure the amount of the impairment loss, if any. The implied fair value of goodwill is determined in the same manner as the value of goodwill is determined in a business combination described in the preceding paragraph, using the fair value of the reporting unit as if it was the purchase price. When the carrying amount of the reporting segment’s goodwill exceeds the implied fair value of the goodwill, an impairment loss is recognized in an amount equal to the excess.
(g) Intangible Assets Intangible assets acquired individually or as part of a group of assets are initially recognized at cost and measured subsequently at cost less accumulated amortization. The cost of a group of intangible assets acquired in a transaction, including those acquired in a business combination that meet the specified criteria for recognition apart from goodwill, is allocated to the individual assets acquired based on their relative fair values. The cost of internally developed intangible assets includes direct development costs and overhead directly attributable to development activity. Costs incurred to enhance the service potential of an intangible asset are capitalized as a betterment, whereas costs incurred in the maintenance of the service potential of an intangible asset are expensed as incurred. The estimated useful lives and amortization methods of intangible assets are reviewed annually. The estimated useful lives of the various intangible assets are as follows:
Computer software
5 years
Customer relationships
10 years
Order backlog
3 months
Non-compete agreement
2 years
(h) Revenue Recognition The Company’s principal sources of revenue and recognition of these revenues for financial statement purposes are as follows: (i)
The Company’s Production Services and Facility Infrastructure reporting segments perform the majority of their projects under the following types of contracts: time-and-materials; cost-plus-fixed-fee; unit-price; and fixed price or lump sum. For these contract types, revenue is recognized using the percentage-of-completion method, measured by the ratio of costs incurred and units produced to date relative to total estimated costs and units to be produced. The resulting ratio is applied to the approved contract value to determine the revenue recognized. The estimated total cost of the contract and percent complete is determined based upon estimates made by management. The costs of items that do not relate to performance of contracted work, particularly in the early stages of the contract, are excluded from costs incurred to date.
2 0 1 0
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NOtes to the consolidated financial statements
December 31, 2010 and 2009 (in thousands of Canadian dollars except share data, unless otherwise specified)
Contract costs include all direct materials, equipment, and labour costs and those indirect costs related to contract performance, such as indirect labour, supplies, and tools. General and administrative costs are charged to expense as incurred. Changes in project performance, project conditions, and estimated profitability, including those arising from contract penalty provisions and final contract settlements, may result in revisions to costs and income that are recognized in the period in which such adjustments are determined. Provisions for estimated losses on all uncompleted contracts are made in the period in which such losses are identified.
Costs related to change orders and claims are recognized when they are incurred. Revenues related to change orders are included in total estimated contract revenue when they are approved. Once a project is underway, the Company may experience changes in conditions, client requirements, specifications, designs, materials, and work schedules. In these circumstances, a change order is generally negotiated with the customer to modify the terms of the original contract to approve both the scope and price of the change.
When a change order is unapproved in both scope and price or becomes a point of dispute between the Company and a customer, the Company will then consider it as a claim. Claims are included in total estimated contract revenue only to the extent that contract costs related to the claim have been incurred and when it is probable that the claim will result in a bona fide addition to contract value and revenues can be reliably estimated. This can lead to a situation where costs are recognized in one period and revenue is recognized when customer agreement is obtained or claim resolution occurs, which can be in subsequent periods.
Within the Facility Infrastructure reporting segment, the length of the contracts varies from one year to several years, whereas within the Production Services reporting segment, the length of the contracts are typically less than one year. The Companyâ&#x20AC;&#x2122;s long-term contracts typically allow its customers to unilaterally reduce, delay or eliminate the scope of the work as contracted without cause. As a result, these long-term contracts represent higher risk due to uncertainty of total contract value and estimated costs to complete potentially impacting revenue recognition in future periods.
Revenue in excess of billings represents costs incurred and revenues earned in excess of amounts billed on uncompleted contracts. Billings in excess of revenue represents amounts invoiced in excess of revenue recognized. (ii) The Company recognizes revenue from the sale of its other products and services as follows: (i) Revenue from Oilfield Services is provided based upon orders and contracts with the customer that include fixed or determinable prices based upon daily, hourly or job rates and is recognized as the services are provided to the customer, (ii) Revenue from manufacturing and product sales is recognized when the products are shipped to the customer; and revenue from inspections, threading, refurbishment and bucking of drill and line pipe is recognized as the services are performed, and (iii) Revenue from Maintenance Services is recognized as services are rendered. Specific contracts include the provision of key performance indicators that provide additional revenue to the Company if certain performance based measurements are achieved by the Company. This revenue is recognized only when the performance based measure is fixed and determinable.
The Company recognizes revenue from the foregoing activities once persuasive evidence of an arrangement exists, delivery has occurred or services have been rendered, fees are fixed and determinable and collectability is reasonably assured.
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NOtes to the consolidated financial statements
December 31, 2010 and 2009 (in thousands of Canadian dollars except share data, unless otherwise specified)
(i) Income Taxes Income taxes are accounted for under the asset and liability method. Under this method, future tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Future tax assets and liabilities are measured using enacted or substantively enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on future tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment or substantive enactment date. The Company accrues interest and penalties for uncertain tax positions in the period in which these uncertainties are identified. A valuation allowance is recorded against any future tax assets if it more likely than not that the asset will not be realized.
(j) Share-Based Compensation Plans (i) Employee Stock Option Plan
The Company accounts for share-based compensation payments that are settled by the issuance of equity at fair value. Employee stock option expense is recognized in the financial statements over the period in which the related services are rendered, which is usually the vesting period of the option or, as applicable, over the period to the date an employee is eligible to retire, whichever is shorter, with a corresponding increase in contributed surplus. The fair value is calculated using the Black-Scholes option pricing model. When options are exercised, the proceeds received by the Company, together with the amount in contributed surplus associated with the exercised options, are credited to share capital.
(ii) Directors’ Deferred Share Unit (“DSU”) Plan
The DSU’s are intended to be settled in cash and are classified as a liability on the consolidated balance sheets, based on the intrinsic value of the units, and recorded in the statement of earnings on a prescribed vesting basis. The change in value of the units resulting from changes in the market price of the Company’s common shares is recognized in the consolidated statements of earnings.
(iii) Restricted Share Unit (“RSU”) Plan
The RSU’s are settled in cash and are classified as a liability on the consolidated balance sheets, based on the intrinsic value of the units, and are recorded in the statement of earnings on a prescribed vesting basis. The cumulative impact of changes in the Company’s payment obligation subsequent to grant of the award and prior to the settlement date, due to changes in the market value of the Company’s common shares, are recorded in the consolidated statements of earnings in the period incurred. The payment amount is established as of the vesting date of the unit.
(iv) Performance Share Unit (“PSU”) Plan
The PSU’s are settled in cash and are classified as a liability on the consolidated balance sheet, based on the intrinsic value of the units, and are recorded in the statement of earnings on a prescribed vesting basis. The cumulative impact of changes in the Company’s payment obligation subsequent to grant of the award and prior to the settlement date, due to changes in management’s assessment of performance against specified levels and the ultimate number of units expected to be issued, are recorded in the consolidated statement of earnings.
2 0 1 0
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NOtes to the consolidated financial statements
December 31, 2010 and 2009 (in thousands of Canadian dollars except share data, unless otherwise specified)
(k) Translation of Foreign Currency Foreign currency transactions are translated to Canadian dollars by applying exchange rates in effect at the transaction date. At each reporting period end, monetary assets and liabilities denominated in foreign currencies are converted to Canadian dollars at rates of exchange prevailing at that date. Foreign exchange gains and losses are included in the determination of earnings. The Companyâ&#x20AC;&#x2122;s investments in its self-sustaining United States subsidiaries are translated into Canadian dollars using the current rate method. Under this method, all assets and liabilities are translated at exchange rates in effect at the balance sheet date and revenues and expenses are translated at average exchange rates for the year. Unrealized translation gains and losses relating to the Companyâ&#x20AC;&#x2122;s self-sustaining operations are included in accumulated other comprehensive loss.
(l) Earnings Per Share Basic earnings per share is calculated by dividing net earnings by the weighted average number of common shares outstanding during each reporting period. The Company uses the Treasury Stock Method for calculating diluted earnings per share. Diluted earnings per share are computed similar to basic earnings per share except that the weighted average number of shares outstanding is increased to include additional shares from the assumed exercise of stock options, if dilutive. The number of additional shares is calculated by assuming that outstanding in-the-money stock options were exercised and that the proceeds from such exercises, including any unamortized stock-based compensation costs, were used to acquire shares of common stock at the average market price during the reporting period.
(m) Accounting for the Impairment of Long-Lived Assets The Company reviews long-lived assets which include property, plant, and equipment and identifiable intangible assets with finite lives, for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset or asset group may not be recoverable. Recoverability of assets to be held and used is assessed by a comparison of the carrying amount of an asset or asset group to the sum of future undiscounted cash flows expected to be generated from its use and eventual disposition. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the long-lived asset or group of assets exceeds its fair value and is charged to the consolidated statement of earnings. Fair value is determined using prices for similar items or the results of discounted cash flows when quoted market prices are not available. The Company made assumptions about the future cash flows expected from the use of its long-lived assets, such as: applicable industry performance and prospects; general business and economic conditions that prevail and are expected to prevail; expected growth; maintaining its customer base; and, achieving cost reductions. There can be no assurance that expected future cash flows will be realized, or will be sufficient to recover the carrying amount of long-lived assets. Furthermore, the process of determining fair values is subjective and requires management to exercise judgment in making assumptions about future results, including revenue and cash flow projections and discount rates. For the years ended December 31, 2010 and 2009, an impairment of long-lived assets did not exist. Assets to be disposed of by sale are reported at the lower of carrying amount or fair value less costs to sell. Such assets are not amortized while they are classified as held for sale.
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NOtes to the consolidated financial statements
December 31, 2010 and 2009 (in thousands of Canadian dollars except share data, unless otherwise specified)
(n) Leases Leases entered into by the Company in which substantially all the benefits and risks of ownership transferred to the Company are recorded as obligations under capital leases, and under the corresponding category of property, plant and equipment. Obligations under capital leases reflect the present value of future lease payments, discounted at an appropriate interest rate, and are reduced by rental payments net of imputed interest. All other leases are classified as operating leases and leasing costs, including any rent holidays, leasehold incentives, and rent concessions, are amortized on a straight line basis over the lease term.
