15 Mar Ensign Energy Services Inc. Reports 2009 Earnings
CALGARY, March 15 /CNW/ –
Overview
Ensign Energy Services Inc. (“Ensign” or the “Company”) recorded net income of $125.4 million ($0.82 per common share) for the year ended December 31, 2009, a 52 percent decrease from $260.0 million ($1.70 per common share) recorded in 2008. Operating earnings, expressed as EBITDA (defined as earnings before interest, taxes, depreciation, amortization and stock-based compensation), for 2009 were $309.0 million, a 38 percent decrease from EBITDA of $497.1 million for the twelve months ended December 31, 2008. Funds from operations similarly decreased 37 percent to $257.4 million ($1.68 per common share) in 2009 from $406.8 million ($2.66 per common share) in the prior year. The decrease in the Company’s financial results is directly attributable to the impact of the unprecedented global economic crisis that weakened oil and natural gas supply and demand fundamentals for much of the year. The oilfield services industry experienced a significant reduction in demand, particularly in North America, as the exploration and production companies, the Company’s customers, reacted to weak oil and natural gas demand and commodity prices.
Net income of $22.6 million ($0.15 per common share) for the fourth quarter of 2009 decreased 69 percent from net income of $73.8 million ($0.48 per common share) recorded in the fourth quarter of 2008. Net income for the fourth quarter of 2009 was negatively impacted by lower levels of demand for oilfield services and reduced margins resulting from a general over-supply of oilfield service equipment, particularly in North America. Gross margin was 28.8 percent for the fourth quarter of 2009 compared with 29.5 percent in the fourth quarter of 2008. The gross margin was negatively impacted by fourth quarter maintenance expenditures in preparation for the Canadian winter drilling season and reduced margins from United States operations as price reductions associated with contract renegotiations were implemented during the fourth quarter.
Despite the challenging environment, the Company’s established geographic diversification and strong balance sheet allowed it to take advantage of opportunities to continue to grow. The 14 Automated Drill Rig (“ADR(TM)”) and seven well servicing rig new build program that commenced in 2008 was completed in December 2009, continuing the enhancement of the Company’s technical capabilities and bolstering its presence in key markets. Two of the newly constructed ADR(TM)-1500 drilling rigs marked the entry of the Company into the promising Haynesville shale gas play in Louisiana. The Company also took advantage of an opportunity to enter the oilfield services market in Mexico, acquiring FE Services Holdings, Inc. (“Foxxe Energy”) and its fleet of six drilling rigs in December 2009. A total of $185.1 million was spent on acquisitions and the purchase of additional equipment in 2009, down 33 percent from the $274.3 million invested in new equipment in 2008.
The Company increased its quarterly dividend declared in the fourth quarter of 2009 to a rate of $0.0875 per common share, an increase of three percent from the 2009 third quarter rate of $0.0850 per common share. This modest increase maintains the Company’s annual dividend increase trend dating back to the first dividend paid in 1995. Additionally, the Company extinguished its long-term debt in 2009 by the early repayment of a promissory note payable with a face value of $20.0 million. This promissory note was issued in July 2008 in connection with the purchase of 12 specialty drilling rigs and related equipment. The Company utilized existing cash resources to extinguish the debt which bore interest at a rate fixed above current market rates of interest.
Working capital at December 31, 2009 was $107.9 million compared to $107.0 million at December 31, 2008. Positive working capital and no long-term debt means that the balance sheet remains a source of strength for the Company. A strong balance sheet, financial discipline, commitment to safety, geographic diversification and the drive to be a technological leader are the cornerstones of a proven strategy that will enable Ensign to continue to grow opportunistically and generate positive returns throughout the challenges of a cyclical industry.
