10 Nov Ensign Energy Services Reports 2008 Third Quarter Results
CALGARY, Nov. 10 /CNW/ –
Overview
Ensign Energy Services Inc. (the “Company”) reports net income of $72.1
million ($0.47 per common share) for the third quarter of 2008 compared with
net income of $49.7 million ($0.33 per common share) for the third quarter of
2007, an increase of 45 percent. For the nine months ended September 30, 2008,
net income totaled $186.1 million ($1.22 per common share), an increase of
five percent over net income of $177.2 million ($1.16 per common share)
recorded in the first nine months of 2007. Funds from operations for the three
months ended September 30, 2008 totaled $90.5 million ($0.59 per common share)
and represents a 70 percent increase over funds from operations of $53.3
million ($0.35 per common share) recorded in the third quarter of 2007. For
the nine months ended September 30, 2008, funds from operations totaled $297.2
million ($1.94 per common share), an increase of 41 percent over the
comparable period of 2007.
The comparability of net income on a period-over-period basis is impacted
by stock-based compensation expense, which fluctuates based on changes in the
price of the Company’s common shares. The Company reports adjusted net income,
which eliminates the tax-effected impact of stock-based compensation expense,
of $61.0 million ($0.40 per common share) for the third quarter of 2008
compared with adjusted net income of $50.2 million ($0.33 per common share)
for the third quarter of 2007, an increase of 22 percent. Adjusted net income
for the nine-month period ended September 30, 2008 was $192.9 million ($1.26
per common share), an increase of six percent over adjusted net income of
$182.2 million ($1.20 per common share) recorded in the nine months ended
September 30, 2007.
Entering 2008, the outlook for the Company’s fiscal 2008 results was
diminished by the uncertain short-term prospects of the Canadian oilfield
services market. At the time, the 2008 outlook for the Canadian market was
negatively impacted by an over-supply of equipment in Canada, concern over
weak natural gas prices and the negative impact a strong Canadian dollar may
have on the cash flows of the Company’s customers. While these factors
contributed to a weak first quarter for the Company, gradual market
improvements resulted in stronger than anticipated second quarter results (at
which point the Company was the most active driller in the Western Canada
Sedimentary Basin (“WCSB”) on a metres drilled basis), and culminated in third
quarter funds from operations that exceeded the same period of 2007 by 70
percent. Favorable natural gas and crude oil commodity prices supported a
recovery in Canadian oilfield services activity in the third quarter of 2008,
while the United States oilfield services division, with its expanded
Automated Drill Rig (ADR(TM)) fleet, captured growing demand for
technologically-advanced equipment in the service-intensive resource plays of
the Rocky Mountain region of the United States. Internationally, the Company
achieved an increase in operating activity levels in the third quarter of 2008
compared with the third quarter of 2007 as repositioned equipment capitalized
on strong crude oil commodity prices and the resultant increase in demand for
the oilfield services provided by the Company.
The positive results generated by the Company in the first nine months of
2008, a period of significant market uncertainty and volatile commodity
prices, are owed to the strategic decisions and investments made by the
Company in recent years to diversify its geographic footprint and leverage its
existing operational bases in the United States and internationally; to
maintain strict cost discipline across all of its business lines; and, to
remain committed to developing technologies that improve the efficiency and
safety of its equipment. The Company’s proven track record during uncertain
times, and its strong balance sheet, will serve the Company well as it faces
the unprecedented events shocking the global economy in the fourth quarter of
2008.
————————————————————————-
FINANCIAL AND OPERATING HIGHLIGHTS
($ thousands, except per share data and operating information)
————————————————————————-
Three months ended Nine months ended
September 30, 2008 September 30, 2008
————————————————————————-
% %
2008 2007 change 2008 2007 change
————————————————————————-
Revenue 435,186 383,316 14 1,245,144 1,189,340 5
————————————————————————-
EBITDA(1) 121,785 103,519 18 383,775 359,624 7
EBITDA per
share(1)
Basic $ 0.80 $ 0.68 18 $ 2.51 $ 2.36 6
Diluted $ 0.79 $ 0.67 18 $ 2.48 $ 2.31 7
————————————————————————-
Adjusted net
income(2) 61,025 50,157 22 192,926 182,227 6
Adjusted net
income per
share(2)
Basic $ 0.40 $ 0.33 21 $ 1.26 $ 1.20 5
Diluted $ 0.39 $ 0.32 22 $ 1.25 $ 1.17 7
————————————————————————-
Net income 72,071 49,748 45 186,129 177,204 5
Net income
per share
Basic $ 0.47 $ 0.33 42 $ 1.22 $ 1.16 5
Diluted $ 0.47 $ 0.32 47 $ 1.20 $ 1.14 5
————————————————————————-
Funds from
opera-
tions(3) 90,450 53,257 70 297,217 210,743 41
Funds from
operations
per
share(3)
Basic $ 0.59 $ 0.35 69 $ 1.94 $ 1.38 41
Diluted $ 0.58 $ 0.34 71 $ 1.92 $ 1.35 42
————————————————————————-
Weighted
average
shares –
basic
(000s) 153,122 152,516 – 153,083 152,456 –
Weighted
average
shares –
diluted
(000s) 154,881 155,513 – 154,647 155,534 (1)
————————————————————————-
Drilling
Number of
marketed
rigs
Canada
Conven-
tional 169 162 4 169 162 4
Oil sands
coring/
coal-bed
methane 28 31 (10) 28 31 (10)
United
States 75 74 1 75 74 1
Interna-
tional(4) 44 49 (10) 44 49 (10)
Operating
days
Canada 7,578 5,760 32 19,509 18,108 8
United
States 5,289 5,118 3 15,316 14,271 7
Interna-
tional 2,458 2,274 8 7,421 6,929 7
————————————————————————-
Well Servicing
Number of
marketed
rigs/units
Canada 118 115 3 118 115 3
United
States 16 12 33 16 12 33
Operating
hours
Canada 37,907 39,674 (4) 111,356 129,899 (14)
United
States 10,481 7,035 49 27,912 19,421 44
————————————————————————-
(1) EBITDA is defined as “income before interest expense, income taxes,
depreciation and stock-based compensation expense”. Management
believes that in addition to net income, EBITDA and EBITDA per share
are useful supplemental measures as they provide an indication of the
results generated by the Company’s principal business activities
prior to consideration of how these activities are financed, how the
results are taxed in various jurisdictions or how the results are
impacted by the accounting standards associated with the Company’s
stock-based compensation plans. EBITDA and EBITDA per share as
defined above are not recognized measures under Canadian generally
accepted accounting principles and accordingly may not be comparable
to measures used by other companies.
(2) Adjusted net income is defined as “net income before stock-based
compensation expense, tax-effected using an income tax rate of 35%”.
Adjusted net income and adjusted net income per share are useful
supplemental measures as they provide an indication of the results
generated by the Company’s principal business activities prior to
consideration of how the results are impacted by the accounting
standards associated with the Company’s stock-based compensation
plans, net of income taxes. Adjusted net income and adjusted net
income per share as defined above are not recognized measures under
Canadian generally accepted accounting principles and accordingly may
not be comparable to measures used by other companies.