(o) Financial Instruments (i) Classification and Measurement
The Company classifies financial instruments into one of five categories: held for trading, available-for-sale financial assets, held-to-maturity investments, loans and receivables or other financial liabilities. The classification depends on the purpose for which the financial instruments were acquired and their characteristics. All financial instruments, including derivatives, must initially be recognized at fair value on the balance sheet. Held for trading financial instruments are measured at fair value with changes in fair value recognized in earnings in the period in which they arise. Available-for-sale financial instruments are carried at fair value on the balance sheet, with changes in fair value recorded in other comprehensive income, until such time as the investments are disposed of or an other-than-temporary impairment has occurred, in which case the impairment is recorded in income. Investments in equity instruments classified as available-for-sale that do not have quoted market prices in an active market are measured at cost. Loans and receivables, held-to-maturity investments and other financial liabilities are initially recorded at fair value and are subsequently measured at amortized cost using the effective interest method. The trade date is used to account for regular way purchase and sale contracts.
(ii) Derivative Financial Instruments
The Company uses derivative financial instruments to manage financial risks from fluctuations in exchange rates and interest rates. All such instruments are only used for risk management purposes. The Company does not hold or issue derivative financial instruments for trading or speculative purposes. These derivative financial instruments are not designated as hedges for accounting purposes. Derivative instruments are classified as held for trading financial instruments and are recorded on the balance sheet at fair value with realized and unrealized gains and losses recognized in the consolidated statement of earnings.
(iii) Transaction Costs
Transaction costs are incremental costs that are directly related to the acquisition or issuance of financial assets or liabilities and are accounted for as part of the respective asset or liabilityâ&#x20AC;&#x2122;s carrying value at inception. The Company incurs transaction costs primarily through the issuance of long-term debt. When these costs arise as a result of a modification or exchange of long-term debt the Company classifies these costs as part of the carrying value of long-term debt on the consolidated balance sheet. The costs capitalized within long-term debt are amortized over the expected life of the related debt using the effective interest method. Transaction costs related to debt that has been extinguished are written-off in the period of extinguishment.
2 0 1 0
A n n ua l
Rep o r t
69
NOtes to the consolidated financial statements
December 31, 2010 and 2009 (in thousands of Canadian dollars except share data, unless otherwise specified)
(iv) Fair Value Measurements
The Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs to the extent possible (note 20(b)). The Company determines fair value based on assumptions that market participants would use in pricing an asset or liability. When considering market participant assumptions in fair value measurements, the following fair value hierarchy distinguishes between observable and unobservable inputs, which are categorized in one of the following levels: •
Level 1 Inputs: Unadjusted quoted prices in active markets for identical assets or liabilities accessible to the reporting entity at the measurement date.
•
Level 2 Inputs: Other than quoted prices included in Level 1 inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the asset or liability.
•
Level 3 Inputs: Unobservable inputs for the asset or liability used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at measurement date.
(p) Correction of an Immaterial Error in 2009 Figures The December 31, 2009 financial information reflects the correction of an immaterial error in the Company’s 2009 consolidated financial statements. The 2009 closing deficit contained within these consolidated financial statements has been adjusted from the originally filed 2009 financial statements resulting in the following changes: a decrease in current future income tax assets of $1,038, a decrease in non-current future income tax assets of $2,318, a decrease in income taxes receivable of $2,703, a decrease in income taxes payable of $2,574, a decrease in income taxes expense of $255 and a decrease in future income tax recovery of $467 for a decrease in earnings of $0.02 per share, with a corresponding decrease in accumulated other comprehensive loss of $8 and an increase in opening deficit of $2,772. This correction did not impact the Company’s cash flows from operating, financing, or investing activities. These adjustments resulted from an over-accrual of income tax assets and liabilities that originated in 2006, 2007, 2008 and 2009.
2. Recent Canadian Accounting Pronouncements (a) Changes in Accounting Policies (i) Business Combinations
Effective January 1, 2010, the Company early adopted CICA Handbook Section 1582, “Business Combinations”. Section 1582 establishes the standards for the accounting of business combinations, and states that all assets and liabilities of an acquired business will be recorded at fair value. Obligations for contingent consideration and contingencies will also be recorded at fair value at the acquisition date. The standard also states that acquisitionrelated costs will be expensed as incurred and that restructuring charges will be expensed in the periods after the acquisition date and that non-controlling interests would be measured at fair value or at the non-controlling interest’s proportionate share of the identifiable assets at the date of acquisition. This standard has been applied prospectively to business combinations with acquisition dates on or after January 1, 2010. This new standard was applied to the acquisition of PES Surface Inc. (“PSI”) and Stallion Heavy Haulers (“Stallion”) (note 3).
70
Flint
E n e r g y
S e r v i c es
L t d.
NOtes to the consolidated financial statements
December 31, 2010 and 2009 (in thousands of Canadian dollars except share data, unless otherwise specified)
(ii) Consolidated Financial Statements
Effective January 1, 2010, the Company early adopted CICA Handbook Section 1601, “Consolidated Financial Statements”, as a result of adopting Section 1582. This section partly replaces the existing Section 1600. Section 1601 carries forward existing Canadian guidance for preparing consolidated financial statements other than non-controlling interests. The adoption of this standard did not have a significant impact on the Company’s consolidated financial statements.
(iii) Non-Controlling Interests
Effective January 1, 2010, the Company early adopted CICA Handbook Section 1602, “Non-controlling Interests”, as a result of adopting Section 1582. This section partly replaces the existing Section 1600. Section 1602 establishes standards for the accounting of non-controlling interests of a subsidiary in the preparation of consolidated financial statements subsequent to a business combination. The adoption of this standard did not have a significant impact on the Company’s consolidated financial statements.
(iv) Equity
Effective January 1, 2010, the Company adopted the amendments relating to presentation requirements of CICA Handbook Section 3251, “Equity” as a result of adopting Section 1602, “Non-controlling Interests”. The adoption of this standard did not have a significant impact on the Company’s consolidated financial statements.
(b) Future Accounting Pronouncements Convergence with International Financial Reporting Standards (“IFRS”) In February 2008, CICA’s Accounting Standards Board (“AcSB”) confirmed that Canadian publicly accountable enterprises will be required to adopt IFRS as promulgated by the International Accounting Standards Board (“IASB”), replacing Canadian GAAP effective January 1, 2011. The Company’s first annual IFRS financial statements will be for the year ending December 31, 2011 and will include the comparative period of 2010. Starting in the first quarter of 2011, the Company will provide unaudited interim consolidated financial information in accordance with IFRS, including comparative figures for 2010.
3. Business Combination (a) PES Surface Inc. (“PSI”) On April 1, 2010, the Company acquired 100% of the outstanding common shares of PSI, a subsidiary of Paintearth Energy Services Inc. PSI is a production equipment company that designs and fabricates pressure vessels, line heaters, mini cyclones, combination units, and zero-emission products in Halkirk, Alberta. The acquisition of PSI is expected to provide opportunities for the Company’s U.S. subsidiaries to enter the Canadian production equipment market with an established company. The total purchase price of PSI, net of working capital adjustments, was $6,298 in cash consideration. In addition to the assumption of long-term debt, of which $610 was settled on the date of the acquisition, the Company acquired net working capital, property, plant and equipment, intangible assets and goodwill.
2 0 1 0
A n n ua l
Rep o r t
71
NOtes to the consolidated financial statements
December 31, 2010 and 2009 (in thousands of Canadian dollars except share data, unless otherwise specified)
In the nine months ended December 31, 2010, PSI contributed revenue of $15,166 and net loss of $2,583. If the acquisition had occurred on January 1, 2010, management estimates that consolidated revenue would have been $1,787,419 and consolidated net earnings for the period would have been $32,448. In determining these amounts, management has assumed that the fair value adjustments that arose on the date of acquisition would have been the same if the acquisition had occurred on January 1, 2010. The following summarizes the consideration transferred, and the recognized amounts of assets acquired and liabilities assumed at the acquisition date: Consideration transferred
Cash
$
6,298
Identifiable assets acquired and liabilities assumed Net working capital: Cash
63
Accounts receivable
3,158
Inventories
3,719
Prepaid expenses
141
Accounts payable and accrued liabilities Billings in excess of revenues
(3,720) (26)
Total net working capital
3,335
Property, plant and equipment
2,070
Long term debt
(767)
Future income tax asset
819
Intangible assets: Customer relationships
593
Order backlog
7
Non-compete agreement
157
$
6,214
Accounts receivable comprises gross contractual amounts of $3,158, which approximates fair value and management estimates to be fully collectible at the acquisition date. None of the fair values of the identifiable assets acquired and liabilities assumed were determined on a provisional basis. Goodwill was recognized as a result of the acquisition as follows:
Total consideration transferred
6,298
Less value of net identifiable assets
(6,214)
Goodwill
72
Flint
E n e r g y
S e r v i c es
L t d.
$
84
NOtes to the consolidated financial statements
December 31, 2010 and 2009 (in thousands of Canadian dollars except share data, unless otherwise specified)
The goodwill recorded is primarily an estimate of the expertise and experience of PSI’s workforce. None of the goodwill recognized is expected to be deductible for income tax purposes. Costs incurred by this acquisition are $106, which relate mainly to external legal fees and due diligence costs. These costs have been included in general and administrative costs in the consolidated statement of earnings.
(b) Stallion Heavy Haulers (“Stallion”) On November 22, 2010, the Company completed an acquisition to expand its oilfield services in the United States for $36,630 in cash consideration. The addition of 450 pieces of equipment and 170 personnel will make the Company a significant oilfield hauler in the U.S. shale basins. From the date of acquisition to December 31, 2010, Stallion contributed revenue of $4,345 and net earnings of $361. If the acquisition had occurred on January 1, 2010, management estimates that consolidated revenue would have been $1,814,210 and consolidated net earnings for the period would have been $33,425. In determining these amounts, management has assumed that the fair value adjustments that arose on the date of acquisition would have been the same if the acquisition had occurred on January 1, 2010. The aggregate consideration given and fair values of net assets acquired in the acquisition of Stallion described above are as follows: Consideration transferred Cash
$
36,630
Identifiable assets acquired and liabilities assumed Property, plant and equipment
37,523
Inventories
91
Intangible assets: Non-compete agreement
99
37,713
Value of net identifiable assets
37,713
Less consideration
(36,630)
Gain on business combination
$
1,083
The transaction resulted in a gain due to the vendor’s strategic decision to realign its core business. This decision along with the Company’s ability to close the transaction expeditiously allowed Flint to negotiate a bargain purchase. None of the fair values of the identifiable assets acquired and liabilities assumed were determined on a provisional basis. Costs incurred by this acquisition are $458, which relate mainly to external legal fees and due diligence costs. These costs have been included in general and administrative costs in the consolidated statement of earnings.