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FINANCIAL AND OPERATING HIGHLIGHTS
($ thousands, except per share data and operating information)
————————————————————————-
Three months ended Year ended
December 31 December 31
————————————————————————-
% %
2009 2008 change 2009 2008 change
————————————————————————-
Revenue 278,682 460,435 (39) 1,137,575 1,705,579 (33)
————————————————————————-
EBITDA(1) 67,150 113,347 (41) 308,954 497,122 (38)
EBITDA per
share(1)
Basic $ 0.44 $ 0.74 (41) $ 2.02 $ 3.25 (38)
Diluted $ 0.44 $ 0.74 (41) $ 2.02 $ 3.22 (37)
————————————————————————-
Adjusted net
income(2) 21,482 67,805 (68) 131,159 260,731 (50)
Adjusted net
income per
share(2)
Basic $ 0.14 $ 0.44 (68) $ 0.86 $ 1.70 (49)
Diluted $ 0.14 $ 0.44 (68) $ 0.86 $ 1.69 (49)
————————————————————————-
Net income 22,638 73,830 (69) 125,436 259,959 (52)
Net income per
share
Basic $ 0.15 $ 0.48 (69) $ 0.82 $ 1.70 (52)
Diluted $ 0.15 $ 0.48 (69) $ 0.82 $ 1.68 (51)
————————————————————————-
Funds from
operations(3) 57,810 109,558 (47) 257,406 406,775 (37)
Funds from
operations
per share(3)
Basic $ 0.38 $ 0.72 (47) $ 1.68 $ 2.66 (37)
Diluted $ 0.38 $ 0.71 (47) $ 1.68 $ 2.63 (36)
————————————————————————-
Weighted average
shares – basic
(000s) 153,156 153,129 – 153,155 153,095 –
Weighted average
shares –
diluted (000s) 153,312 153,552 – 153,261 154,408 (1)
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Drilling
Number of
marketed
rigs
Canada
Conventional 154 163 (6) 154 163 (6)
Oil sands
coring/
coal-bed
methane 28 28 – 28 28 –
United States 82 75 9 82 75 9
International(4) 58 42 38 58 42 38
Operating days
Canada 4,325 6,072 (29) 13,719 25,581 (46)
United States 2,550 4,670 (45) 9,797 19,986 (51)
International 2,225 2,497 (11) 7,616 9,918 (23)
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Well Servicing
Number of marketed
rigs/units
Canada 112 108 4 112 108 4
United States 18 17 6 18 17 6
Operating hours
Canada 26,334 31,138 (15) 102,341 142,494 (28)
United States 10,551 9,333 13 35,205 37,245 (5)
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(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 plan. 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
plan, 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 ended Year ended
December 31 December 31
——————————————————-
% %
($ thousands) 2009 2008 change 2009 2008 change
————————————————————————-
Revenue
Canada 112,415 180,201 (38) 425,854 742,968 (43)
United States 91,078 181,704 (50) 407,363 635,465 (36)
International 75,189 98,530 (24) 304,358 327,146 (7)
——————————————————-
278,682 460,435 (39) 1,137,575 1,705,579 (33)
Oilfield services
expense 198,347 324,472 (39) 781,021 1,145,884 (32)
——————————————————-
80,335 135,963 (41) 356,554 559,695 (36)
——————————————————-
Gross margin 28.8% 29.5% 31.3% 32.8%
————————————————————————-
Revenue recorded in the fourth quarter of 2009 totaled $278.7 million, a decrease of 39 percent over the fourth quarter of 2008. Revenue recorded in the year ended December 31, 2009 totaled $1,137.6 million, a decrease of 33 percent over the prior year. The reduction in revenues across all segments was a reflection of reduced demand for services attributed to weak commodity prices, a global credit crunch and regional geopolitical issues.
Despite the market turbulence experienced in Canada and throughout the world in 2009, the Company continued to achieve acceptable operating margins of 31.3 percent in 2009 compared with 32.8 percent for the twelve months ended December 31, 2008. In order to protect operating margins during 2009, the Company continued to maintain a highly variable cost structure that allows it to react quickly to changes in market conditions. In addition to maintaining the variable cost structure, several cost control initiatives initiated in prior periods, including improvements in supply chain management, operational consolidations, and a rationalization of the equipment fleet, received increased attention and focus.
As a percentage of revenue, gross margin for the fourth quarter of 2009 fell to 28.8 percent from 29.5 percent for the fourth quarter of 2008. In general, margins were lower as equipment that was idle for much of the second and third quarters received the necessary maintenance in preparation for the Canadian winter drilling season and price reductions associated with contract renegotiations in the Company’s United States segment were implemented during the fourth quarter.
Canadian Oilfield Services
————————–
Three months ended Year ended
December 31 December 31
——————————————————-
% %
2009 2008 change 2009 2008 change
————————————————————————-
Conventional
drilling
and coring
rigs
Opening balance 185 197 191 191
Addition – – – 12
Transfer (3) – (4) –
Decommission/
Disposal – (6) (5) (12)
——————————————————-
Ending balance 182 191 (5) 182 191 (5)
Drilling operating
days 4,325 6,072 (29) 13,719 25,581 (46)
Drilling rig
utilization % 28.8 33.8 20.3 36.5
——————————————————-
Well servicing
rigs/units
Opening balance 112 118 108 116
Addition – – 4 2
Decommission/
Disposal – (10) – (10)
——————————————————-
Ending balance 112 108 4 112 108 4
Well servicing
operating
hours 26,334 31,138 (15) 102,341 142,494 (28)
Well servicing
utilization % 29.8 31.3 26.5 33.7
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The Company recorded revenue of $112.4 million in Canada in the fourth quarter of 2009, a 38 percent decrease from $180.2 million recorded in the fourth quarter of 2008. Canadian revenue was $425.9 million for the year ended December 31, 2009, a 43 percent decrease from $743.0 million recorded in the year ended December 31, 2008. Canada accounted for 40 percent of the Company’s revenue in the fourth quarter of 2009 (2008 – 39 percent); and for 37 percent of the Company’s revenue for 2009 (2008 – 44 percent).
Drilling days recorded by the Canadian segment in the fourth quarter of 2009 decreased by 29 percent from the comparable period of the prior year. For the year ended December 31, 2009, Canadian drilling days decreased 46 percent from the prior year. Similarly, Canadian well servicing hours decreased by 15 percent in the fourth quarter of 2009 and by 28 percent in the year ended December 31, 2009 with respect to the corresponding periods in the prior year.
The overall results for Canada reflect continued weakness resulting from an oversupply of oilfield service equipment in the industry, negatively impacting the utilization and margins in the Canadian market. Although utilization improved during the fourth quarter, the overall competitive conditions will not improve until the underlying oil and natural gas commodity fundamentals improve to a level that encourages additional investment in oil and natural gas development.