(3) Funds from operations is defined as “cash provided by operating
activities before the change in non-cash working capital”. Funds from
operations and funds from operations per share are measures that
provide shareholders and potential investors with additional
information regarding the Company’s liquidity and its ability to
generate funds to finance its operations. Management utilizes these
measures to assess the Company’s ability to finance operating
activities and capital expenditures. Funds from operations and funds
from operations per share are not measures that have any standardized
meaning prescribed by Canadian generally accepted accounting
principles and accordingly may not be comparable to similar measures
used by other companies.
(4) Includes workover rigs.
Revenue and Oilfield Services Expense
Three months Nine months
ended September 30 ended September 30
———————————————————-
% %
($ thousands) 2008 2007 change 2008 2007 change
————————————————————————-
Revenue
Canada 193,939 169,726 14 562,767 592,884 (5)
United
States 161,621 149,108 8 453,761 416,739 9
International 79,626 64,482 23 228,616 179,717 27
———————————————————-
435,186 383,316 14 1,245,144 1,189,340 5
Oilfield
services
expense 301,233 268,270 12 821,412 791,151 4
———————————————————-
133,953 115,046 16 423,732 398,189 6
———————————————————-
Gross margin 30.8% 30.0% 34.0% 33.5%
————————————————————————-
Canada
——
The fundamentals of the Canadian oilfield services market strengthened
and continued its upward trend during the third quarter of 2008. Following a
weak first half of 2008, favorable natural gas and crude oil commodity prices
supported an increase in operating activity levels in the third quarter of
2008 compared with earlier expectations and the third quarter of 2007.
Improved operating cash flows realized by the Company’s customers during the
third quarter of 2008 translated to increased demand for oilfield services in
the WCSB and a 32 percent increase in operating days for the Canadian oilfield
services segment compared with the third quarter of 2007. As the Company’s
customers redirected capital outside of the Province of Alberta in
anticipation of unfavorable royalty regime changes, the most noted growth in
operating activity levels were realized by the Company’s operations based in
southeast Saskatchewan. The Company has strategically expanded its operations
in Saskatchewan since the acquisition of Big Sky Drilling Ltd. in 2003, and
was well-positioned to capture the recent increase in exploration and
development activity in that province as operators shifted their focus to
popular crude oil plays in that region. Similarly, the Company experienced
steady demand for its services in northeast British Columbia, where activity
levels in shale gas resource plays, such as the Montney and Horn River basins,
are not as susceptible to short-term fluctuations in natural gas prices given
the longer life spans of these reservoirs compared with conventional plays.
For the nine months ended September 30, 2008, revenue generated by the
Canadian oilfield services segment totaled $562.8 million, a decline of five
percent from the same period of 2007. Operating days for the nine months ended
September 30, 2008 totaled 19,509 compared with 18,108 operating days recorded
in the first three quarters of 2007. While the Company delivered strong
financial and operating results in the third quarter of 2008, year-to-date
results for 2008 continue to reflect a weak first quarter which experienced
period-over-period declines in operating activity and pricing levels. While
momentum began to shift in Canada in the second quarter of 2008, continued
soft pricing, spring break up and wet weather conditions negated any
substantial improvements in financial results in that quarter compared with
the same period of 2007.
During the third quarter of 2008, the Company expanded its Canadian-based
equipment fleet with the acquisition of 12 specialty drilling rigs and related
equipment from Terracore Specialty Drilling Ltd. (“Terracore”). The specialty
drilling rigs have the capability of drilling coal bed methane and
conventional wells in addition to oil sands coring applications. Financial
contributions from this additional equipment will be most noted in the first
quarter of 2009, as the seasonal demand for coring equipment peaks during the
winter months.
United States
————-
Partially offsetting challenges faced by the Company’s Canadian
operations, the United States oilfield services division delivered record
financial results in both the third quarter of 2008 and the nine months ended
September 30, 2008, highlighting the importance of the Company’s initiatives
to lessen its exposure to the cyclicality of any one particular market
segment. Revenue from the United States oilfield services segment totaled
$161.6 million for the third quarter of 2008, an increase of eight percent
over the third quarter of 2007. Revenue growth was also achieved in the nine
months ended September 30, 2008, with revenue surpassing the prior period by
nine percent. The revenue growth achieved by the United States oilfield
services division in the first nine months of 2008 compared with the first
nine months of 2007, as presented in Canadian dollars, is somewhat diminished
by the impact of foreign exchange rates. The average United States dollar
exchange rate at which results are translated to Canadian dollars for
presentation purposes declined eight percent in the first nine months of 2008
compared with the first nine months of 2007.
The addition of 13 ADRs to the United States drilling rig fleet is the
main contributor to the improved financial and operational results delivered
by the United States oilfield services segment in 2008. As of September 30,
2008, all 13 ADRs from the 2007 build program were operating compared with 11
operating and two under construction as of September 30, 2007. The Company’s
proprietary ADR(TM) enabled it to capture increased demand for the specialty,
technologically-advanced equipment required to explore and develop the
unconventional natural gas resource plays in the Rocky Mountain region. The
newly constructed ADRs were introduced to the fleet under term contracts,
which have partially mitigated the Company’s exposure to the impact of
short-term fluctuations in natural gas prices on drilling day rates. The
Company also expanded its United States well servicing operation in 2008,
adding two well servicing units to that market in the first nine months of
2008 and realizing a 49 percent increase in operating hours in the third
quarter of 2008 and a 44 percent increase in operating hours in the nine
months ended September 30, 2008 compared with the same periods of 2007.
The Company previously announced intentions to further expand its
drilling rig fleet in the United States by a total of 20 ADRs and four well
servicing rigs. Subsequent to that announcement, the Company’s customers have
been forced to react to a sharp decline in commodity prices, substantial
uncertainty caused by the current global credit crisis and the threat of a
global recession. As a result, in working with the needs of its customers, the
Company has scaled back its expansion plans accordingly. As of November 10,
2008, the Company’s construction program consists of eight ADRs destined for
the United States under term contracts. The well servicing fleet expansion is
continuing as planned. The construction of one well servicing rig was
completed during the third quarter of 2008 and the remaining three well
servicing rigs are expected to be complete in the fourth quarter of 2008.
International
————-
Revenue for the Company’s international oilfield services segment totaled
$79.6 million for the third quarter of 2008, an increase of 23 percent over
the third quarter of 2007. For the nine months ended September 30, 2008,
revenue generated by the international oilfield services segment totaled
$228.6 million, an increase of 27 percent over the prior period. International
operating days increased eight percent and seven percent for the third quarter
of 2008 and for the nine months ended September 30, 2008, respectively,
compared with the corresponding periods of 2007.
Demand for oilfield services in the international arena is more heavily
influenced by crude oil prices compared with the predominantly natural gas
focus of the WCSB and the Rocky Mountain region of the United States. Crude
oil prices improved significantly in 2008 compared with 2007, driving strong
demand for oilfield services in all of the Company’s international locations.
West Texas Intermediate crude oil averaged US$118.22 per barrel during the
third quarter of 2008, an increase of 57 percent over an average price of
US$75.15 per barrel during the third quarter of 2007. For the nine months
ended September 30, 2008, West Texas Intermediate crude oil averaged US$113.52
per barrel, an increase of 71 percent over the average price of $66.22 per
barrel for the nine months ended September 30, 2007.