2 0 1 0
A n n ua l
Rep o r t
73
NOtes to the consolidated financial statements
December 31, 2010 and 2009 (in thousands of Canadian dollars except share data, unless otherwise specified)
4. Cash and Cash Equivalents 2010
As at December 31
$ 143,629
Cash
$
40,929
20,000
–
–
123,000
$ 163,629
$ 163,929
Cash equivalents – redeemable guaranteed investment certificate Cash equivalents – money market fund
2009
5. Inventories Inventories expensed in direct costs during the year ended December 31, 2010 were $118,929 (2009 – $100,023). Included in the cost of inventory are direct product costs, direct labour and an allocation of variable and fixed manufacturing overhead including amortization. Amortization expense on property, plant and equipment included in direct costs for the year ended December 31, 2010 was $1,595 (2009 – $1,320). In the year ended December 31, 2010 there were $256 (2009 – $1,000) of write-downs. During the years ended December 31, 2010 and 2009, there were no reversals of write-downs that were taken in previous periods. The carrying amounts of inventories at the reporting date were: 2010
As at December 31
$
Raw materials
8,200
2009
$
10,404
9,069
5,678
Finished goods
21,993
25,579
Supplies
11,987
8,287
Work in progress
–
Other
$ 51,249
1,200 $
51,148
The Company has provided a first charge over all assets under a General Security Agreement as security for the revolving operating loans and the term loans as outlined in note 12(a) to the consolidated financial statements.
74
Flint
E n e r g y
S e r v i c es
L t d.
NOtes to the consolidated financial statements
December 31, 2010 and 2009 (in thousands of Canadian dollars except share data, unless otherwise specified)
6. Property, Plant and Equipment Accumulated Net Book Cost Amortization Value
Land
$ 31,370
–
$ 31,370
Buildings and improvements
121,351
32,064
89,287
Vehicles and automotive equipment
229,790
82,312
147,478
Construction and other equipment
236,701
134,351
102,350
49,953
35,463
14,490
Office furniture and equipment
4,699
–
4,699
$ 673,864
$ 284,190
$ 389,674
Buildings and equipment under construction Balance, December 31, 2010
$
Cost
Land Buildings and improvements
$
35,245 116,727
Accumulated Amortization
$
– 28,856
Net Book Value
$
35,245 87,871
Vehicles and automotive equipment
200,697
72,387
128,310
Construction and other equipment
233,551
125,143
108,408
52,615
32,093
20,522
1,568
–
1,568
$ 640,403
$ 258,479
$ 381,924
Office furniture and equipment Buildings and equipment under construction Balance, December 31, 2009
During the year ended December 31, 2010, additions to property, plant and equipment included $666 (2009 – $393) of assets that were acquired by means of capital leases. Depreciation of equipment under capital leases of $2,531 (2009 – $1,190) is included in amortization on property, plant, and equipment expense. At December 31, 2010, vehicles, automotive, construction, and other equipment includes $18,112 (2009 – $19,771) of assets under capital lease and $8,151 (2009 – $6,496) of accumulated amortization for a net book value of $9,961 (2009 – $13,275).
7. Long-term Investment On March 26, 2010, the Company entered into an agreement for the establishment of a joint venture conditional on the achievement of future milestones with Sub-One Technology Inc. (“Sub-One”), a privately held entity from California, U.S. The Company will have a fifty-one percent interest in the new joint venture, which will provide hard surfacing treatment services, InnerArmor (R) Technology, to clients in the North American oil and gas industry, including the oil sands. The joint venture will be reported within the results of the Production Services segment. As at December 31, 2010, the joint venture had not been established, and therefore no assets, liabilities, earnings or cash flows were recorded in these consolidated financial statements. The Company has committed to providing approximately $2,500 in funds to the joint venture for it to begin operations. In addition to the establishment of this joint venture, the Company has also acquired preferred shares of Sub-One for an investment of $1,989. This investment has been classified as available for sale and is measured at cost as the equity instruments acquired do not have a quoted market price in an active market.
2 0 1 0
A n n ua l
Rep o r t
75
NOtes to the consolidated financial statements
December 31, 2010 and 2009 (in thousands of Canadian dollars except share data, unless otherwise specified)
8. Goodwill
Balance, December 31, 2009
Cost
$
â&#x20AC;&#x201C;
$
84
Additions (Note 3)
Balance, December 31, 2010
84
The current year addition of goodwill relates to the acquisition of PSI (note 3).
9. Intangible Assets Accumulated Net Book Cost Amortization Value
$ 10,831
Computer software Order backlog Non-compete agreement
(1,954)
$
(44)
8,877 549
7
(7)
â&#x20AC;&#x201C;
255
(67)
188
$ 11,686
Balance, December 31, 2010
$
593
Customer relationships
Cost
$
(2,072)
$
Accumulated Amortization
9,614
Net Book Value
Computer software
$
7,293
$
(95)
$
7,198
Balance, December 31, 2009
$
7,293
$
(95)
$
7,198
The computer software intangible asset relates to the costs of implementing various information systems. All other intangible assets relate to the acquisitions in the current year (note 3).
76
Flint
E n e r g y
S e r v i c es
L t d.
NOtes to the consolidated financial statements
December 31, 2010 and 2009 (in thousands of Canadian dollars except share data, unless otherwise specified)
10. Income Taxes (a) Components of Future Income Taxes The income tax effects of temporary differences that give rise to significant portions of the future income tax assets and liabilities are presented below: 2010
As at December 31
2009
Future income tax assets: Current: Contract retentions payable and accrued liabilities
$
92
$
–
Bad debt reserve
2,516 221
Billings in excess of revenue
1,014
1,101
Non-capital loss carried forward
1,273
2,787
Other Total current future income tax assets
556
243
2,935
6,868
97
5,957
Non-current: Tax value in excess of carrying value of property, plant and equipment Tax value in excess of carrying value of intangible assets
6,925
7,392
Share based payments
2,068
466
Non-capital loss carried forward
5,722
17,089
282
222
15,094
31,126
Contract retentions receivable
1,011
745
Deferred partnership income
5,716
4,388
20
–
6,747
5,133
23,054
41,142
–
123
Other Total non-current future income tax assets Future income tax liabilities: Current:
Other Total current future income tax liabilities Non-current: Carrying value of property, plant and equipment in excess of tax value Other Total non-current future income tax liabilities Net future income tax liability
23,054 $ 11,772
2 0 1 0
A n n ua l
41,265 $
8,404
Rep o r t
77
NOtes to the consolidated financial statements
December 31, 2010 and 2009 (in thousands of Canadian dollars except share data, unless otherwise specified)
In assessing whether the future income tax assets are realizable, management considers whether it is more likely than not that some portion or all of the future income tax assets will be realized. The ultimate realization of future income tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversals of future income tax liabilities, the character of the future income tax assets and available tax planning strategies in making this assessment. To the extent that management believes that the realization of future income tax assets does not meet the more likely than not realization criterion, a valuation allowance is recorded against future income tax assets. In 2010, a valuation allowance of $259 (2009 – $645) relating to non-capital loss carry forwards was recorded for one of the legal entities within the Maintenance Services segment. The amount of the future income tax assets considered realizable, however, could be reduced in the near term if estimates of future taxable income during the carry-forward period are reduced. At December 31, 2010, non-capital loss carry forwards of $25,947 (2009 – $78,739) are available to reduce taxable income of certain Canadian subsidiaries. These losses expire as follows:
2015
2026
$
1,501 1,167
2027
2,556
2028
5,392
2029
6,963
2030
8,368
Loss carry forwards
$ 25,947
Included in the table above is $3,489 (2009 – $3,168) of temporary differences related to non-capital loss carry forwards where no future benefit is expected to be realized. A valuation allowance has been recognized for these non-capital loss carry forwards as noted above. In addition to the non-capital loss carry forwards related to its Canadian subsidiaries disclosed in the table above, the Company’s U.S. subsidiary has $10,791 (2009 – $5,089) of U.S. state net operating loss carry forwards.
(b) Income Tax Rate Reconciliation Actual income tax expense differs from the “expected” income tax expense that would have been computed by applying the statutory income tax rate to income before taxes for the following reasons: As at December 31
Federal and provincial statutory income tax rates Expected income tax expense
2010
2009
28.0%
29.0%
$ 14,260
$ 19,802
Changes in income tax expense resulting from: Jurisdictional income tax rate differences Changes in tax rates impacting future income tax balances
373 1,583
Permanent differences
645
70
Valuation allowance
259
645
$ 17,925
$ 22,473
Actual income tax expense
78
166 2,595
Flint
E n e r g y
S e r v i c es
L t d.
NOtes to the consolidated financial statements
December 31, 2010 and 2009 (in thousands of Canadian dollars except share data, unless otherwise specified)
11. Bank Indebtedness One of the Company’s joint ventures has an operating credit facility that consists of a demand revolving credit facility subject to interest payments only with a maximum amount of $60,000, bearing interest at bank prime rate of 3.00% plus 0.85%. As at December 31, 2010, the Company’s share of the outstanding credit facility was $12,915 (2009 – $nil). Security for the credit facility is in the form of letters of credit issued by each of the joint venture’s shareholders in the amount of $15,000 each for a total of $30,000 (note 18b).
12. Long-term Debt 2010
Years ended December 31
2009
Term Loans Interest at 7.57% per annum, payable monthly in arrears, no principal payments, with the balance due April 30, 2011.
$
44,000
$
44,000
Stamping fee at 2.65% of BA Equivalent Note, payable at Note issuance including the discount, with the principal due on each Note term, all not to exceed April 30, 2011.
5,000
5,000
U.S. dollar term loans (U.S. $25,000), interest at 7.77% per annum, payable monthly in arrears, no principal payments, with the balance due April 30, 2011.
24,865
26,275
Interest at 7.57% per annum, payable monthly in arrears, principal payable in quarterly installments of $984 starting in 2008, with the balance due April 30, 2011.
9,188
13,125
Stamping fee at 2.65% of BA Equivalent Note, payable at Note issuance including the discount, with the principal due on each Note term, all not to exceed April 30, 2011.
2,188
3,125
Interest at 8.38% to 8.63% per annum depending upon certain financial ratios, payable monthly in arrears, principal payable in quarterly installments of $938 starting in 2008, with the balance due November 15, 2011.
8,750
12,500
Interest at Canadian Deposit Offering Rate (“CDOR”) plus 2.00% per annum, payable monthly in arrears, no principal payments, with the balance due December 1, 2011.