During 2009, there were several pockets of the Canadian market where the need for oilfield service equipment remained active. In particular, the Montney and Horn River shale gas plays in northeast British Columbia, the Bakken play in southeast Saskatchewan and the heavy oil areas, where our customers carried on with their longer term development plans.
United States Oilfield Services
——————————-
Three months ended Year ended
December 31 December 31
——————————————————-
% %
2009 2008 change 2009 2008 change
————————————————————————-
Conventional
drilling
rigs
Opening balance 80 75 75 76
Addition 2 1 7 1
Decommission/
Disposal – (1) – (2)
——————————————————-
Ending balance 82 75 9 82 75 9
Drilling operating
days 2,550 4,670 (45) 9,797 19,986 (51)
Drilling rig
utilization % 33.8 67.7 34.3 72.3
————————————————————————-
Well servicing
rigs/units
Opening balance 18 16 17 14
Addition – 1 2 3
Decommission/
Disposal – – (1) –
——————————————————-
Ending balance 18 17 6 18 17 6
Well servicing
operating
hours 10,551 9,333 13 35,205 37,245 (6)
Well servicing
utilization % 63.7 59.7 53.6 66.7
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The Company’s United States operations recorded revenue of $91.1 million in the fourth quarter of 2009, a 50 percent decrease from the $181.7 million recorded in the corresponding period of the prior year. United States revenue was $407.4 million for the year ended December 31, 2009, down 36 percent from revenue of $635.5 million for the year ended 2008. The United States accounted for 33 percent of the Company’s revenue in the fourth quarter of 2009 (2008 – 39 percent); and 36 percent of the Company’s revenue in the current year (2008 – 37 percent). Revenues were lower in 2009 compared with 2008 primarily due to a reduction in drilling demand caused by lower commodity prices beginning in the fourth quarter of 2008 and continuing throughout 2009. For the year ended December 31, 2009, drilling rig utilization hit its lowest level since 2002, as customers delayed or cancelled drilling programs.
The United States industry’s land drilling rig count has recovered approximately 35 percent from its lows experienced in the first half of 2009; however, as at December 31, 2009, the industry continues to operate at approximately 50 percent below the highs of 2008. Weakened market conditions have resulted in reduced margins for the rigs working in the spot market. The number of drilling days recorded by the Company’s United States segment in the fourth quarter of 2009 decreased 45 percent from the same period of the prior year; drilling days for 2009 decreased 51 percent from the prior year. United States well servicing hours in the fourth quarter of 2009 increased 13 percent compared to the same period in the prior year and well servicing hours for the year ended December 31, 2009 were down six percent compared to the year ended December 31, 2008.
In 2009, the Company added seven new ADR(TM) rigs under long-term contracts and two well servicing rigs. Late in 2009, the Company began operating in the unconventional shale gas plays of Haynesville and Marcellus with one rig in each area. A second rig began operating in the Haynesville area in the first quarter of 2010.
Financial contributions generated by the United States oilfield services segment during the year, as converted to Canadian dollars, were negatively impacted from the weakening of the United States dollar relative to the Canadian dollar during this period. The United States/Canadian dollar exchange rate closed 2009 at 1.051, compared with 1.218 at December 31, 2008, a 14 percent decline during the year.
International Oilfield Services
——————————-
Three months ended Year ended
December 31 December 31
——————————————————-
% %
2009 2008 change 2009 2008 change
————————————————————————-
Conventional
drilling
and
workover
rigs
Opening balance 49 44 42 49
Acquisition 6 – 6 –
Addition – – 6 –
Decommission/
Disposal (2) – (7)
Transfer 3 – 4 –
——————————————————-
Ending balance 58 42 38 58 42 38
Drilling operating
days 2,225 2,497 (11) 7,616 9,918 (23)
Drilling rig
utilization % 46.5 64.6 43.4 59.9
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Crude oil prices, the primary driver of international oilfield service activity, recovered significantly in later 2009 following the dramatic decline in late 2008 and early 2009. The crude oil price recovery bodes well for future activity levels, but it alone was not enough to overcome various geopolitical issues influencing the demand for oilfield services in the international segment in 2009.
Drilling days recorded by the Company’s international operations in the quarter ended December 31, 2009 decreased 11 percent from the fourth quarter of 2008, while drilling days recorded in the year ended December 31, 2009 decreased 23 percent from the same period in 2008. The Company’s international operations recorded revenue of $75.2 million in the fourth quarter of 2009, a 24 percent decrease from the $98.5 million recorded in the fourth quarter of 2008. International revenue totaled $304.4 million for the year ended December 31, 2009, a seven percent decrease from $327.1 million in 2008. Consistent with our United States segment, the financial results from our international segment were negatively impacted by the weakening of the United States dollar relative to the Canadian dollar in the 2009 fiscal year, as our international segment uses the United States dollar as its functional currency. The international segment contributed 27 percent of the Company’s revenue in the fourth quarter of 2009 (2008 – 21 percent); and 27 percent of the Company’s revenue in the year ended December 31, 2009 (2008 – 19 percent). The Company’s international operations struggled in a few key areas during the latter half of 2009, as the Company worked through a significant reduction in operating activity in Africa and Latin America. These negative events were partially offset by the expansion of the Company’s international drilling rig fleet in 2009.