The Company repositioned several drilling rigs late in 2007 and early
2008 to better position itself to capture an increase in global demand for
oilfield services. These equipment transfers resulted in meaningful
period-over-period financial improvements for the international segment. The
equipment transfers include the relocation of two ADRs from Canada to
Australia in the latter half of 2007, the deployment of one drilling rig to
the Middle East in the fourth quarter of 2007, as well as the completion of
two drilling rig construction projects in the Middle East and Africa in the
first quarter of 2008. Partially offsetting improved financial contributions
from this relocated equipment, two drilling rigs previously operating in Asia
completed their contracts in 2008 and are being marketed to other
international jurisdictions. The drilling rig deployed to the Middle East in
the fourth quarter of 2007 completed its contract subsequent to September 30,
2008 and will remain at a Middle East port until a new contract can be
secured. The construction of six new ADRs for deployment to the Middle East
and Africa markets under term contracts is continuing as planned, with
delivery expected to occur in the first and second quarters of 2009.
Gross Margin
————
The Company recorded a gross operating margin of 30.8 percent in the
third quarter of 2008 and 34.0 percent for the nine months ended September 30,
2008, slight improvements over gross operating margins realized in the
comparable periods of 2007. Stable pricing in the United States and improved
operating margins in the international oilfield services division, driven by
robust crude oil prices, offset declining operating margins in Canada
throughout 2008.
Depreciation
Three months Nine months
ended September 30 ended September 30
———————————————————-
% %
($ thousands) 2008 2007 change 2008 2007 change
————————————————————————-
Depreciation 33,987 22,028 54 89,705 64,938 38
————————————————————————-
Depreciation expense totaled $34.0 million for the third quarter of 2008
compared with $22.0 million for the third quarter of 2007. Depreciation
expense increased to $89.7 million for the nine months ended September 30,
2008 compared with $64.9 million for the nine months ended September 30, 2007.
These increases are due to the introduction of higher valued equipment to the
drilling rig fleet following the completion of the 2007 rig building programs,
primarily in the United States, as well as an increase in consolidated
operating activity levels on a period-over-period basis.
Several changes in accounting estimates in 2008 impact the comparability
of depreciation on a period-over-period basis. Effective January 1, 2008 the
Company reduced the estimated useful life of oil sands coring rigs and coiled
tubing units, thereby accelerating the depreciation of this equipment.
Effective July 1, 2008, the Company began applying a depreciation charge for
drilling and well servicing rigs that are not currently operating based on the
revised estimated useful life of such equipment.
General and Administrative Expense
Three months Nine months
ended September 30 ended September 30
———————————————————-
% %
($ thousands) 2008 2007 change 2008 2007 change
————————————————————————-
General and
administrative 12,168 11,527 6 39,957 38,565 4
% of revenue 2.8% 3.0% 3.2% 3.2%
————————————————————————-
General and administrative expense totaled $12.2 million (2.8 percent of
revenue) for the third quarter of 2008 compared with general and
administrative expense of $11.5 million (3.0 percent of revenue) for the third
quarter of 2007. For the nine-month period ended September 30, 2008, general
and administrative expense totaled $40.0 million (3.2 percent of revenue), an
increase of four percent over general and administrative expense of $38.6
million (3.2 percent of revenue) recorded in the first three quarters of 2007.
Stock-Based Compensation Expense
Three months Nine months
ended September 30 ended September 30
———————————————————-
% %
($ thousands) 2008 2007 change 2008 2007 change
————————————————————————-
Stock-based
compensation (16,993) 630 (2,797) 10,457 7,728 35
————————————————————————-
Stock-based compensation expense arises from the fair value accounting
for the Company’s stock option plan. For the quarter-ended September 30, 2008,
stock-based compensation is a recovery of $17.0 million, arising from a
decline in the price of the Company’s common shares over this period. For the
nine months ended September 30, 2008, stock-based compensation expense totaled
$10.5 million and comprises $1.8 million for additional vesting of stock
options and $8.7 million due to an increase in the price of the Company’s
common shares. The price of the Company’s common shares was $16.68 at
September 30, 2008 compared with $22.22 at June 30, 2008 and $15.25 at
December 31, 2007.
Interest Expense
Three months Nine months
ended September 30 ended September 30
———————————————————-
% %
($ thousands) 2008 2007 change 2008 2007 change
————————————————————————-
Interest 1,458 1,190 23 5,402 4,095 32
————————————————————————-
Interest expense is incurred on the Company’s operating lines of credit
and the promissory note payable. The variance in interest expense on a
period-over-period basis is due to an increase in the average balance
outstanding on the Company’s operating lines of credit, and the issuance of a
promissory note payable in the third quarter of 2008.
Income Taxes
Three months Nine months
ended September 30 ended September 30
———————————————————-
% %
($ thousands) 2008 2007 change 2008 2007 change
————————————————————————-
Current income
tax 27,364 48,944 (44) 72,885 130,776 (44)
Future income
tax 3,898 (19,021) (120) 19,197 (25,117) (176)
———————————————————-
31,262 29,923 4 92,082 105,659 (13)
———————————————————-
Effective
income tax
rate (%) 30.3% 37.6% 33.1% 37.4%
————————————————————————-
The effective income tax rate for the third quarter of 2008 was 30.3
percent compared with 37.6 percent for the third quarter of 2007. For the nine
months ended September 30, 2008, the effective income tax rate was 33.1
percent compared with 37.4 percent for the nine months ended September 30,
2007. The decrease in the effective income tax rate for the nine months ended
September 30, 2008 compared with the corresponding period of 2007 is partially
the result of $4.0 million of Omani tax assessments included in current income
tax expense for the nine months ended September 30, 2007 with no comparable
amount in 2008. Excluding the impact of the Omani tax assessments, the
effective income tax rate would have been 35.9 percent for the nine months
ended September 30, 2007.
The decrease in the Company’s effective income tax rate on a
quarter-over-quarter and year-to-date basis is also due to ongoing income tax
rate reductions in Canada. Income tax rate reductions previously announced by
the federal government will phase in income tax rate reductions each year
until 2012, at which point the federal corporate income tax rate in Canada
will reduce to 15.0 percent from its current level of 19.5 percent.
Financial Position
The following chart outlines significant changes in the consolidated
balance sheets from December 31, 2007 to September 30, 2008:
($ thousands) Change Explanation
————————————————————————-
Cash and cash 22,745 See consolidated statement of cash flows.
equivalents
Accounts receivable 45,216 Increase due to an increase in operating
activity in the third quarter of 2008
compared with the fourth quarter of 2007.
Inventory and other (38,351) Decrease due to the reclassification of
drill pipe inventory to property and
equipment as a result of a revision in the
estimated useful life.
Property and 185,127 Increase due to the acquisition of 12
equipment specialty drilling rigs, the new build
construction program, ongoing capital
expenditures and the reclassification of
drill pipe inventory, offset by
depreciation in the period.
Accounts payable 18,342 Increase due to an increase in operating
and accrued activity in the third quarter of 2008
liabilities compared with the fourth quarter of 2007.
Operating lines (3,155) Decrease due to net repayments of the
of credit operating lines of credit.
Promissory note 20,000 Increase due to the issuance of a
payable promissory note payable in conjunction with
the acquisition of 12 specialty drilling
rigs during the third quarter of 2008.
Stock-based 1,364 Increase due to additional vesting of stock
compensation options and common share price increases,
net of stock option exercises.
Income taxes (20,142) Decrease due to income tax instalments, net
payable of the current income tax provision for the
period.
Dividends payable 10 Increase due to a slight increase in the
number of outstanding common shares
compared with the fourth quarter of 2007.