20,000
20,000
Interest at 6.17% per annum, payable monthly in arrears, principal payable in quarterly installments of $1,779 starting in 2011, with the balance due November 30, 2013.
35,000
35,000
Stamping fee at 2.00% of BA Equivalent Note, payable at Note issuance including the discount, with the principal due on each Note term in respect to the quarterly installments of $763 starting in 2011, all not to exceed November 30, 2013.
15,000
15,000
U.S. dollar term loans (U.S. $40,000), interest at 6.83% per annum, payable quarterly in arrears, principal payable in quarterly installments of U.S. $2,033, with the balance due November 30, 2013.
39,784
42,040
7,957
8,408
U.S. dollar term loans (U.S. $8,000), interest at 6.79% per annum, payable monthly in arrears, principal payable in quarterly installments of U.S. $407, with the balance due November 30, 2013.
211,732
2 0 1 0
A n n ua l
224,473
Rep o r t
79
NOtes to the consolidated financial statements
December 31, 2010 and 2009 (in thousands of Canadian dollars except share data, unless otherwise specified)
2010
2009
Finance contracts, secured by construction and automotive equipment with an aggregate carrying value of $1,374, interest varying from 0.00% to 6.35% per annum, with terms varying up to 60 months.
2,214
3,293
Mortgages payable, interest at HSBC Canada bank prime rate (3.00%) plus 0.25% per annum at December 31,2010, payment terms include interest only with no principal payments due. Mortgages are due for renewal in 2011 to 2014.
4,218
6,363
Liability under share-based compensation plan
5,930
838
Years ended December 31
Other Long-Term Debt
Other debts
2,403
1,541
226,497
236,508
Capital Leases Capital leases, secured by construction and automotive equipment with an aggregate carrying value of $198, interest varying from 0.05% to 13.01% per annum, with terms varying up to 60 months.
3,239
3,368
229,736
239,876
(444)
(744)
229,292
239,132
Less: Current portion
136,902
16,714
92,390
$ 222,418
Less: Finance costs (amortization of $300 (2009 – $1,318) is included in interest expense)
$
Interest expense for the year ended December 31, 2010 includes $16,142 (2009 – $18,345) of interest on long-term debt.
(a) Terms and Security On July 1, 2009 the Company entered into an amended and restated credit agreement with its lenders which extended the maturity date of its revolving operating loan to June 30, 2012. The Company may draw from the facility and make repayments at any time before the maturity date. As at December 31, 2010 and 2009, there was no outstanding balance on this facility. Maximum available credit under the Canadian and United States revolving operating loans is $137,000 Canadian and $15,000 U.S., respectively and $139,125 Canadian and $73,000 U.S. under the term loans. The Company has the ability to request the expansion of the borrowing capacity under the revolving operating loans to $250,000 Canadian and expand borrowing capacity to a maximum of $325,000 Canadian under the term loans with the approval of its lenders. The Company’s unused borrowing availability under the facility was $114,000 Canadian and $15,000 U.S. As of December 31, 2010, the Company issued $23,000 (2009 – $19,000) in letters of credit. The funds available under the revolving credit facility are reduced by any outstanding letters of credit. Interest on the revolving operating loans is at bank prime rate plus 0.50% to 1.75% for Canadian dollar loans, U.S. base rate loans and U.S. prime rate loans, at LIBOR or Bankers Acceptance rate plus 2.00% to 3.25% for Bankers Acceptances and LIBOR loans, and 1.75% to 2.75% for letters of credit depending upon certain financial ratios. There have been no changes to the Company’s banking covenants.
80
Flint
E n e r g y
S e r v i c es
L t d.
NOtes to the consolidated financial statements
December 31, 2010 and 2009 (in thousands of Canadian dollars except share data, unless otherwise specified)
The Company has provided a first charge over all assets under a General Security Agreement as security for the revolving operating loans and the term loans. The Company has also provided a general assignment of book debts, a first charge over all real property assets, pledged all shares of its subsidiaries and an assignment of insurance. The credit facilities require the Company to meet certain covenants. The Company was in compliance with these covenants at December 31, 2010 and 2009 which are presented as follows: As at December 31 Requirement
2010
2009
Working capital ratio
> 1.35
4.10
3.58
Senior funded debt to EBITDA
< 2.75
0.60
0.56
Fixed charge coverage
> 1.40
2.24
2.93
Funded debt to total capital
< 0.50
0.10
0.12
The Company has an option to, at any time, prepay in whole or in part the term loans included in long-term debt. If a prepayment is made for any portion of the term loans the Company shall pay an amount equivalent to an interest rate differential between the interest rate on the facility and the midpoint of bid-ask spread on Government bond rates plus 0.50% on the remaining principal. If a change of control occurs, without appropriate written notice to the Company’s principal lender, all outstanding advances shall become immediately due and payable. Mortgages payable balance of $4,218 (2009 – $6,363) represents the Company’s proportionate share of long-term debt of Flint Transfield Services Ltd., which bears interest at HSBC Canada prime rate. Mortgages payable are due for renewal in 2011 to 2014. Security for mortgages payable is in the form of residential properties of Flint Transfield Services Ltd. included in land and buildings with net book value of $5,142 (2009 – $8,030).
(b) Principal Payments are Due as Follows:
Capital Leases
Other Long-Term Debt
Total
2011
$ 1,195
$ 135,481
$ 136,676
2012
1,981
24,356
26,337
2013
52
58,143
58,195
2014
11
165
176
2015
–
19
19
Thereafter
–
–
–
$ 3,239
$ 218,164
$ 221,403
2 0 1 0
A n n ua l
Rep o r t
81
NOtes to the consolidated financial statements
December 31, 2010 and 2009 (in thousands of Canadian dollars except share data, unless otherwise specified)
13. Capital Stock (a) Issued Capital Stock: Authorized: Unlimited common shares Unlimited preferred shares Issued: Note
Balance, December 31, 2008
Common Shares
46,188,514
Amount
$
561,376
Shares issued in conjunction with: Exercised employee stock options
13(a)(i)
1,000
6
Transfer from contributed surplus for stock options exercised
13(a)(i)
–
2
Share repurchase via normal course issuer bid
13(a)(ii)
Balance, December 31, 2009
(688,300) 45,501,214
(8,366) $
553,018
Shares issued in conjunction with: 151,000
741
Exercised employee stock options
13(a)(i)
Transfer from contributed surplus for stock options exercised
13(a)(i)
–
256
45,652,214
$ 554,015
Balance, December 31, 2010 (i)
During the year ended December 31, 2010, the Company issued 151,000 (2009 – 1,000) common shares under the Company’s stock option plan at $4.91 (2009 – $5.71) per share for total proceeds of $ 741 (2009 – $6). In addition $256 (2009 – $2) was transferred from contributed surplus to share capital with respect to options exercised during the year that were part of the grants occurring since January 1, 2002, when the Company adopted the fair value method.
(ii) On February 26, 2008, the Company released details of the Normal Course Issuer Bid (“NCIB”) to purchase up to 2,379,689 of the Company’s common shares, representing 5% of its then issued and outstanding common shares. The NCIB commenced on February 29, 2008 and terminated on February 28, 2009.
On February 26, 2009 the Company received regulatory approval to make an additional NCIB to purchase up to 2,308,725 common shares, representing 5% of the total issued and outstanding common shares. The NCIB commenced on March 3, 2009 and terminated on March 2, 2010.
For the year ended December 31, 2009, the Company repurchased and cancelled 688,300 common shares pursuant to the Company’s NCIB for a total expenditure of $5,465 or $7.94 per share. As a result, the average carrying value of $8,366 was allocated as a reduction to share capital, and $2,901 was charged to contributed surplus during the period representing the consideration below stated value.
82
During the year ended December 31, 2010, the Company did not repurchase any common shares.
Flint
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NOtes to the consolidated financial statements
December 31, 2010 and 2009 (in thousands of Canadian dollars except share data, unless otherwise specified)
(b) Employee Stock Option Plan The Company has an incentive stock option plan for certain employees, officers and directors. Options issued under the plan vest at a rate of one third on the three subsequent award date anniversaries. All stock options must be exercised over specified periods not to exceed five years from the date granted. The number of shares reserved for issuance under the stock option plan shall not exceed 12% of the total number of issued and outstanding shares of the Company. At December 31, 2010, 2,663,075 (2009 – 2,449,315) common shares remained reserved for issuance under the stock option plan. The continuity of the Company’s outstanding and exercisable stock options for the years ended December 31, 2010 and 2009 is as follows: 2010
Years ended December 31
2009
Weighted Average Shares Exercise Price ($)
Options
Shares
Weighted Average Exercise Price ($)
2,888,356
17.77
2,353,228
22.12
Granted
449,000
11.47
820,000
4.91
Exercised
(151,000)
4.91
(1,000)
5.71
Forfeited
(502,773)
18.24
(283,872)
16.69
Outstanding at end of year
2,683,583
17.35
2,888,356
17.77
Options exercisable at end of year
1,619,550
22.85
1,576,961
23.33
Outstanding at beginning of year
The following table summarizes information about the stock options outstanding and exercisable at December 31, 2010: Exercise Price Ranges as at December 31, 2010
$ 2.50 – $11.99
Number Outstanding
Options Outstanding Remaining Weighted Average Life (years) Exercise Price ($)
1,047,250
3.5
7.50
$12.00 – $21.49
379,416
2.2
$21.50 – $30.99
1,236,917
0.6
20,000
0.7
2,683,583
2.0
$31.00 – $40.49
Options Exercisable Number Weighted Average Exercisable Exercise Price ($)
121,833
5.00
16.52
246,468
16.65
25.70
1,231,249
25.70
32.56
20,000
32.56
17.27
1,619,550
22.85
For the year ended December 31, 2010, the Company recognized $1,613 (2009 – $3,107) of compensation cost related to stock options. For the year ended December 31, 2010, the weighted average remaining contractual life of outstanding options was 2.0 years (2009 – 2.5 years), and the weighted average fair value per option granted was approximately $4.01 (2009 – $1.69). The fair value of common share options is estimated at the grant date using the Black-Scholes option-pricing model, with the following weighted-average assumptions: 2010
2009
Risk-free rate
1.61%
1.88%
Expected life
3.82 years
3.88 years
43.46%
41.71%
Expected volatility Expected dividends
$
–
2 0 1 0
A n n ua l
$
–
Rep o r t
83
NOtes to the consolidated financial statements
December 31, 2010 and 2009 (in thousands of Canadian dollars except share data, unless otherwise specified)
(c) Directors’ Deferred Share Unit Plan On March 18, 2008 the Company established a Directors’ Deferred Share Unit Plan (“DSU”) which became effective on May 19, 2009. Under the terms of the DSU, the portion of a director’s annual remuneration to be paid through units in the DSU is set at the beginning of the Company’s fiscal year (or, in the initial year of the plan) or on the date a director joins the Board in that fiscal year. The units vest on a per day basis such that the grant is fully vested on the last day of each fiscal year. Upon the resignation, termination, retirement or death, of a director (the “Termination Date”) the vested units are settled, at the Company’s option, either by the issuance of one common share per unit or by cash payment based on one common share of the Company per unit. The value of a unit in the DSU is equal to the volume weighted average trading price per common share of the Company on the Toronto Stock Exchange for the five consecutive trading days prior to the redemption date. The units accumulated under this plan have been recorded as a liability and included in accounts payable and accrued liabilities on the consolidated balance sheet based on the intrinsic value of the award. The change in the value of the units resulting from changes in the market price of the Company’s common shares is recognized in the consolidated statement of earnings each period. For the year ended December 31, 2010, the Company recorded $1,835 (2009 – $970) in director fee compensation relating to the DSU. This compensation cost has been included in share based compensation expense in the consolidated statement of earnings. The outstanding Directors’ Deferred Share Units are as follows: 2010
2009
122,475
–
Granted
48,107
122,475
Forfeited
(3,808)
–
Balance at beginning of year
(37,986)
Settled
128,788
Balance at end of year
– 122,475
(d) Restricted Share Unit Plan The Company established a Restricted Share Unit Plan (“RSU”) for certain officers, managers and employees of the Company effective March 10, 2009. The units under the RSU plan vest three years from the effective grant date and entitle the holder to receive a cash payment from the Company equal to the volume weighted average trading price per common share of the Company on the Toronto Stock Exchange for the five consecutive trading days prior to the vesting date. The units accumulated under this plan have been classified as a liability and included in long-term debt on the consolidated balance sheet based on the intrinsic value of the award. The change in the value of the units resulting from changes in the market price of the Company’s common shares is recognized in the consolidated statement of earnings each period. For the year ended December 31, 2010, the Company recorded $3,754 (2009 – $838) in compensation relating to the RSU. This compensation cost has been included in share based compensation expense in the consolidated statement of earnings. The weighted average remaining contractual life for the units outstanding under this plan is 1.6 years (2009 – 2.3 years).