During 2009, the Company completed the international component of its new build program that resulted in six new ADRs being successfully deployed into the international market. Additionally, the Company transferred four ADR(TM) rigs from its Canadian fleet to its International operation to capitalize on additional opportunities in existing markets. The financial contributions of these transfers will not be realized until the first half of 2010, but they indicate the advantage of having an already established geographic diversification strategy. On December 31, 2009, the Company acquired Foxxe Energy and its fleet of six relatively new drilling rigs operating in Mexico. The acquisition of Foxxe Energy represents the Company’s entry point into the major land drilling market of Mexico. The Company’s international fleet closed 2009 with a total of 58 marketed drilling and workover rigs, an increase of 16 rigs or 38 percent in the past year.
Depreciation
Three months ended Year ended
December 31 December 31
——————————————————-
% %
($ thousands) 2009 2008 change 2009 2008 change
————————————————————————-
Depreciation 34,857 36,104 (3) 111,015 125,809 (12)
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Depreciation expense totaled $34.9 million for the fourth quarter of 2009 compared with $36.1 million for the fourth quarter of 2008. Annual depreciation expense decreased 12 percent to $111.0 million for the year ended December 31, 2009 compared with $125.8 million for the year ended December 31, 2008. This decrease reflects lower consolidated operating activity levels, partially offset by increased depreciation on higher valued equipment added to the Company’s oilfield services equipment fleet over the course of 2009. Depreciation expense for 2009 included $7.5 million (2008 – $11.3 million) of additional depreciation charges with respect to equipment that has been inactive for a period of 12 consecutive months or more.
General and Administrative Expense
Three months ended Year ended
December 31 December 31
——————————————————-
% %
($ thousands) 2009 2008 change 2009 2008 change
————————————————————————-
General and
administrative 11,063 19,043 (42) 50,884 61,556 (17)
% of revenue 4.0% 4.1% 4.5% 3.6%
————————————————————————-
General and administrative expense decreased 42 percent to $11.1 million (4.0 percent of revenue) for the fourth quarter of 2009 compared with $19.0 million (4.1 percent of revenue) for the fourth quarter of 2008. General and administrative expense decreased 17 percent to $50.9 million (4.5 percent of revenue) for the year ended December 31, 2009 compared with $61.6 million (3.6 percent of revenue) for the year ended December 31, 2008. The reduction in general and administrative expense reflects a reduction in operating activity in 2009 and the efforts of the Company to reduce fixed costs in response to declining market conditions.
Stock-Based Compensation Expense
Three months ended Year ended
December 31 December 31
——————————————————-
% %
($ thousands) 2009 2008 change 2009 2008 change
————————————————————————-
Stock-based
compensation (1,779) (9,269) (81) 8,804 1,188 641
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Stock-based compensation expense arises from the intrinsic value accounting associated with the Company’s stock option plan, whereby the liability associated with stock-based compensation is adjusted for the effect of granting and vesting of employee stock options and changes in the underlying price of the Company’s common shares.
For the quarter ended December 31, 2009, stock-based compensation recovery was $1.8 million compared with a recovery of $9.3 million recorded in the fourth quarter of 2008. These recoveries result from a decline in the price of the Company’s common shares over these periods, net of the impact of additional granting and vesting of stock options.
For the year ended December 31, 2009, stock-based compensation was an expense of $8.8 million compared with an expense of $1.2 million for the year ended December 31, 2008. The closing price of the Company’s common shares was $15.00 at December 31, 2009, compared with $13.22 at December 31, 2008 and $15.25 at December 31, 2007.
Interest Expense
Three months ended Year ended
December 31 December 31
——————————————————-
% %
($ thousands) 2009 2008 change 2009 2008 change
————————————————————————-
Interest 368 1,604 (77) 1,432 7,006 (80)
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Interest expense is incurred on the Company’s utilized balance of operating lines of credit and promissory note payable. During the second quarter of 2009, the Company repaid the principal sum in full and the accrued interest on the promissory note without penalty. The decrease in interest expense for the three and twelve months ended December 31, 2009 compared to the prior year is due to the decline in interest rates and the repayment of the promissory note.
Interest is incurred on the Company’s $200 million global revolving credit facility at prime interest rates or bankers’ acceptance rates/LIBOR plus 0.75 percent.
Other
Three months ended Year ended
December 31 December 31
——————————————————-
% %
($ thousands) 2009 2008 change 2009 2008 change
————————————————————————-
Other 2,122 3,573 (41) (3,284) 1,017 (423)
————————————————————————-
This amount consists primarily of foreign exchange gains and losses on the conversion of the Australian operations from Australian dollars to United States dollars as the Australian currency has strengthened during 2009 but weakened against the United States dollar during 2008.
Income Taxes
Three months ended Year ended
December 31 December 31
——————————————————-
% %
($ thousands) 2009 2008 change 2009 2008 change
————————————————————————-
Current income
tax 5,991 2,002 199 38,910 74,887 (48)
Future income
tax 5,075 9,076 (44) 23,357 28,273 (17)
——————————————————-
11,066 11,078 – 62,267 103,160 (40)
——————————————————-
Effective income
tax rate (%) 32.8% 13.0% 33.2% 28.4%
————————————————————————-
The effective income tax rate for the fourth quarter of 2009 was 32.8 percent compared with 13.0 percent for the fourth quarter of 2008. For the twelve months ended December 31, 2009, the effective income tax rate was 33.2 percent compared with 28.4 percent for the twelve months ended December 31, 2008.