Future income 19,065 Increase due to the current period future
taxes income tax provision and changes in foreign
exchange rates in the period.
Shareholders’ 179,253 Increase due to the aggregate impact of net
equity income for the period, increase in capital
stock due to exercises of employee stock
options, impact of foreign exchange rate
fluctuations on net assets of foreign self-
sustaining subsidiaries, less dividends
declared in the period.
————————————————————————-
Working Capital and Funds from Operations
Three months Nine months
ended September 30 ended September 30
———————————————————-
% %
($ thousands) 2008 2007 change 2008 2007 change
————————————————————————-
Funds from
operations 90,450 53,257 70 297,217 210,743 41
Funds from
operations
per share $ 0.59 $ 0.35 69 $ 1.94 $ 1.38 41
Working
capital(1) 93,001 60,272 54 93,001 60,272 54
————————————————————————-
(1) Comparative figures as of December 31, 2007.
During the three months ended September 30, 2008, the Company generated
funds from operations of $90.5 million ($0.59 per common share) compared with
funds from operations of $53.3 million ($0.35 per common share) for the three
months ended September 30, 2007, an increase of 70 percent. Funds from
operations totaled $297.2 million ($1.94 per common share) in the first nine
months of 2008, an increase of 41 percent over funds from operations of $210.7
million ($1.38 per common share) generated in the nine months ended September
30, 2007.
The substantial increase in funds from operations in the third quarter of
2008 compared with the third quarter of 2007 reflects record funds from
operations generated in the United States, as well as a rebound in
period-over-period operating activity levels in Canada as stable natural gas
and high crude oil commodity prices revived demand in parts of the WCSB. The
growth in funds from operations achieved in the nine months ended September
30, 2008 over the comparable period of 2007 is predominantly due to improved
operating margins and increased operating activity levels in the Company’s
United States and international oilfield services divisions, offsetting
weakness experienced in the Canadian market in the first half of 2008.
At September 30, 2008, the Company had a positive working capital
position of $93.0 million compared with working capital of $60.3 million at
December 31, 2007. The improvement in working capital in the first nine months
of 2008 is attributable to positive cash flows generated by all of the
Company’s operating segments. Offsetting the improvement in working capital
arising from strong operating results, working capital was reduced by the
reclassification of drill pipe inventory to property and equipment as a result
of a revision in the estimated useful lives of these assets. As of September
30, 2008, the Company continues to operate with sufficient liquidity to meet
its obligations as they come due.
Investing Activities
Three months Nine months
ended September 30 ended September 30
———————————————————-
% %
($ thousands) 2008 2007 change 2008 2007 change
————————————————————————-
Net purchase
of property
and equipment (128,149) (62,850) 104 (206,672) (223,967) (8)
Net change in
non-cash
working
capital 48,845 12,183 301 43,589 (14,218) (407)
———————————————————-
Cash used in
investing
activities (79,304) (50,667) 57 (163,083) (238,185) (32)
————————————————————————-
Net purchases of property and equipment during the third quarter of 2008
totaled $128.1 million compared with $62.9 million for the third quarter of
2007. Net purchases of property and equipment for the nine months ended
September 30, 2008 totaled $206.7 million compared with $224.0 million for the
nine months ended September 30, 2007.
In addition to ongoing drilling rig upgrade initiatives, capital
expenditures in Canada during the third quarter of 2008 include the
acquisition of 12 specialty drilling rigs and related equipment from
Terracore. The acquisition of this equipment was funded from existing working
capital and the issuance of a $20 million promissory note payable. Other
capital additions include the construction of two well servicing rigs in
Canada in the first quarter of 2008 and the construction of one well servicing
rig in the United States in the third quarter of 2008. Major capital additions
in the international oilfield services division during the first nine months
of 2008 include the deployment of one drilling rig to the Middle East and one
drilling rig to North Africa in the first quarter of 2008.
Net purchases of property and equipment for the third quarter of 2008 and
for the nine months ended September 30, 2008 also include purchases associated
with the 2008 new build program. Additional details regarding construction
programs in progress at September 30, 2008 are provided below.
Financing Activities
Three months Nine months
ended September 30 ended September 30
———————————————————-
% %
($ thousands) 2008 2007 change 2008 2007 change
————————————————————————-
Net increase
(decrease) in
operating
lines of
credit 39,618 48,243 (18) (3,155) 42,375 (107)
Net increase in
promissory
note payable 20,000 – – 20,000 – –
Issue of
capital stock 488 276 77 899 1,942 (54)
Dividends (12,632) (12,202) 4 (37,889) (36,591) 4
Net change in
non-cash
working
capital 4 1 300 10 47 (79)
———————————————————-
Cash provided
by (used in)
financing
activities 47,478 36,318 31 (20,135) 7,773 (359)
————————————————————————-
During the nine months ended September 30, 2008, the Company restructured
its operating credit facilities to better support its global operations and
international growth initiatives. Effective June 26, 2008, the Company’s
available operating lines of credit consist of a $200 million global revolving
credit facility (the “global facility”) and a $50 million Canadian based
revolving credit facility (the “Canadian facility”). The global facility is
available to the Company and any of its wholly owned subsidiaries, and may be
drawn in Canadian, United States or Australian dollars, up to the equivalent
value of $200 million Canadian dollars. The amount available under the
Canadian facility is $50 million or the equivalent United States dollars. The
utilized balance of the operating lines of credit was increased during the
three months ended September 30, 2008 primarily to finance the Company’s new
build program.
During the third quarter, the Company issued a promissory note payable in
the amount of $20 million in connection with the purchase of specialty
drilling rigs and related equipment from Terracore. The promissory note is
unsecured, bears interest at five percent and is payable in full on July 16,
2011.
Other financing activities during the third quarter of 2008 include the
receipt of $0.5 million on the exercise of employee stock options and the
payment of dividends in the amount of $12.6 million. Dividends were declared
at a quarterly dividend rate of $0.0825 per common share for the third quarter
of 2008, an increase of four percent over dividends of $0.08 per common share
declared in the third quarter of 2007. For the nine months ended September 30,
2008, cash received on employee stock option exercises totaled $0.9 million
and dividends declared totaled $37.9 million. During the first nine months of
2008, the Company declared year-to-date dividends totaling $0.2475 per common
share compared with $0.24 per common share during the first nine months of
2007. All dividends paid by the Company subsequent to January 1, 2006 qualify
as an eligible dividend, as defined by subsection 89(1) of the Canadian Income
Tax Act.
The Company also announces an increase of three percent in its regular
quarterly dividend to $0.085 per common share. The Company has increased the
cumulative amount of dividends declared in each fiscal year since the Company
began paying a dividend in September 1995. The Board of Directors of the
Company has declared the dividend of $0.085 to be payable on January 2, 2009
to all Common Shareholders of record as of December 22, 2008. The dividend
payment is pursuant to the quarterly dividend policy adopted by the Company.
Pursuant to subsection 89(14) of the ITA, the dividend being paid is being
designated as an eligible dividend, as defined in subsection 89(1) of the ITA.
New Builds
As previously disclosed, the Company is expanding its global fleet of
state-of-the-art ADR(TM) drilling rigs. As of November 10, 2008, the
world-wide drilling rig construction program consists of 14 ADRs and eight
well servicing rigs, a decline of 13 drilling rigs from previous disclosure.