84
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NOtes to the consolidated financial statements
December 31, 2010 and 2009 (in thousands of Canadian dollars except share data, unless otherwise specified)
The outstanding Restricted Share Units are as follows:
2010
2009
Balance at beginning of year
350,000
–
Granted
237,400
382,000
Forfeited Balance at end of year
(34,000)
(32,000)
553,400
350,000
(e) Performance Share Unit Plan The Company established a Performance Share Unit (“PSU”) Plan for certain executives (the “Participants”) of the Company effective January 1, 2010. PSU awards vest at the end of three years and are subject to the performance criteria approved by the Compensation Committee of the Board of Directors at the date of grant. In addition to the passage of time, the vesting of the awards is based on the extent to which the Company’s average return on capital employed, achieves or exceeds the specified performance levels over a three-year period. The number of units that will ultimately vest will be in the range of 20% to 200% of the original grant. The value of a PSU is equal to the volume weighted average trading price per common share of the Company on the Toronto Stock Exchange for the five consecutive trading days prior to the date of redemption. The PSUs will be settled in cash and have been classified as a liability and included in long-term debt on the consolidated balance sheet. The share-based compensation expense is recognized evenly over the vesting period, or, as applicable, over the period to the date an employee is eligible to retire, whichever is shorter. This compensation expense is adjusted based upon management’s assessment of performance against specified levels and the ultimate number of units expected to be issued. For the year ended December 31, 2010, the Company recorded $1,338 in compensation expense under the plan. Compensation cost for these awards has been included in share based compensation expense in the consolidated statement of earnings. The weighted average remaining contractual life for this plan is 2.0 years. The outstanding Performance Share Units are as follows:
2010
–
Balance at beginning of year Granted Balance at end of year
2009
–
221,000
–
221,000
2 0 1 0
A n n ua l
–
Rep o r t
85
NOtes to the consolidated financial statements
December 31, 2010 and 2009 (in thousands of Canadian dollars except share data, unless otherwise specified)
14. Contributed Surplus During the years ended December 31, 2010 and 2009, contributed surplus changed as follows: 2010
Years ended December 31
$ 23,021
Balance at beginning of year Employee stock option expense Stock options exercised Adjustment arising from shares purchased under a normal course issuer bid (Note 13(a)(ii))
$
17,015
1,613
3,107
(256)
(2)
–
2,901
$ 24,378
Balance at end of year
2009
$
23,021
15. Earnings Per Share The following table reconciles basic and diluted earnings per share: 2010
Years ended December 31
2009
Basic Net earnings
$
Weighted average number of common shares outstanding
45,594,986 $
Basic earnings per share
33,003
$
45,811
45,722,973
0.72
$
1.00
33,003
$
45,811
Diluted Net earnings
$
Weighted average number of common shares outstanding
45,594,986 393,442
309,449
45,988,428
46,032,422
Diluted effect of options Diltuted weighted number of common shares outstanding
$
Diluted earnings per share
45,722,973
0.72
$
1.00
Stock options outstanding with an exercise price greater than the market price of the Company’s common shares at December 31, 2010 were not recognized in the computation of diluted net earnings per common share. Accordingly, 1,273,417 (2009 – 2,067,606) stock options, with a weighted average exercise price of $25.72 (2009 – $22.89) per common share, were excluded from the computation of diluted net earnings per common share.
86
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NOtes to the consolidated financial statements
December 31, 2010 and 2009 (in thousands of Canadian dollars except share data, unless otherwise specified)
16. Investment in Joint Ventures The Company participates in three joint ventures and the consolidated financial statements include the Company’s proportionate share of the assets, liabilities, revenues, expenses, net earnings and cash flows of the following: (a) 50% interest in Flint Transfield Services Ltd. (“FT Services”), a joint venture with Transfield Services Limited (Canada) a subsidiary of a publicly traded Australian company. The joint venture provides operations, maintenance and asset management and project management services to the North American energy sector. (b) 49% interest in Mackenzie Valley Construction Ltd. (“MVC”), a joint venture with Gwich’in Development Corporation. The joint venture provides construction, oil and gas production and maintenance services in the Northwest Territories area. (c) 331/3% interest in S.R.P. North Ventures Ltd. (“SRP”). This joint venture provides a variety of logistical oilfield services in the Norman Wells, Northwest Territories area. The following table sets out the Company’s proportionate share of the assets, liabilities, revenues, expenses, net earnings and cash flows of these joint ventures. Included in expenses in the determination of net earnings of joint ventures are income taxes for those entities that are separately liable for the payment of taxes. 2010
Years ended December 31
2009
Balance sheets: $ 87,018
$ 41,723
Long-term assets
7,786
11,086
Current liabilities
72,520
36,125
5,445
3,687
Revenue
421,674
278,945
Direct costs and expenses
380,587
253,065
19,196
14,026
(752)
13,951
Current assets
Long-term liabilities Statements of earnings:
Net earnings Statements of cash flows: Cash provided by operating activities Cash used in investing activities Cash used in financing activities
$
1,963
(1,921)
(1,885)
$ (12,493)
Cash and cash equivalents as at December 31, 2010 includes $134 (2009 – $770), which is the Company’s proportionate share of its joint ventures’ cash balance and is restricted to the operations of those joint ventures.
2 0 1 0
A n n ua l
Rep o r t
87
NOtes to the consolidated financial statements
December 31, 2010 and 2009 (in thousands of Canadian dollars except share data, unless otherwise specified)
17. Related Party Transactions All transactions are provided in the normal course of business at exchange amounts agreed upon by the related parties. Related party transactions include transactions with parties that are related by equity investment, parties related by common directors and transactions with other private companies owned or controlled by officers or directors. Years ended December 31
Nature of Relationship
2010
2009
Expenses: Transportation and supply of materials reported in direct costs
(a)
Information system support reported in general and administrative expenses
(b)
134
990
Facility leases reported in general and administrative expenses
(c)
1,022
1,373
$
$
1,156
Accounts payable at end of year
–
$
–
257
2,620 $
12
Nature of relationship: (a) Related by common officers or directors (b) Related by a common director (c) Leases with private companies owned or controlled by an officer or senior management
18. Commitments and Contingencies Future minimum annual operating lease payments for construction equipment, vehicles, office equipment, and premises are as follows:
2011
2012
$
38,417 27,444
2013
21,240
2014
12,149
2015
8,868
Thereafter
6,478
$ 114,596
(a) The vehicle leases are at normal commercial terms. Following the end of the minimum lease terms, the Company has the option to rent the vehicles on a month-to-month basis or return them to the lessors. Under the commercial lease terms, the Company has provided the lessors with residual value guarantees. At December 31, 2010, the undiscounted maximum amount of potential future payments under these guarantees aggregate to $50,578 (2009 – $67,073). For the year ended December 31, 2010, the Company incurred $35,553 (2009 – $54,093) of operating lease payments. The Company does not expect these amounts to have a material impact on the financial position or the results of the Company in the future.
88
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NOtes to the consolidated financial statements
December 31, 2010 and 2009 (in thousands of Canadian dollars except share data, unless otherwise specified)
(b) A contingent liability has arisen as a result of the Company’s interests in Flint Transfield Services Ltd. (“FT Services”) joint venture. The full amount of FT Services operating credit facility line, amounting to $60,000 (2009 – $60,000), is secured by a letter of credit for a total of $30,000 (2009 – $30,000) that is jointly and severally guaranteed by the Company and by Transfield Services Limited (Canada). The extent to which an outflow of funds will be required is dependent on the future operations of the joint venture being more or less favorable than currently expected. The Company is not contingently liable for the liabilities of other partners in its joint ventures. (c) On January 29, 2010, a customer filed an action in the Court of Queen’s Bench of Alberta against a number of defendants, including the Company, alleging that the negligent provision of a pipe coating and insulation system, engineering services, design services and other work caused damage to the customer’s pipeline in Canada. The customer alleges that it has suffered damages in the amount of $85,000. While the Company was the construction contractor on the project and did construct the pipeline, it was constructed to a design specified and with materials supplied by others. The customer served the Statement of Claim against the Company in late January 2011, prior to the first anniversary of the filing of the claim. Although the claim has been served, the Plaintiff has advised that the Company is not required to file a Statement of Defence or to take any other steps at this time. Based on management’s current understanding of the facts of this claim management believes the Company has meritorious defenses to this action and as such does not believe that this litigation will materially affect the Company’s consolidated financial position or results of its operations. Accordingly, no provision for losses has been reflected in the accounts of the Company for this matter. The Company is also involved in various other claims and legal actions arising in the ordinary course of business. In the opinion of management, the ultimate disposition of these matters will not have a material adverse effect on the Company’s consolidated financial position, results of operations, or liquidity.