The increase in the Company’s effective income tax rate on a period-over-period basis is due to a greater proportion of taxable income being generated by the Company’s United States operations, which has a higher effective income tax rate.
The lower effective income tax rate in 2008 is largely due to additional deductions available to the Company’s United States subsidiaries, namely a domestic production deduction available to companies engaged in qualified activities. Additional guidance issued by the tax authorities in 2008 confirmed that the drilling of crude oil and natural gas wells performed by the Company was a qualified activity and that the Company was therefore entitled to an additional income tax deduction. This deduction was claimed for the year ended December 31, 2008. As well, income tax returns for the years 2005 through 2007 were amended and re-filed in order to claim the deduction for those periods. The benefit of these deductions was reflected as a reduction in current income tax expense in the fourth quarter of December 31, 2008.
Financial Position
The following chart outlines significant changes in the consolidated balance sheet from December 31, 2008 to December 31, 2009:
($ thousands) Change Explanation
————————————————————————-
Cash and cash equivalents 39,248 See consolidated statement of
cash flows.
————————————————————————-
Accounts receivable (118,134) Decrease due to a decrease in
operating activity levels in the
fourth quarter of 2009 compared
with the fourth quarter of 2008.
————————————————————————-
Income taxes recoverable (4,424) Decrease due to the current
income tax provision for the
period, net of tax instalments.
————————————————————————-
Inventory and other 207 Increase due to the acquisition
of Foxxe Energy at year-end off
set by the normal course use of
consumables and spare parts.
————————————————————————-
Property and equipment (35,437) Decrease due to increased
depreciation on higher-value
equipment and the impacts of
foreign exchange fluctuations on
the consolidation of the
Company’s foreign self-sustaining
subsidiaries.
————————————————————————-
Long-term note receivable 7,607 Increase due to sale of non-core
oilfield equipment during fourth
quarter of 2009.
————————————————————————-
Accounts payable and (82,424) Decrease due to a decrease in
accrued liabilities operating activity levels in the
fourth quarter of 2009 compared
with the fourth quarter of 2008.
————————————————————————-
Operating lines of credit (439) Decrease due to net repayments of
the operating lines of credit.
————————————————————————-
Promissory note payable (20,000) Decrease due to payment of the
promissory note in June 2009.
————————————————————————-
Stock-based compensation (2,872) Decrease due to the exercise of
employee stock options during
the year offset by an increase
in the price of the Company’s
common shares as at December 31,
2009 compared with December 31,
2008.
————————————————————————-
Dividends payable 387 Increase due to a three percent
increase in the fourth quarter
dividend rate and a slight
increase in the number of
outstanding common shares
during 2009.
————————————————————————-
Future income taxes 14,769 Increase primarily due to the
acquisition of Foxxe Energy.
————————————————————————-
Shareholders’ equity (20,354) Decrease due to the net income
for the period being offset by
the impact of foreign exchange
rate fluctuations on net assets
of foreign self-sustaining
subsidiaries and the amount of
dividends declared in the period.
————————————————————————-
Funds from Operations and Working Capital
Three months ended Year ended
December 31 December 31
——————————————————-
% %
($ thousands) 2009 2008 change 2009 2008 change
————————————————————————-
Funds from
operations 57,810 109,558 (47) 257,406 406,775 (37)
Funds from
operations per
share $0.38 $0.72 (47) $1.68 $2.66 (37)
Working capital 107,894 107,024 1 107,894 107,024 1
————————————————————————-
During the three months ended December 31, 2009, the Company generated funds from operations of $57.8 million ($0.38 per common share) compared with funds from operations of $109.6 million ($0.72 per common share) for the three months ended December 31, 2008, a decrease of 47 percent. Funds from operations totaled $257.4 million ($1.68 per common share) in the year ended December 31, 2009, a decrease of 37 percent compared to $406.8 million of funds from operations ($2.66 per common share) generated in the year ended December 31, 2008.
The decrease in funds from operations in both the three months and the year ended December 31, 2009 compared to the corresponding periods of 2008 are the result of the continued deterioration of oilfield services market conditions, primarily in the Company’s Canadian and United States segments, resulting in lower activity levels compared to the prior year. Further, the Company’s international operations experienced a reduction in contributions from its Latin American operations in the latter half of 2009 as all of the drilling rigs in Venezuela were stacked pending further negotiations with a major customer. The decline in operating activity is slightly offset by contributions from the newly constructed ADRs placed in operation in the United States and international markets under term contracts in 2009.
Despite what may have been the most challenging year in recent memory for the oilfield services industry, the Company exited the year with a strong balance sheet with working capital of $107.9 million and no long-term debt. Cash and cash equivalents totaled $135.2 million as at December 31, 2009, an increase of $39.2 million from the cash and cash equivalents balance as at December 31, 2008. The Company’s strong cash position and existing credit facilities are expected to adequately support its future operations and capital expansion initiatives. Existing credit facilities provide for total borrowings of $210.0 million, of which $26.8 million was available as at December 31, 2009.