Following the unprecedented events impacting the global economy in recent
months and the sharp decline in crude oil prices, the Company has prudently
reviewed and amended its drilling rig construction program. Accordingly, 13 of
the previously announced drilling rig construction projects have been
suspended or delayed. All remaining drilling rig construction projects are
supported by term contracts and are proceeding as planned. The Company is
carefully monitoring market conditions and continues to look for additional
expansion opportunities.
Of the 14 ADRs to be constructed, two are ADR(TM)-250 models, two are
ADR(TM)-300 models, four are ADR(TM)-350 models and six are ADR(TM)-500
models. Upon completion of this new build program the Company will have a
total of 62 ADRs in its fleet.
The Company is continuing the expansion of its well servicing fleet in
Canada and the United States. During the third quarter of 2008, one new well
servicing rig was placed in service in the United States. An additional eight
newly built well servicing rigs will be added to the Canadian and United
States markets over the remainder of 2008 and early 2009.
The revised new build delivery schedule, by geographic area, is as
follows:
Q4 2008 Q1 2009 Q2 2009 Q3 2009 Q4 2009 Q1 2010 Total
————————————————————————-
ADRs
United
States 1 1 – 2 2 2 8
Interna-
tional – 5 1 – – – 6
————————————————————
Total 1 6 1 2 2 2 14
————————————————————————-
Well Servicing
Rigs
Canada 2 1 2 – – – 5
United
States 3 – – – – – 3
————————————————————
Total 5 1 2 – – – 8
————————————————————————-
Outlook
As previously disclosed, the operating and financial results for the
third quarter of 2008, after adjusting for the impact of stock based
compensation expense, exceeded the Company’s results from one year ago and our
expectations set earlier in the year. That said, there is much uncertainty
with respect to the immediate future given the expected impact of the global
credit crisis and a general reduction in the demand for crude oil and natural
gas owing to recessionary conditions in key North American, European and other
world markets. The recent sharp decline in commodity prices, particularly for
crude oil, and the tightening of credit availability dictates that our
customers will not have the same level of cash flows directed to oilfield
services expenditures as we have seen in the past. Reduced demand for oilfield
services will, obviously, negatively impact the operating and financial
results for the Company and the industry in general. The Company has already
taken steps to reduce capital expenditure levels and strategically updated its
credit facilities in the second quarter of this year, ensuring that it has the
operating facilities required to support current and future levels of
operations. The strength of the Company’s balance sheet has never been more
important than it is now.
Currently, the Canadian operations are expected to experience a winter
drilling season that is improved over the previous year, more a testament to
the weakness of the winter of 2007/08 than the anticipated strength of
2008/09. Exploration and production companies have generally cash flowed very
well through the first nine months of 2008, leading to an increase in drilling
plans in some areas for this winter compared to last year. Accordingly,
bookings for the Canadian drilling fleet are improved for this winter and the
Company has been developing crews to ensure that operations can be effectively
and safely staffed for the winter. What happens beyond the first quarter of
2009 is still very much in doubt and will be dependent on commodity prices at
the end of the winter heating season in North America. In addition to the
ongoing risks from global credit, recessionary and environmental issues, oil
and natural gas projects in the Province of Alberta also have to contend with
the negative economic impacts of royalty changes effective January 1, 2009.
Although representatives of the Province of Alberta have stated that they will
continue to look at the “unintended consequences” of the royalty changes, it
seems that they are making a mistake by not reviewing their stance on this
important matter given the way the world has changed. Record crude oil prices
and favorable natural gas commodity prices through the first half of 2008
merely masked the problems and issues with the revised Alberta royalty regime.
Despite high crude oil prices and favorable natural gas prices, demand for
drilling services in Alberta in the third quarter of this year did not react
as positively to such prices as did demand in the neighbouring provinces of
Saskatchewan and British Columbia. The Company believes that, without
meaningful royalty changes, the impact in Alberta will be even worse in 2009.
The negative outlook for natural gas prices of one year ago did not
materially impact the demand for United States drilling services in 2008 as
the exploration and production companies appeared to focus on future strip
prices and the need to prove-up reserves. Consequently, many companies drilled
through the lower initial outlook for spot prices for natural gas. The Company
is not as confident this time around and expects that the demand for drilling
rigs in the United States, particularly for conventional natural gas projects,
will react to lower expectations for natural gas prices and reduced levels of
cash flows and credit availability. The Company expects that its fleet
modernization program undertaken over the last several years will allow it to
maintain or increase market share in an environment of reduced activity levels
in the United States. However, reduced demand for oilfield services will
negatively impact margins and cash flow levels. It is therefore prudent that
the Company has reduced its previously announced drilling rig building program
in the United States from 20 drilling rigs to eight drilling rigs. All eight
of the drilling rigs to be constructed over the next 12 to 15 months are
supported by “take-or-pay” contracts with major customers. The Company’s
United States operations are further supported by a significant number of
existing term contracts.
The international oilfield services market is not immune to the impacts
of the global credit crisis and recessionary pressures; however, the nature of
the drilling projects is such that they take a longer term view. The projects
themselves are generally of a longer term and will carry on through
completion. There may be a reduction or delay in new projects resulting from
current global conditions and outlook, but existing programs should continue
unabated. Accordingly, the Company anticipates its existing international
operations will remain steady in the immediate future and that operating and
financial results will improve with the completion of the six new drilling
rigs currently under construction. These rigs will be deployed to Africa and
the Middle East early in the new year adding scale to the international
operations. The previously announced refurbishment of an idle international
drilling rig has been postponed until general economic conditions improve.
This is not the first cyclical low period faced by the Company, nor will
it likely be the last. While it is difficult, if not impossible, to ascertain
how bad things could really get before the inevitable recovery commences, it
is clear that the Company has the advantages of a proven cost-conscious
culture and one of the strongest balance sheets in the industry. These
strengths will enable the Company to weather the storm and take advantage of
the inevitable opportunities that will arise. The key, as always, is not
“growth for growth’s sake”, but acquiring the right type of equipment at the
right cost. Our value conscious strategy will ensure that the interests of all
our stakeholders, including shareholders, customers and employees, will
continue to be well served.
Risks and Uncertainties
This document contains forward-looking statements based upon current
expectations that involve a number of business risks and uncertainties. The
factors that could cause results to differ materially include, but are not
limited to, political and economic conditions, crude oil and natural gas
prices, foreign currency fluctuations, weather conditions and the ability of
oil and natural gas companies to raise capital or other unforeseen conditions
which could impact on the use of the services supplied by the Company.
Conference Call
A conference call will be held to discuss the Company’s second quarter
results at 2:00 p.m. MST (4:00 p.m. EST) on Monday, November 10, 2008. The
conference call number is 1-800-732-1073. A taped recording will be available
until November 17, 2008 by dialing 1-877-289-8525 and entering reservation
number 21288240No.. A live broadcast may be accessed through the Company’s web
site at www.ensignenergy.com.
Ensign Energy Services Inc. is an international oilfield services
contractor and is listed on the Toronto Stock Exchange under the trading
symbol ESI.