19. Capital Management The Company’s objective in managing capital is to maintain a cost-effective capital structure that supports its long-term growth strategy, maximizes operating flexibility and to provide returns to its shareholders. The Company defines capital that it manages as the aggregate of its shareholders’ equity, which is comprised of issued capital, contributed surplus, accumulated other comprehensive income (loss) and deficit. The Company manages its structure by establishing a capital structure which optimizes the cost of capital at acceptable risk. The Company makes adjustments for changes in economic conditions and the risk characteristics of the underlying assets and the Company’s working capital requirements. To maintain or adjust the capital structure, the Company, upon approval from its Board of Directors, may issue or repay long-term debt, issue new shares, or undertake other activities as deemed appropriate under the specific circumstances. The Board of Directors reviews and approves any material transaction out of the ordinary course of business, including proposals on acquisitions or other major investments or divestitures, as well as annual capital and operating budgets. The Company monitors debt leverage ratios as part of the management of liquidity and shareholders’ return and to sustain future development of the business. The Company has established financial objectives including maintaining a debt capitalization ratio that will not exceed 50% and a minimum cash flow to interest bearing debt of 16% for the year.
2 0 1 0
A n n ua l
Rep o r t
89
NOtes to the consolidated financial statements
December 31, 2010 and 2009 (in thousands of Canadian dollars except share data, unless otherwise specified)
Debt to total capitalization and cash flow to interest bearing debt ratios are non-GAAP measures which do not have a standardized meaning prescribed by GAAP and, therefore, may not be comparable to similar measures presented by other issuers. The Company defines these terms as follows: •
Debt to total capitalization is calculated as short-term and long-term debt (total debt) divided by total capitalization. Total capitalization is defined as the sum of total debt and all components of equity (share capital, contributed surplus, accumulated other comprehensive loss, and deficit), which is consistent with the definition within the Company’s Credit Agreement.
•
Cash flow to interest bearing debt, expressed as a percentage, is equal to cash flow divided by interest bearing debt. Cash flow is equal to funds provided by operations before changes in non-cash working capital. Interest bearing debt is equal to long-term debt including the current portion, which is consistent with definition within the Company’s Credit Agreement.
The objectives and strategies with respect to capital risk management are established on an annual basis and are monitored on a quarterly basis, and remained unchanged from the prior comparative period. These ratios are currently in the targeted range and provide access to capital at a reasonable cost. 2010
(in millions of Canadian dollars) Years ending December 31
2009
Components of Debt and Coverage Ratios $
97.9
$ 102.5
229.3
239.1
543.4
511.8
29.7%
31.8%
42.7%
42.9%
Funds provided by operations before changes in non-cash working capital Long-term debt (including current portion) Total shareholders’ equity Ratios Debt to total capitalization Cash flow to interest bearing debt
The Company is also subject to externally imposed capital requirements under its credit facilities and long-term debt agreements with its principal lenders that are measured on a quarterly basis. These covenants include, but are not limited to, incurring additional debt, transferring or selling assets, making investments including acquisitions or to pay dividends or redeem shares of capital stock. Other than the restrictive covenants contained within its debt agreements, neither the Company nor any of its subsidiaries are subject to externally imposed capital requirements. As at December 31, 2010, the Company was in compliance with all externally imposed capital requirements.
90
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NOtes to the consolidated financial statements
December 31, 2010 and 2009 (in thousands of Canadian dollars except share data, unless otherwise specified)
20. Financial Instruments and Risk Management (a) Financial Instruments – Classification The Company’s financial assets and liabilities are classified into the following categories:
Cash
Classification
Measurement
Held for trading
Fair value
Accounts receivable
Loans and receivables
Amortized cost
Revenue in excess of billings
Loans and receivables
Amortized cost
Other long-term assets
Loans and receivables
Amortized cost
Available for sale
Cost
Long-term investment Accounts payable and accrued liabilities
Other financial liabilities
Amortized cost
Long-term debt (including capital lease obligations)
Other financial liabilities
Amortized cost
Held for trading
Fair value
Derivative financial instruments
The Company has not classified any of its financial assets as held-to-maturity.
(b) Fair Value The fair value of financial assets and liabilities classified as loans and receivables and other financial liabilities (excluding long-term debt) approximate their carrying value due to the short-term nature of these financial instruments. The fair value of long-term debt as at December 31, 2010 was $236,961 (2009 – $250,325) as compared to its carrying value of $229,292 (2009 – $239,132) on the consolidated balance sheet. The fair value of the Company’s long-term debt was estimated based on discounted future cash flows using current rates for similar financial instruments subject to similar risks and maturities. The fair values of the Company’s cross-currency and interest rate swap agreements are based on appropriate price modeling commonly used by market participants to estimate fair value. The fair values of the Company’s interest rate swap agreements are estimated using discounted cash flow analysis with inputs of observable market data including future interest rates, implied volatilities and the credit risk of the Company or the counterparties as appropriate with resulting valuations periodically validated through third-party or counterparty quotes. The fair values of cross-currency swaps are estimated using discounted cash flow analysis with inputs of observable market data including foreign currency exchange rates, implied volatilities, interest rates and the credit risk of the Company or the counterparties as appropriate, with resulting valuations periodically validated through third-party or counterparty quotes. The Company has segregated all financial assets and liabilities that are measured at fair value into the most appropriate level within the fair value hierarchy based on the inputs used to determine the fair value at the measurement date. Cash and cash equivalents are valued using level 1 inputs (quoted market prices); whereas the Company’s derivative financial instruments are valued using level 2 (observable) inputs. For the year ended December 31, 2010, the Company has not measured the fair value of any financial instruments using level 3 (significant unobservable) inputs.
2 0 1 0
A n n ua l
Rep o r t
91
NOtes to the consolidated financial statements
December 31, 2010 and 2009 (in thousands of Canadian dollars except share data, unless otherwise specified)
Fair values of financial instruments are determined by reference to quoted bid or asking price, as appropriate, in active markets at period-end dates. In the absence of an active market, the Corporation determines fair value by using valuation techniques that refer to observable market data or estimated market prices. These include comparisons with similar instruments that have observable market prices and other valuation techniques used by market participants. Fair values determined using valuation models require the use of assumptions about the amount and timing of estimated future cash flows and discount rates. Fair value estimates are made at a specific point in time, based on relevant market information and information about the financial instruments. These estimates are subjective in nature and involve uncertainties and matters of significant judgment and, therefore, cannot be determined with precision. It is possible that the assumptions used in establishing fair value amounts will differ from future outcomes and the impact of such variations could be material. The fair values of derivative financial instruments are shown below:
Non-Current Liability 2010
2009
Interest rate swap contracts: $
â&#x20AC;&#x192; Canadian dollar interest rate swaps
â&#x20AC;&#x192; Cross-currency interest rate swap
113 1,146
$ 1,259
Total
$
425 862
$ 1,287
(c) Guarantees The Company indemnifies its directors, officers and employees against claims reasonably incurred and resulting from the performance of their services to the Company, and maintains liability insurance for its directors and officers as well as those of its subsidiaries. The Company is unable to make a reasonable estimate of the maximum potential amount it would be required to pay counterparties. The amount also depends on the outcome of future events and conditions, which cannot be predicted. Historically, the Company has not made any significant payments under this indemnification and no amounts have been accrued in the consolidated financial statements.
(d) Risk Management The risks associated with the Companyâ&#x20AC;&#x2122;s financial instruments and policies for managing these risks are detailed below. (i) Credit Risk
Credit risk is the financial loss to the Company if a customer or counterparty to a financial instrument fails to meet its contractual obligations.
In the normal course of business, the Company is exposed to credit risk through its accounts receivable and revenues in excess of billings from its customers, which operate primarily in the oil and natural gas industry in Canada and the United States. Credit risk for trade and other accounts receivables, and revenues in excess of billings is managed through the establishment of credit policies and limits, which are applied in the selection of counterparties, and through ongoing management review of all receivable balances past due with the objective of identifying matters that could potentially delay the collection of funds at an early stage. The Company carries adequate provisions for expected losses arising from credit risk associated with all financial assets.
92
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NOtes to the consolidated financial statements
December 31, 2010 and 2009 (in thousands of Canadian dollars except share data, unless otherwise specified)
At December 31, 2010, the Company had one customer who represented 10% (2009 – two customers) or more of accounts receivable and revenues in excess of billings. One customer accounts for 40.5% (2009 – 25.7%) of the Company’s accounts receivable, and two customers account for 12.6% (2009 – 32.6%) of the Company’s revenue in excess of billings. There are no other single customers with a balance greater than 10% of the total of accounts receivable and revenue in excess of billings. Payment terms are generally net 30 days. At December 31, 2010 and 2009 the Company’s maximum exposure to credit risk for trade accounts receivable is as follows: 2010
Years ended December 31
2009
$ 183,814
$ 171,274
Past due 1 – 30 days
42,314
33,391
Past due 31 – 60 days
12,877
15,807
Past due 61 – 90 days
6,304
6,896
Not past due
Past due > 91 days Subtotal
6,178
5,918
251,487
233,286
Allowance for doubtful accounts
(2,264)
(3,795)
Holdbacks receivable
4,670
11,621
4,259
3,184
$ 258,152
$ 244,296
Other receivables
At December 31, 2010, the Company has recorded an allowance for doubtful accounts of $2,264 (2009 – $3,795), of which 100% (2009 – 100%) relates to amounts greater than 91 days past due. The Company reviews its accounts receivable amounts regularly and amounts are written down to their expected realizable value when outstanding amounts are determined not to be fully collectible. Bad debt is charged to net earnings in the period that the account is determined to be doubtful. Estimates of the allowance for doubtful accounts are determined on a customer-bycustomer evaluation of collectability at each reporting date taking into consideration the following factors: the length of time the receivable has been outstanding, specific knowledge of each customer’s financial condition and historical experience. The change in the allowance for doubtful accounts specific to trade receivables during the period is as follows: 2010
Years ended December 31
Allowance, beginning of period
$
3,795
$
(1,457)
Provisions and revisions $
2,264
7,093 (3,058)
(74)
Foreign exchange translation adjustments Allowance, end of period
2009
(240) $
3,795
The Company is exposed to limited credit risk on its cash and cash equivalents as these are primarily made up of deposits and short term investments with large, reputable Canadian chartered banks. Credit risk on derivative financial instruments arises from the possibility that the counterparties to the agreements may default on their respective obligations under the agreements. This credit risk only arises in instances where these agreements have positive fair value for the Company.