Investing Activities
Three months ended Year ended
December 31 December 31
——————————————————-
% %
($ thousands) 2009 2008 change 2009 2008 change
————————————————————————
Acquisitions (52,573) – (100) (52,573) – (100)
Net purchase of
property and
equipment (14,921) (87,651) (83) (132,573) (274,323) (52)
Net change in
non-cash working
capital 12,242 (8,304) (247) 9,683 35,285 (73)
——————————————————-
Cash used in
investing
activities (55,252) (95,955) (42) (175,463) (239,038) (27)
————————————————————————-
Effective December 31, 2009, the Company completed a corporate acquisition by acquiring all of the issued and outstanding shares of Foxxe Energy. The purchase of Foxxe Energy was funded with existing cash balances and credit facilities.
Net purchases of property and equipment during the fourth quarter of 2009 totaled $14.9 million (2008 – $87.7 million). In the fourth quarter, the Company sold its camp and related assets for $17.8 million for which the Company received $7.9 million in cash and a non-interest bearing promissory note for $9.9 million. The promissory note includes annual minimum re-payments of $1.0 million with a lump sum payment of the balance on or before December 4, 2015.
Net purchases of property and equipment for the year ended December 31, 2009 totaled $132.6 million compared with $274.3 million for the year ended December 31, 2008. The net purchase of property and equipment relates predominantly to expenditures pursuant to the completion of the Company’s most recent new build program as all other non-critical capital expenditures were tightly controlled or suspended during 2009.
Significant additions to the Company’s oilfield services equipment fleet in 2009 include:
– Construction of two well servicing rigs in the United States in the
first quarter;
– Construction of six ADR(TM) drilling rigs in the Middle East and
Africa, two in the first quarter and four in the second;
– Construction of seven ADR(TM) drilling rigs in the United States, one
in each of the first and second quarters, three in the third quarter
and two in the fourth quarter;
– Acquisition of Canadian wireline assets in the third quarter;
– Construction of four well servicing rigs in Canada in the third
quarter and;
– Acquisition of six drilling rigs and related equipment in Mexico in
the fourth quarter.
Financing Activities
Three months ended Year ended
December 31 December 31
——————————————————-
% %
($ thousands) 2009 2008 change 2009 2008 change
————————————————————————-
Net increase
(decrease) in
operating lines
of credit 34,456 54,629 (37) (439) 51,474 (101)
Repayment of
promissory note
payable – – – (20,000) – –
Issue of capital
stock 709 115 517 977 1,014 (4)
Dividends (13,403) (13,016) 3 (52,456) (50,905) 3
Net change in
non-cash working
capital 384 383 – 387 393 (2)
——————————————————-
Cash used in
financing
activities 22,146 42,111 (47) (71,531) 1,976 (3,720)
————————————————————————-
Net repayments of the operating lines of credit were the result of operating cash flows generated by the Company’s Canadian and United States oilfield services divisions in excess of capital expenditure requirements. As of December 31, 2009, the operating lines of credit are primarily being used to fund the completion of the most recent new build program and to support international operations.
The Company’s available operating lines of credit consist of a $200 million global revolving credit facility (the “Global Facility”) and a $10 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 $10 million or the equivalent United States dollars.
During the third quarter of 2008, the Company issued a promissory note payable in the amount of $20.0 million in connection with the purchase of 12 specialty drilling rigs and related equipment. The $20.0 million promissory note was paid in full during the second quarter of 2009. Currently, the Company has no long-term debt. Other financing activities during the year ended December 31, 2009 include the receipt of $1.0 million (2008 – $1.0 million) on the exercise of employee stock options and dividends declared totaled $52.5 million (2008 – $50.9 million).
In the fourth quarter of 2009, the Company increased its quarterly dividend rate to $0.0875 per common share, a three percent increase over the dividend of $0.0850 per common share declared for the fourth quarter of 2008. During the year ended December 31, 2009, the Company declared dividends of $0.3425 per common share, an increase of three percent over dividends of $0.3325 per common share declared in 2008. 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 (“ITA”).
The Board of Directors of the Company has declared a first quarter dividend of $0.0875 per common share to be payable April 2, 2010 to all Common Shareholders of record as of March 26, 2010. The dividend is pursuant to the quarterly dividend policy adopted by the Company. Pursuant to subsection 89(1) of the ITA, the dividend being paid is designated as an eligible dividend, as defined in subsection 89(1) of the ITA.
New Builds
The 14 ADR(TM) and seven well servicing rig new build program that commenced in 2008 was completed in December 2009. Of the 14 ADRs included in the construction program, two are ADR(TM)-250 models, two are ADR(TM)-300 models, four are ADR(TM)-350 models, four are ADR(TM)-1000 models, and two are ADR(TM)-1500 models. The well servicing rig new build program consisted of seven well servicing rigs: four in the Canadian market and three in the United States market.
In anticipation of continued opportunities for new oilfield services equipment to meet the growing technical demands of the exploration and production companies, the Company has commenced a 2010 new build program that will result in six new ADR(TM)-1500 model drilling rigs being constructed for delivery starting in early 2011.