CONSOLIDATED BALANCE SHEETS
As at September 30, 2008 and December 31, 2007
(Unaudited, in thousands of dollars)
September 30 December 31
2008 2007
————- ————
Assets
Current assets
Cash and cash equivalents $ 24,685 $ 1,940
Accounts receivable 346,937 301,721
Inventory and other 51,401 89,752
Future income taxes 3,129 2,367
————————–
426,152 395,780
Property and equipment 1,575,907 1,390,780
————————–
$ 2,002,059 $ 1,786,560
————————–
————————–
Liabilities
Current liabilities
Accounts payable and accrued liabilities $ 195,937 $ 177,595
Operating lines of credit (note 4) 114,814 117,969
Current portion of stock-based compensation 10,644 8,056
Income taxes payable (877) 19,265
Dividends payable 12,633 12,623
————————–
333,151 335,508
Promissory note payable (note 5) 20,000 –
Stock-based compensation 3,499 4,723
Future income taxes 221,950 202,123
————————–
578,600 542,354
————————–
Shareholders’ Equity
Capital stock (note 6) 169,320 167,599
Accumulated other comprehensive income (68,296) (97,588)
Retained earnings 1,322,435 1,174,195
————————–
1,423,459 1,244,206
————————–
$ 2,002,059 $ 1,786,560
————————–
————————–
See accompanying notes to the consolidated financial statements.
CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS
For the three and nine months ended September 30, 2008 and 2007
(Unaudited – in thousands of dollars, except per share data)
Three months ended Nine months ended
September 30 September 30
2008 2007 2008 2007
—————————————————
Revenue
Oilfield services $ 435,186 $ 383,316 $ 1,245,144 $ 1,189,340
Expenses
Oilfield services 301,233 268,270 821,412 791,151
Depreciation 33,987 22,028 89,705 64,938
General and
administrative 12,168 11,527 39,957 38,565
Stock-based
compensation (16,993) 630 10,457 7,728
Interest 1,458 1,190 5,402 4,095
—————————————————
331,853 303,645 966,933 906,477
—————————————————
Income before income
taxes 103,333 79,671 278,211 282,863
Income taxes
Current 27,364 48,944 72,885 130,776
Future 3,898 (19,021) 19,197 (25,117)
—————————————————
31,262 29,923 92,082 105,659
Net income for the
period 72,071 49,748 186,129 177,204
Retained earnings –
beginning of period 1,262,996 1,076,711 1,174,195 973,644
Dividends (note 6) (12,632) (12,202) (37,889) (36,591)
—————————————————
Retained earnings –
end of period $ 1,322,435 $ 1,114,257 $ 1,322,435 $ 1,114,257
—————————————————
—————————————————
Net income per share
(note 6)
Basic $ 0.47 $ 0.33 $ 1.22 $ 1.16
Diluted $ 0.47 $ 0.32 $ 1.20 $ 1.14
—————————————————
—————————————————
See accompanying notes to the consolidated financial statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the three and nine months ended September 30, 2008 and 2007
(Unaudited – in thousands of dollars)
Three months ended Nine months ended
September 30 September 30
2008 2007 2008 2007
—————————————————
Cash provided by
(used in)
Operating activities
Net income for the
period $ 72,071 $ 49,748 $ 186,129 $ 177,204
Items not affecting
cash:
Depreciation 33,987 22,028 89,705 64,938
Stock-based
compensation, net
of cash paid (19,506) 502 2,186 (6,282)
Future income taxes 3,898 (19,021) 19,197 (25,117)
—————————————————
Cash provided by
operating activities
before the change in
non-cash working
capital 90,450 53,257 297,217 210,743
Net change in non-cash
working capital
(note 8) (67,669) (33,538) (91,254) 20,400
—————————————————
22,781 19,719 205,963 231,143
—————————————————
Investing activities
Net purchase of
property and
equipment (128,149) (62,850) (206,672) (223,967)
Net change in non-cash
working capital
(note 8) 48,845 12,183 43,589 (14,218)
—————————————————
(79,304) (50,667) (163,083) (238,185)
—————————————————
Financing activities
Net increase (decrease)
in operating lines of
credit 39,618 48,243 (3,155) 42,375
Net increase in
promissory note
payable (note 5) 20,000 – 20,000 –
Issue of capital stock 488 276 899 1,942
Dividends (note 6) (12,632) (12,202) (37,889) (36,591)
Net change in non-cash
working capital (note 8) 4 1 10 47
—————————————————
47,478 36,318 (20,135) 7,773
—————————————————
Net (decrease) increase
in cash and cash
equivalents during the
period (9,045) 5,370 22,745 731
Cash and cash
equivalents –
beginning of period 33,730 9,931 1,940 14,570
Cash and cash
equivalents – end of
period $ 24,685 $ 15,301 $ 24,685 $ 15,301
—————————————————
—————————————————
Supplemental
information
Interest paid $ 1,521 $ 1,485 $ 5,585 $ 3,812
Income taxes paid $ 17,794 $ 37,145 $ 93,027 $ 141,068
—————————————————
—————————————————
See accompanying notes to the consolidated financial statements.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
For the three and nine months ended September 30, 2008 and 2007
(Unaudited – in thousands of dollars)
Three months ended Nine months ended
September 30 September 30
2008 2007 2008 2007
—————————————————
Net income for the
period $ 72,071 $ 49,748 $ 186,129 $ 177,204
Other comprehensive
income
Foreign currency
translation adjustment (11,800) (31,357) 29,292 (69,708)
—————————————————
Comprehensive income
for the period $ 60,271 $ 18,391 $ 215,421 $ 107,496
—————————————————
—————————————————
See accompanying notes to the consolidated financial statements.
CONSOLIDATED STATEMENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME
For the three and nine months ended September 30, 2008 and 2007
(Unaudited – in thousands of dollars)
Three months ended Nine months ended
September 30 September 30
2008 2007 2008 2007
—————————————————
Accumulated other
comprehensive income
– beginning of period $ (56,496) $ (58,514) $ (97,588) $ (20,163)
Foreign currency
translation adjustment (11,800) (31,357) 29,292 (69,708)
—————————————————
Accumulated other
comprehensive income
– end of period $ (68,296) $ (89,871) $ (68,296) $ (89,871)
—————————————————
—————————————————
See accompanying notes to the consolidated financial statements.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the three and nine months ended September 30, 2008 and 2007
(Unaudited, in thousands of dollars, except share and per share data)
The interim consolidated financial statements have been prepared in
accordance with Canadian generally accepted accounting principles
(“Canadian GAAP”), and include the accounts of Ensign Energy Services
Inc. and its subsidiaries and partnerships (the “Company”), substantially
all of which are wholly-owned. The interim consolidated financial
statements have been prepared following the same accounting policies and
methods of computation as the consolidated financial statements for the
year ended December 31, 2007, except as noted below. The disclosures
provided below are incremental to those included with the annual
consolidated financial statements. These interim consolidated financial
statements should be read in conjunction with the consolidated financial
statements and the notes thereto in the Company’s annual report for the
year ended December 31, 2007.
1. Adoption of new accounting standards
Capital disclosures
Effective January 1, 2008, the Company adopted the Canadian Institute
of Chartered Accountants (“CICA”) Handbook Section 1535 “Capital
Disclosures”. The new section requires an entity to disclose
information about its capital and how it is managed. The Company’s
capital management strategy is outlined in note 9.
Financial Instruments
Effective January 1, 2008, the Company adopted CICA Handbook Section
3862 “Financial Instruments – Disclosures” and Section 3863
“Financial Instruments – Presentation”, which replaced Section 3861
“Financial Instruments – Disclosure and Presentation”. The new
sections revise and enhance financial instruments disclosure
requirements and place increased emphasis on disclosures about the
nature and extent of risks arising from financial instruments and how
the Company manages those risks.