2 0 1 0
A n n ua l
Rep o r t
93
NOtes to the consolidated financial statements
December 31, 2010 and 2009 (in thousands of Canadian dollars except share data, unless otherwise specified)
(ii) Liquidity Risk
Liquidity risk is the risk that the Company will encounter difficulty in meeting obligations associated with financial liabilities when they come due.
The contractual undiscounted cash flows payable with respect to financial liabilities as at the balance sheet date are as follows: Carrying Contractual As at December 31, 2010 Amount Cash Flows
1 Year More Than or Less 1 – 3 Years 4 – 5 Years 5 Years
Non-derivative financial liabilities
$ 221,403 $ 236,373 $ 145,656 $ 90,518 $
Long-term debt
Accounts payable and accrued liabilities
159,501
159,501
159,501
199 $
–
–
–
–
12,915
12,915
12,915
–
–
–
Other debts
2,403
2,403
–
2,403
–
–
Derivative financial liabilities Interest rate swaps
1,259 1,259
113
1,146
–
–
199 $
–
Bank indebtedness
$ 397,481 $ 412,451 $ 318,185 $ 94,067 $
As at December 31, 2009
Carrying Contractual Amount Cash Flows
1 Year or Less 1 – 3 Years 4 – 5 Years
More Than 5 Years
Non-derivative financial liabilities $ 237,497 $ 251,963 $ 17,649 $ 171,117 $ 63,197 $
Long-term debt Accounts payable and accrued liabilities Other debts
–
160,701
160,701
160,701
–
–
–
1,541
1,541
–
1,541
–
–
1,287
–
425
862
–
Derivative financial liabilities Interest rate swaps
1,287
$ 401,026 $ 415,492 $ 178,350 $ 173,083 $ 64,059 $
–
The Company manages its liquidity risk through the management of its capital structure and financial leverage, as outlined in note 19. In addition, the Company manages liquidity risk by monitoring forecasted and actual cash flows, minimizing reliance on any single source of credit, maintaining sufficient undrawn committed credit facilities and managing the maturity profiles of financial assets and financial liabilities to minimize refinancing risk.
As at December 31, 2010, the Company had cash and cash equivalent balances available of $163,629 (2009 – $163,929) and available undrawn committed bank borrowing facilities of $114,000 Canadian, and $15,000 U.S. (2009 – $118,000 Canadian, $15,000 U.S.).
The Company is subject to restrictive covenants under its banking agreements with its principal lenders related to its credit facilities that are measured on a quarterly basis. These covenants include, but are not limited to, a working capital ratio, debt to EBITDA ratio, fixed charge coverage ratio, and debt to total capitalization ratio. Failure to meet the terms of one or more of these covenants may constitute a default, potentially resulting in an acceleration of the repayment of the Company’s debt obligations by the Company’s lenders. As at December 31, 2010, the Company was in compliance with all covenants under this agreement.
94
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E n e r g y
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L t d.
NOtes to the consolidated financial statements
December 31, 2010 and 2009 (in thousands of Canadian dollars except share data, unless otherwise specified)
The Company has provided a first charge over all assets under a General Security Agreement as security for the revolving operating loans and the term loans. The Company has also provided a general assignment of book debts, a first charge over all real property assets, pledged all shares of its subsidiaries and an assignment of insurance. In certain circumstances, leasing companies have finance contracts which take precedence over the General Security Agreement with the financial institutions. Waivers have been placed as required in these situations.
(iii) Market Risk
Foreign Currency Exchange Risk
Foreign exchange risk refers to the risk that the value of financial instruments or cash flows associated with the instruments will fluctuate due to changes in foreign exchange rates.
The Company has foreign currency exchange risk that arises from its long-term debt of which a portion is in the form of U.S. dollar denominated credit facilities.
The Company manages its exposure to foreign exchange transaction exposure by periodically using cross-currency swap agreements and foreign currency forward contracts. These derivative financial instruments are not designated as hedges for accounting purposes and consist of the following: •
The foreign exchange forward contracts are used to primarily fix the Company’s exposure on U.S. dollar exchange rate changes on anticipated repayments of loans to/from the Company’s foreign operations. As at December 31, 2010 and 2009 the Company did not have any outstanding forward contracts.
•
The cross currency swap agreement was entered into by the Company to manage its exposure to changes in the U.S. to Canadian Dollar exchange rate with respect to a U.S. Dollar term loan in the amount of U.S. $8,000. The cross currency swap manages the foreign exchange risk for both the principal balance due on November 30, 2013 as well as the monthly interest payments from the issue date to the maturity date. In conjunction with the cross-currency swap agreement, the Company also entered into a U.S. Dollar interest rate swap and a Canadian Dollar interest rate swap. These derivative financial instruments were not designated as hedges for accounting purposes. At December 31, 2010 the notional principal amount of the cross-currency swap was U.S. $8,000 and Canadian $9,124.
A portion of the Company’s accounts receivable and accounts payable and accrued liabilities is denominated in U.S. dollars; however, due to their short-term nature, there is no significant market risk arising from fluctuations in foreign exchange rates.
In 2010, the Company had an unrealized foreign exchange gain (loss) of $451 (2009 – $1,336) on long-term debt recorded in interest expense.
As at December 31, 2010, holding all other variables constant, a $0.01 increase (decrease) in exchange rates of the Canadian dollar against the U.S. dollar would decrease (increase) net equity and net earnings by approximately $27 (2009 – $25). Holding all other variables constant, a 100 basis point increase (decrease) in exchange rates in the Canadian to the U.S. dollar related to the cross-currency swap would increase (decrease) net earnings and increase (decrease) net equity by approximately $89 (2009 – $91).
2 0 1 0
A n n ua l
Rep o r t
95
NOtes to the consolidated financial statements
December 31, 2010 and 2009 (in thousands of Canadian dollars except share data, unless otherwise specified)
The following table summarizes the notional amounts and interest rates of the Company’s interest rate swaps and cross-currency interest rate swaps: Maturity
Notional Amount Receive Rate
Notional Amount Pay Rate
CDN dollar interest rate swap
30-Apr-11
$5,000 CDN
90/CDOR
$5,000 CDN
7.57%
CDN dollar interest rate swap
30-Apr-11
$5,000 CDN
90/CDOR
$5,000 CDN
7.57%
Cross-currency swap
29-Nov-13
$8,000 USD
6.79%
$9,124 CDN
6.95%
In 2010, the Company had an unrealized (gain) loss of ($28) (2009 – $579) on derivative financial instruments recorded in interest expense.
Interest Rate Risk
Interest rate risk refers to the risk that the value of a financial instrument or cash flows associated with the instrument will fluctuate due to changes in market interest rates.
The Company’s interest rate arises from long-term borrowings issued at fixed rates that create fair value interest rate risk and variable rate borrowings that create cash flow interest rate risk. Capital leases all bear interest at fixed rates. Drawings on the demand credit facilities bear interest at floating rates.
The Company regularly reviews the mix of floating and fixed rate debt for consistency with its financing objectives. In addition, the Company’s cash equivalents are invested in short-term interest bearing assets. The Company manages its interest rate risk exposure by balancing its portfolio of fixed and floating rate debt; periodically using derivative instruments to achieve the desired proportion of fixed to floating-rate debt; and by managing the term to maturity of its debt portfolio.
The Company has entered into two Canadian Dollar interest rate swaps with the net effect of economically converting the floating 90 day Canadian Deposit Offering Rate payable on Bankers Acceptance Equivalent Note into a fixed rate of 7.57% until the related long-term debt matures on April 30, 2011. In conjunction with the cross-currency swap agreement discussed above, the Company also entered into a U.S. Dollar interest rate swap and a Canadian Dollar interest rate swap with the net effect of economically converting the 6.79% rate payable on the U.S. Dollar term loan into a fixed rate of 6.95% for the duration that the U.S. term loan is outstanding. These derivative financial instruments were not designated as a hedge for accounting purposes.
As at December 31, 2010, holding all other variables constant, a 100 basis point increase (decrease) to Canadian interest rates would impact the fair value of the interest rate swaps by $207 (2009 – $378) with this change in fair value being recorded in net earnings. As at December 31, 2010, holding all other variables constant, a 100 basis point increase (decrease) to U.S. interest rates would impact the fair value of the interest rate swaps by $174 (2009 – $263) with this change in fair value being recorded in net earnings. As at December 31, 2010, holding all other variables constant, a 100 basis point increase (decrease) of Canadian to U.S. interest rate volatility would impact the fair value of the interest rate swaps by $nil (2009 – $nil) with this change in fair value being recorded in net income.
As at December 31, 2010, holding all other variables constant, a 100 basis point increase (decrease) to interest rates on floating rate debt would increase (decrease) net earnings and net equity by $593 (2009 – $495).
96
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E n e r g y
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L t d.
NOtes to the consolidated financial statements
December 31, 2010 and 2009 (in thousands of Canadian dollars except share data, unless otherwise specified)
21. Employee Future Benefits The Company has a defined contribution registered retirement savings plan for its employees. The Company matches voluntary contributions made by employees to the registered retirement savings plan to a maximum of 5% of wages for each employee. The Company made contributions of $14,585 during the year ended December 31, 2010 (2009 – $17,063).
22. Changes in Non-Cash Balances Relating to Operations 2010
Years ended December 31
Accounts receivable
$ (13,342)
2009
$
99,801
Revenue in excess of billings
5,000
104,072
Inventories
1,805
16,152
(11,542)
4,716
(2,658)
(54)
Income taxes receivable Prepaids and other current assets
(240)
–
Accounts payable and accrued liabilities
13,961
(64,701)
Billings in excess of revenue
(1,459)
(2,687)
Income taxes payable
3,400
(3,241)
(5,075)
$ 154,058
Other assets
$
23. Segmented Disclosure The Company is operating within four reportable business segments, each of which is a distinct business unit that offers different products and services within the oil and natural gas industry. These reportable business segments include Production Services, Facility Infrastructure, Oilfield Services, and Maintenance Services. •
The Production Services segment focuses on midstream oil and gas field production services. These services encompass: fabrication, construction and maintenance of production facilities, mid-inch pipelines, production equipment, and mid-sized construction management with the inspection repair and refurbishing of production tubing, drill pipe, sucker rods, casing, small diameter pipelines and polyethylene pipe and liners.