Outlook
As expected, the 2009 fiscal year contained many challenges for the oilfield services industry. Weakening global economic conditions reduced the levels of demand for oil and natural gas as witnessed by the sharp decline in commodity prices from the recent highs experienced in 2008. Additionally, the tightening of credit availability created challenges for many of the Company’s customers as they struggled through a period of reduced levels of cash flows. The Company’s strong balance sheet, financial discipline and established geographic diversification enabled it to weather the storm better than most oilfield services companies. Indeed, the Company was able to continue to take advantage of opportunities to grow through this very difficult year for the industry. While oil prices have recovered from their lows of 2009 and natural gas prices have stabilized somewhat, the feeling persists that there are still many challenges ahead before we can claim to be in a period of recovery. The Company expects that 2010 will be another challenging year for the industry as oil and, particularly, natural gas prices, being the ultimate driving force of the North American energy industry, remain volatile as general economic conditions continue on the rocky road to recovery. While it is still too early to declare an end to the global malaise, it appears that the worst may be behind us.
The Company’s Canadian operations have had a decent start to the year, with winter 2010 utilization being slightly better than expected, particularly for the deeper drilling rig classes. However, financial contributions from Canada in 2010 are expected to be reduced from the prior year as margins for the winter drilling season reflect revenue rates associated with the lower levels of demand for oilfield services that persisted through much of 2009. Generally speaking, the Company will not be in a position to improve margins until the demand for oilfield services increases meaningfully from current levels. Revenue rates always drop faster than they rise. While the first quarter activity levels are slightly improved over expectations, there remains much uncertainty with respect to the rest of the year. The oil plays and certain natural gas shale plays are expected to contribute reasonable levels of demand for oilfield services through the remainder of the year, but conventional natural gas plays, the bread and butter of the industry, are expected to remain weak against a backdrop of unfavorable natural gas supply and demand fundamentals. The recent modifications to the royalty framework announced by the Government of Alberta should help to improve the competitive conditions in the largest oil and natural gas producing province in Canada. The extension of the current incentive program for new natural gas and conventional oil wells; and the reduction in the maximum royalty rates applicable to natural gas and conventional oil production have the goal of attracting investment dollars back to Alberta. Until there is a rebalancing of supply and demand, a prospect normally fixed by market reaction to commodity price changes but now complicated by the impact of favorable economics of natural gas shale plays, the Canadian oilfield services industry will remain challenged to improve levels of profitability.
The Company’s United States operations also started the 2010 fiscal year better than expected, bolstered by the positive impact from the completion of the Company’s most recent new build program that resulted in seven new ADR(TM) drilling rigs and two new well servicing rigs being added to the Company’s United States fleet of equipment in 2009. Additionally, the Company was able to modestly improve its margins on operating equipment in the face of better than expected levels of demand for certain equipment classes. While the margins remain below peak levels attained within the last couple of years, the slight improvements indicate the level of customer acceptance and demand for the Company’s newer high technology drilling rig fleet. This technology has been developed and proven in the natural gas resource plays of the Rocky Mountain region and is quickly showing its advantages in key natural gas shale plays of the United States. The Company only recently moved two ADR(TM)-1500 drilling rigs into the Haynesville shale play of the southern United States and is already moving faster and drilling deeper than most other drilling rigs in the area. The Company has also recently established a presence in the Marcellus shale play by moving ADR(TM) drilling technology and production testing equipment into the area. The Company believes there are additional opportunities for advanced technology equipment in these shale plays and will develop them over time. The challenge, as with Canada, will be to effectively and efficiently manage the total equipment fleet until natural gas fundamentals improve to levels that increase the demand for oilfield services in all equipment classes.
The six new ADR(TM) drilling rigs added to the Company’s international drilling rig fleet through the course of 2009 will improve the financial contribution from the Company’s international operations in 2010. The majority of international operations are subject to longer term contracts and are, generally, driven by crude oil supply and demand fundamentals. Crude oil prices have recovered from their lows of 2009 and are now within a range that should continue to drive activity in many international energy producing regions. That being said, there remain many geopolitical challenges that vary from region to region. The most challenging region for the Company currently is Latin America as individual countries struggle with the direction and pace of the future development of their natural resources. Against this backdrop, the Company most recently entered the Mexican oilfield services market with the acquisition of a six drilling rig operation. The Company believes that Mexico will have some short-term challenges, but the acquisition was done with an eye to the long-term growth potential for this major oil producing country. The biggest challenge faced by the Company’s international operations in 2009 occurred in Venezuela, where operations were halted mid-year pending the resolution of certain contractual issues. Since the start of the year, there has been considerable progress in resolving these issues and the Company is expecting resumption of operations in Venezuela before the end of the first quarter of the 2010 fiscal year.
The Company believes that the 2010 fiscal year will continue to be filled with many challenges and opportunities. Until general economic conditions meaningfully improve, there will continue to be much uncertainty around oil and natural gas supply and demand fundamentals as reflected in volatile oil and natural gas commodity prices, the key drivers influencing the demand for oilfield services. There will also continue to be opportunities for new oilfield services equipment to meet the growing technical demands of the exploration and production companies as they further develop new resource plays. In this regard, the Company has commenced a 2010 new build program that will result in six new ADR(TM)-1500 style drilling rigs being constructed for delivery starting in early 2011. While no specific regions have been targeted for these new builds, the new rigs will likely be contracted for natural gas shale plays within North America before the construction of the new ADRs is completed. The Company’s balance sheet strength will be used to finance the construction of the new ADRs and other growth opportunities that are expected to evolve during these interesting times for the oilfield services industry.