The Company has designated its financial instruments as follows:
– Cash and cash equivalents are classified as “held for trading” and
any period change in fair value is recorded through net income;
– Accounts receivable are classified as “loans and receivables”.
After their initial fair value measurement, they are measured at
amortized cost using the effective interest rate method. For the
Company, the measured amount generally corresponds to historical
cost; and
– Accounts payable and accrued liabilities, operating lines of
credit, dividends payable and promissory note payable are classified
as “other financial liabilities”. After their initial fair value
measurement, they are measured at amortized cost using the effective
interest rate method. For the Company, the measured amount generally
corresponds to historical cost.
Inventories
Effective January 1, 2008, the Company adopted CICA Handbook Section
3031 “Inventories”, which requires inventory to be valued on a
‘first-in, first out’ or weighted average basis. The new standard
also requires fixed and variable production overheads that are
incurred in converting materials into finished goods to be allocated
to the cost of inventory on a systematic basis. The adoption of this
standard did not have a material impact on the Company’s consolidated
financial statements.
Recent accounting pronouncements
In January 2006, the CICA Accounting Standards Board (“AcSB”) adopted
a strategic plan for the direction of accounting standards in Canada.
As part of that plan, the AcSB confirmed in February 2008 that
International Financial Reporting Standards (“IFRS”) will replace
Canadian GAAP in 2011 for profit-oriented Canadian publicly
accountable enterprises. As the Company will be required to report
its results in accordance with IFRS starting in 2011, the Company is
assessing the potential impacts of this changeover and developing its
plan accordingly. When finalized, it will include project structure
and governance, resourcing and training, and an analysis of key
differences between IFRS and Canadian GAAP.
2. Change in accounting estimates
Effective January 1, 2008 the Company revised the estimated useful
life of drill pipe to 1,500 operating days, to be depreciated on a
unit-of-production basis. The change in estimated useful life
reflects the Company’s recent experience with respect to the period
over which future benefits are derived from drill pipe and the impact
improved technologies have had on extending the useful lives of these
assets. As a result of this change in accounting estimate, drill pipe
of $39,000 previously classified as inventory and other on the
consolidated balance sheet has been reclassified to property and
equipment on the basis that its estimated useful life of 1,500
operating days extends beyond the current period.
Effective January 1, 2008 the Company revised the estimated useful
life of oil sands coring rigs from 3,650 operating days to 1,000
operating days. The oil sands coring rigs will continue to be
depreciated on a unit-of-production basis with a 20% residual value.
Further, the Company revised the estimated useful life of coiled
tubing units from 24,000 operating hours to five years, to be
depreciated on a straight-line basis. Effective July 1, 2008, the
Company began applying a deprecation charge for crude oil and natural
gas drilling and well servicing rigs that are not currently operating
based on the revised estimated useful life of such equipment.
These changes in accounting estimates have been applied on a
prospective basis and did not have a significant effect on
consolidated net income for the nine months ended September 30, 2008.
It is impracticable to estimate the effect of these changes in
accounting estimates on future periods as such an estimate would
depend on a forecast of future operating activity levels.
3. Seasonality of operations
The Company’s Canadian oilfield services operations are seasonal in
nature and are impacted by weather conditions that may hinder the
Company’s ability to access locations or move heavy equipment. The
lowest activity levels are experienced during the second quarter of
the year when road weight restrictions are in place and access to
wellsites in Canada is reduced.
4. Operating lines of credit
During the nine months ended September 30, 2008, the Company
restructured its operating credit facilities to better support its
global operations. Effective June 26, 2008, the Company’s available
operating lines of credit consist of a $200,000 global revolving
credit facility (the “global facility”) and a $50,000 Canadian based
revolving credit facility (the “Canadian facility”).
The global facility is available to the Company and any of its wholly
owned subsidiaries and may be drawn in Canadian, United States or
Australian dollars, up to the equivalent value of $200,000 Canadian
dollars. Interest is incurred on the utilized balance of the global
facility at prime interest rates or bankers’ acceptance rates/LIBOR
plus 0.75%. The global facility is unsecured.
The amount available under the Canadian facility is $50,000 or the
equivalent United States dollars. Interest is incurred on the
utilized balance of the Canadian facility at prime interest rates or
bankers’ acceptance rates/LIBOR plus 0.85%. The Canadian facility is
unsecured.
5. Promissory note payable
In connection with the purchase of specialty drilling rigs and
related equipment from Terracore Specialty Drilling Ltd.
(“Terracore”) on July 17, 2008, the Company issued a promissory note
to Terracore in the amount of $20,000. The promissory note has a term
of three years and shall be payable in full on July 16, 2011.
Interest on the promissory note is equal to five percent (5.0%) per
annum and will be paid in 12 consecutive quarterly instalments. The
Company may prepay the principal sum and interest in whole, or in
part, without penalty. The promissory note is unsecured.
6. Capital stock
Authorized
Unlimited common shares
Unlimited preferred shares, issuable in series
Outstanding
Number of
Common
Shares Amount
———————————————————————
Balance at January 1, 2008 153,041,378 $ 167,599
Issued under employee stock option plan 81,628 1,721
————————–
Balance at September 30, 2008 153,123,006 $ 169,320
———————————————————————
Options
A summary of the status of the Company’s stock option plan as of
September 30, 2008, and the changes during the nine-month period then
ended, is presented below:
Weighted
Average
Number of Exercise
Options Price
———————————————————————
Outstanding at January 1, 2008 9,655,450 $ 16.55
Granted 2,369,000 21.68
Exercised for common shares (81,628) (11.01)
Exercised for cash (937,860) (11.45)
Forfeited (469,700) (19.34)
———————————————————————
Outstanding at September 30, 2008 10,535,262 $ 18.07
———————————————————————
Exercisable at September 30, 2008 3,627,062 $ 15.32
———————————————————————
Options Outstanding Options Exercisable
———————————————————————
Average Weighted Weighted
Vesting Average Options Average
Options Remaining Exercise Exer- Exercise
Exercise Price Outstanding (in years) Price cisable Price
———————————————————————
$8.75 to $11.05 2,085,962 0.56 $ 10.44 1,501,562 $ 10.42
$13.50 to $18.85 1,832,200 1.52 14.10 822,400 13.79
$19.88 to $23.33 6,617,100 2.88 21.58 1,303,100 21.93
—————————————————–
10,535,262 2.19 $ 18.07 3,627,062 $ 15.32
———————————————————————
Common share dividends
During the nine months ended September 30, 2008, the Company declared
dividends of $37,889 (2007 – $36,591), being $0.2475 per common share
(2007 – $0.24 per common share).
Net income per share
Net income per share is calculated by dividing net income by the
weighted average number of common shares outstanding during the
period. Diluted net income per share is calculated using the treasury
stock method, which assumes that all outstanding stock options are
exercised, if dilutive, and the assumed proceeds are used to purchase
the Company’s common shares at the average market price during the
period.
The weighted average number of common shares outstanding for the
nine-month period ended September 30, 2008 and 2007 are as follows:
2008 2007
————————-
Weighted average number of common shares
outstanding – basic 153,083,329 152,455,715
Weighted average number of common shares
outstanding – diluted 154,646,906 155,533,693
————————-
Stock options of 4,390,000 (2007 – 4,806,000) were excluded from the
calculation of diluted weighted average number of common shares
outstanding, as the options’ exercise price was greater than the
average market price of the common shares for the period.