•
The Facility Infrastructure segment, which includes oil sands construction activities, provides construction management, modular fabrication, field construction services on major construction projects primarily in Edmonton and Fort McMurray, Alberta.
•
The Oilfield Services segment provides drill rig and service rig moving; module, equipment and specialty hauling; fluid handling, pressure and vacuum services, industrial and chemical cleaning; and coiled tubing and flush-by services.
•
The Maintenance Services segment provides oil and gas production and maintenance, construction, logistical oilfield services, asset management and project management services to the North American energy sector. The segment consists of three joint ventures: FT Services, Mackenzie Valley Construction, and SRP North Ventures.
2 0 1 0
A n n ua l
Rep o r t
97
NOtes to the consolidated financial statements
December 31, 2010 and 2009 (in thousands of Canadian dollars except share data, unless otherwise specified)
The Company allocates resources based on revenue and evaluates performance of reporting segments based on earnings before interest, taxes, depreciation, amortization, impairment charge, and share-based compensation which follows the organization, management and reporting structure of the Company. The accounting policies for each of these business segments are the same as those described in the summary of significant accounting policies and practices (note 1). Corporate costs, depending on their nature, are allocated based on a percentage of the segments revenue to total revenue or asset utilization to total asset utilization. Under a new allocation method adopted in 2010, equipment costs and capital expenditures are now allocated based on utilization of property, plant and equipment rather than revenue. The comparative results have been restated to conform to the new basis of segment presentation.
(a) Reportable Segments Selected financial information for each reportable business segment is as follows: (in thousands of dollars) Production Facility Oilfield Maintenance Year ended December 31, 2010 Services Infrastructure Services Services Total
$ 788,355
Revenue
$ 229,182
$ 421,675 $ 1,794,167
(4,415)
(61)
(8,351)
–
(12,827)
783,940
354,894
220,831
421,675
1,781,340
EBITDA (1)
58,394
38,928
15,315
18,710
131,347
Amortization on property, plant and equipment
28,666
5,188
22,353
1,688
57,895
Capital expenditures
21,019
3,215
15,315
1,086
40,635
84
–
–
–
84
547,572
78,746
211,039
146,265
983,622
Inter-segment revenue Net external revenue
Goodwill Total assets
(in thousands of dollars) Year ended December 31, 2009
Revenue
Production Facility Services Infrastructure
Oilfield Maintenance Services Services
Total
$ 799,792
$ 595,720
$ 215,374
(4,448)
(6)
(8,703)
(1)
(13,158)
795,344
595,714
206,671
278,807
1,876,536
45,620
70,619
16,477
16,512
149,228
Amortization on property, plant and equipment 27,254 7,154
22,721
1,846
58,975
Inter-segment revenue Net external revenue EBITDA (1)
Capital expenditures Total assets (1)
9 8
$ 354,955
$ 278,808 $ 1,889,694
12,207
4,973
8,884
2,068
28,132
454,017
186,024
240,433
80,994
961,468
In addition to providing earnings measures in accordance with GAAP, the Company presents EBITDA as a supplemental earnings measure as it is used by the chief operating decision makers of the Company to measure reporting segment profitability. EBITDA is equal to earnings before interest, taxes, depreciation, amortization, impairment of intangibles and goodwill, share based compensation. Management uses EBITDA to establish performance benchmarks for incentive compensation for employees and to evaluate the performance of its reporting segments. EBITDA is a non-GAAP financial measure that does not have any standardized meaning prescribed by other issuers.
Flint
E n e r g y
S e r v i c es
L t d.
NOtes to the consolidated financial statements
December 31, 2010 and 2009 (in thousands of Canadian dollars except share data, unless otherwise specified)
Revenue from the Company’s two largest customers accounted for approximately 26.1% and 11.6% of total consolidated revenues for the year ended December 31, 2010 (2009 – 22.9% and 21.0%). Both the Production Services and Facility Infrastructure reporting segments performed work for the Company’s two largest customers while the Maintenance Services segment performed work for the Company’s largest customer. The Facility Infrastructure segment earned the majority of the revenue from both of the Company’s largest customers.
(b) Geographic Segments The Company’s operations are carried on in the following geographic locations: Year Ended Dember 31, 2010 Canada United States Total
$ 1,470,650
$ 310,690
$ 1,781,340
Property, plant and equipment
300,646
89,028
389,674
Total assets
852,323
131,299
983,622
Revenue
Year ended December 31, 2009
Revenue
$ 1,563,554
$ 312,982
$ 1,876,536
Property, plant and equipment
330,241
51,683
381,924
Total assets
833,150
128,318
961,468
(c) Reconciliation of EBITDA Years ended December 31
Net earnings Amortization on property, plant and equipment
2010
$ 33,003
2009
$
45,811
57,895
58,975
Amortization on intangible assets
2,008
95
Share based compensation expense
8,540
4,915
Interest expense, net of interest income
11,976
16,959
Income tax expense
17,925
22,473
EBITDA
$ 131,347
$
149,228
24. Comparative Information Certain comparative figures have been reclassified to conform to the current year presentation.
2 0 1 0
A n n ua l
Rep o r t
99
FIve-Year Review
2010
(C$millions except as noted)
2009
2008
2007
2006
Revenue
Production Services
$
783.9
$
795.3
Facility Infrastructure
354.9
595.7
585.5
425.8
410.9
Oilfield Services
220.8
206.7
278.8
225.7
88.9
Maintenance Services
421.7
278.8
303.4
57.7
4.1
Total
$ 1,781.3
$ 1,876.5
$ 2,314.6
$ 1,816.3
$ 1,440.0
Direct Costs
$ 1,504.7
$ 1,578.4
$ 1,948.4
$ 1,476.0
$ 1,168.2
Expenses General and administrative 148.3 Interest 12.0 Impairment charge
151.6 17.0
166.2 19.9 442.5
162.7 29.6
125.1 18.1
76.3
23.1
37.7
78.3
412.2
131.3 7.4%
149.2 8.0%
201.7 8.7%
177.6 9.8%
146.7 10.2%
Net Earnings (Before Impairment Charge)
33.0
45.8
74.7
53.1
41.6
Net Earnings
33.0
45.8
(341.4)
53.1
41.6
45,595 45,988
45,723 46,032
47,447 47,447
47,380 47,883
37,958 38,811
Capital Expenditures EBITDA EBITDA margin
Weighted Average Shares O/S (000s) Basic Fully diluted
$ 1,146.9
$ 1,107.1
$
936.1
EPS Basic (Before Impairment Charge)
$
0.72
$
1.00
$
1.57
$
1.12
$
1.09
EPS fully diluted
$
0.72
$
1.00
$
1.57
$
1.11
$
1.07
EPS Basic
$
0.72
$
1.00
$
(7.20)
$
1.12
$
1.09
EPS fully diluted
$
0.72
$
1.00
$
(7.20)
$
1.11
$
1.07
Share Price
High
$
19.11
$
14.11
$
25.78
$
30.69
$
34.66
Low
$
9.67
$
4.16
$
4.75
$
17.45
$
20.50
Commodity Prices (Annual Average)
Crude oil prices (WTI US$/bbl)
$
78.93
$
61.11
$
99.13
$
72.22
$
66.01
(NYMEX, US$/mmbtu)
$
4.41
$
4.16
$
9.16
$
7.11
$
7.14
Wells Drilled Canada U.S.
12,110 51,883
Natural gas prices
8,360 34,595
16,865 57,129
18,540 52,497
23,241 52,312
Sources: Oil and gas prices: Nickles Energy; Canadian wells rig released: Nickles Energy; U.S. wells drilled: Spears & Associates
10 0 Flint
E n e r g y
S e r v i c es
L t d.
Corporate Information
Directors
Officers
Bankers
Stuart O’Connor Chairman of the Board Flint Energy Services Ltd. President Timber Ridge Capital Ltd. Alberta, Canada
W. J. (Bill) Lingard President and Chief Executive Officer
Bank of Montreal
C. Douglas Annable President CD Consulting Inc. Former President Energy and Mining Division AMEC Americas Limited Alberta, Canada John Bates President Flint Resources Company, LLC Oklahoma, U.S.A. T. D. (Terry) Freeman Managing Director Northern Plains Capital Alberta, Canada
Designed and produced by Merlin Edge Inc. Printed in Canada
Philip C. Lachambre President PCML Consulting Inc. Former Executive Vice President and Chief Financial Officer Syncrude Canada Ltd. Alberta, Canada W. J. (Bill) Lingard President and Chief Executive Officer Flint Energy Services Ltd. Alberta, Canada Ian Reid Vice Chair The Churchill Corporation Former President Finning (Canada) Alberta, Canada Roger Thomas Chairman, Maxxam Analytics International Corporation Former Executive Vice President North America, Nexen Inc. Alberta, Canada
Paul M. Boechler Executive Vice President and Chief Financial Officer
Auditors KPMG LLP
Legal Counsel Bennett Jones LLP
Keith Lambert President Canadian Operations Bryce Satter President Flint Energy Services Inc. (U.S.A.) Wayne Shaw President North American Services Shawn Carry Senior Vice President Oilfield Services Glen Greenshields Senior Vice President Production Services Steve Russom Senior Vice President Process Equipment Ray Sandhu Senior Vice President Finance and IT Neil Wotton Senior Vice President Facility Infrastructure Terry Densmore Vice President Environmental, Health and Safety Bob Henderson Vice President Human Resources and Communications Joel Jarding Vice President Business Development
Transfer Agent and Registrar Computershare Trust Company of Canada 600, 530–8th Ave. S.W. Calgary, Alberta, Canada T2P 3S8 Tel: 1-888-267-6555 Email: caregistryinfo@computershare.com www.computershare.com
Stock Exchange Listing Toronto Stock Exchange (TSX) Common Shares – FES
Corporate Head Office 700, 300–5th Ave. S.W. Calgary, Alberta, Canada T2P 3C4 Tel: 403-218-7100 Toll Free: 1-877-215-5499 Fax: 403-215-5445 www.flintenergy.com
Notice of Annual General Meeting Flint Energy Services Ltd. Annual Meeting will be held on May 5, 2011 at 2:30 pm (MDT) at the Metropolitan Centre, Main Floor, 333 Fourth Avenue S.W., Calgary, Alberta. Shareholders and others who are interested in an update on the Company are encouraged to attend. Shareholders unable to attend are asked to sign and return the Form of Proxy mailed with the Annual Report.
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