7. Segmented information
The Company operates in three geographic areas within one industry
segment. Oilfield services are provided in Canada, the United States
and internationally. The amounts related to each geographic area are
as follows:
Three months ended September 30, 2008
———————————————————————
Canada United States International Total
———————————————————————
Revenue $193,939 $161,621 $79,626 $435,186
Property and
equipment, net $765,665 $453,479 $356,763 $1,575,907
Capital expenditures,
net $3,980 $56,526 $67,643 $128,149
Depreciation $18,348 $8,109 $7,530 $33,987
———————————————————————
Three months ended September 30, 2007
———————————————————————
Canada United States International Total
———————————————————————
Revenue $169,726 $149,108 $64,482 $383,316
Property and
equipment, net $771,916 $325,535 $284,194 $1,381,645
Capital expenditures,
net $12,214 $29,741 $20,895 $62,850
Depreciation $11,400 $5,509 $5,119 $22,028
———————————————————————
Nine months ended September 30, 2008
———————————————————————
Canada United States International Total
———————————————————————
Revenue $562,767 $453,761 $228,616 $1,245,144
Property and
equipment, net $765,665 $453,479 $356,763 $1,575,907
Capital expenditures,
net $9,489 $85,706 $111,477 $206,672
Depreciation $46,176 $22,035 $21,494 $89,705
———————————————————————
Nine months ended September 30, 2007
———————————————————————
Canada United States International Total
———————————————————————
Revenue $592,884 $416,739 $179,717 $1,189,340
Property and
equipment, net $771,916 $325,535 $284,194 $1,381,645
Capital expenditures,
net $28,390 $141,955 $53,622 $223,967
Depreciation $34,255 $15,201 $15,482 $64,938
———————————————————————
8. Supplemental disclosure of cash flow information
The net change in non-cash working capital for the three and nine
months ended September 30, 2008 and 2007 is determined as follows:
Three months ended Nine months ended
September 30 September 30
2008 2007 2008 2007
—————————————————
Net change in non-cash
working capital
Accounts receivable $(63,440) $(39,649) $(45,216) $82,681
Inventory and other 1,576 (1,026) (649) (7,726)
Accounts payable and
accrued liabilities 33,469 7,521 18,342 (58,481)
Income taxes payable 9,571 11,799 (20,142) (10,292)
Dividends payable 4 1 10 47
—————————————————
$(18,820) $(21,354) $(47,655) $6,229
—————————————————
Relating to
Operating activities $(67,669) $(33,538) $(91,254) $20,400
Investing activities 48,845 12,183 43,589 (14,218)
Financing activities 4 1 10 47
—————————————————
$(18,820) $(21,354) $(47,655) $6,229
—————————————————
—————————————————
9. Capital management strategy
The Company’s objectives when managing capital are to exercise
financial discipline, and to deliver positive returns and stable
dividend streams to its shareholders. The Company’s capital
management strategy remained unchanged during the nine months ended
September 30, 2008; however, the Company continues to be cognizant of
the challenges associated with operating in a cyclical, commodity-
based industry and may make future adjustments to its capital
management strategy in light of changing economic conditions.
The Company considers its capital structure to include shareholders’
equity and operating lines of credit. In order to maintain or adjust
its capital structure, the Company may from time to time adjust its
capital spending or dividend policy to manage the level of its short-
term borrowings, or may revise the terms of its operating lines of
credit to support future growth initiatives. During the nine months
ended September 30, 2008, the Company revised the terms of its
operating lines of credit as described in note 4. As at September 30,
2008, operating lines of credit totalled $114,814 and shareholders’
equity totalled $1,423,459.
The Company is subject to externally imposed capital requirements
associated with its operating lines of credit, including financial
covenants that incorporate shareholders’ equity and level of
indebtedness. As at September 30, 2008, the Company is in compliance
with these requirements.
10. Financial instruments
Fair value
The carrying value of cash and cash equivalents, accounts receivable,
accounts payable and accrued liabilities, operating lines of credit
and dividends payable approximate fair value due to the short-term
nature of these instruments. The carrying value of the promissory
note payable approximates fair value as its interest terms
approximate a market rate of interest.
Credit risk
Credit risk is the risk of financial loss to the Company if a
customer or counterparty to a financial instrument fails to meet its
contractual obligations. Credit risk arises principally from the
Company’s accounts receivable balances owing from customers operating
primarily in the oil and natural gas industry in Canada, the United
States and internationally. The carrying amount of accounts
receivable represents the maximum credit exposure as at September 30,
2008.
The Company assesses the credit worthiness of its customers on an
ongoing basis and considers the credit risk on these amounts normal
for the industry. The Company establishes credit limits for each
customer based on external credit reports, internal analysis and
historical experience with the customer. Credit limits are approved
by senior management and are reviewed on a regular basis or when
changing economic circumstances dictate. The Company also monitors
the amount and age of accounts receivable balances on an ongoing
basis. At September 30, 2008 the Company’s allowance for doubtful
accounts was $629, an increase of $221 from the balance as at
December 31, 2007.
Liquidity risk
Liquidity risk is the risk that the Company will not be able to meets
its financial obligations as they are due. The Company manages
liquidity by forecasting cash flows on an annual basis and secures
sufficient credit facilities to meet financing requirements that
exceed anticipated internally generated funds. As at September 30,
2008, the remaining contractual maturities of accounts payable and
accrued liabilities, operating lines of credit and dividends payable
are less than one year. As at September 30, 2008, the remaining
contractual maturity of the promissory note payable is less than
three years.
Market risk
Market risk is the risk that changes in market prices, such as
foreign exchange rates and interest rates, will affect the Company’s
net income or the value of the financial statements.
Interest rate risk
——————
The Company is exposed to interest rate risk with respect to its
operating lines of credit that bear interest at floating market
rates. For the nine months ended September 30, 2008, if interest
rates applicable to the operating lines of credit had been 1% higher
or lower, with all other variables held constant, net income would
have been $779 higher or lower.
Foreign currency exchange rate risk
———————————–
The Company operates internationally and is exposed to foreign
exchange risk arising from various currency exposures, primarily with
respect to the United States dollar and the Australian dollar. The
principal foreign exchange risk relates to the conversion of the
Company’s self-sustaining subsidiaries from their functional
currencies to Canadian dollars. At September 30, 2008, had the
Canadian dollar weakened or strengthened by $0.01 against the United
States dollar, with all other variables held constant, the Company’s
other comprehensive income would have been approximately $5,500
higher or lower. At September 30, 2008, had the Canadian dollar
weakened or strengthened by $0.01 against the Australian dollar, with
all other variables held constant, the Company’s other comprehensive
income would have been approximately $2,500 higher or lower. The
Company is also exposed to foreign currency exchange rate risk
related to its net United States dollar denominated debt held within
its Australian subsidiary. A $0.01 change in the United States to
Australian dollar exchange rate would have resulted in a change in
net income of approximately $155 at September 30, 2008.
The above sensitivities are limited to the impact of changes in the
specified variable applied to the items noted above and do not
represent the impact of a change in the variable on the operating
results of the Company taken as a whole.
11. Prior period amounts
Certain prior period amounts have been reclassified to conform to the
current period’s presentation.
%SEDAR: 00001999E
For further information: Glenn Dagenais, Executive Vice President
Finance and Chief Financial Officer, (403) 262-1361