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 year-end 2009 results at 2:00 p.m. MDT (4:00 p.m. EDT) on Monday, March 15, 2010. The conference call number is (647) 427-7450 (in Toronto) or 1-888-231-8191 (outside Toronto). A taped recording will be available until March 22, 2010 by dialing 1-416-849-0833 (in Toronto) or 1-800-642-1687 (outside Toronto) and entering the reservation number 58571742. 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
(Unaudited, in thousands of Canadian dollars)
As at December 31
2009 2008
————- ————-
Assets
Current assets
Cash and cash equivalents $ 135,153 $ 95,905
Accounts receivable 242,352 360,486
Income taxes recoverable 6,426 10,850
Inventory and other 61,031 60,824
Future income taxes 377 1,040
—————————
445,339 529,105
Property and equipment 1,675,144 1,710,581
Long-term note receivable 7,607 –
—————————
$ 2,128,090 $ 2,239,686
—————————
—————————
Liabilities
Current liabilities
Accounts payable and accrued liabilities $ 153,660 $ 236,084
Operating lines of credit 169,004 169,443
Current portion of stock-based compensation 1,378 3,538
Dividends payable 13,403 13,016
—————————
337,445 422,081
Promissory note payable – 20,000
Stock-based compensation 391 1,103
Future income taxes 259,457 245,351
—————————
597,293 688,535
—————————
Shareholders’ Equity
Capital stock 170,932 169,485
Accumulated other comprehensive loss (96,364) (1,583)
Retained earnings 1,456,229 1,383,249
—————————
1,530,797 1,551,151
—————————
$ 2,128,090 $ 2,239,686
—————————
—————————
CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS
(Unaudited, in thousands of Canadian dollars – except per share data)
Three months ended Year ended
December 31 December 31
2009 2008 2009 2008
————- ————- ————- ————-
Revenue
Oilfield services $ 278,682 $ 460,435 $ 1,137,575 $ 1,705,579
Expenses
Oilfield services 198,347 324,472 781,021 1,145,884
Depreciation 34,857 36,104 111,015 125,809
General and
administrative 11,063 19,043 50,884 61,556
Stock-based
compensation (1,779) (9,269) 8,804 1,188
Interest 368 1,604 1,432 7,006
Other 2,122 3,573 (3,284) 1,017
————- ————- ————- ————-
244,978 375,527 949,872 1,342,460
————- ————- ————- ————-
Income before
income taxes 33,704 84,908 187,703 363,119
Income taxes
Current 5,991 2,002 38,910 74,887
Future 5,075 9,076 23,357 28,273
————- ————- ————- ————-
11,066 11,078 62,267 103,160
————- ————- ————- ————-
Net income 22,638 73,830 125,436 259,959
Retained
earnings –
beginning of
period 1,446,994 1,322,435 1,383,249 1,174,195
Dividends (13,403) (13,016) (52,456) (50,905)
————- ————- ————- ————-
Retained
earnings –
end of period $ 1,456,229 $ 1,383,249 $ 1,456,229 $ 1,383,249
————- ————- ————- ————-
————- ————- ————- ————-
Net income per
share
Basic $ 0.15 $ 0.48 $ 0.82 $ 1.70
Diluted $ 0.15 $ 0.48 $ 0.82 $ 1.68
————- ————- ————- ————-
————- ————- ————- ————-
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited, in thousands of Canadian dollars)
Three months ended Year ended
December 31 December 31
2009 2008 2009 2008
————- ————- ————- ————-
Cash provided by
(used in)
Operating
activities
Net income for
the period $ 22,638 $ 73,830 $ 125,436 $ 259,959
Items not
affecting cash:
Depreciation 34,857 36,104 111,015 125,809
Stock-based
compensation,
net of cash
paid (4,760) (9,452) (2,402) (7,266)
Future income
taxes 5,075 9,076 23,357 28,273
————- ————- ————- ————-
57,810 109,558 257,406 406,775
Net change in
non-cash working
capital (32,544) (15,506) 28,836 (75,748)
————- ————- ————- ————-
25,266 125,064 286,242 331,027
————- ————- ————- ————-
Investing
activities
Acquisition (52,573) – (52,573) –
Net purchase of
property and
equipment (14,921) (87,651) (132,573) (274,323)
Net change in
non-cash working
capital 12,242 (8,304) 9,683 35,285
————- ————- ————- ————-
(55,252) (95,955) (175,463) (239,038)
————- ————- ————- ————-
Financing
activities
Net decrease
(increase)
in operating
lines of credit 34,456 54,629 (439) 51,474
Repayment of
promissory note – – (20,000) –
Issue of capital
stock 709 115 977 1,014
Dividends (13,403) (13,016) (52,456) (50,905)
Net change in
non-cash working
capital 384 383 387 393
————- ————- ————- ————-
22,146 (42,111) (71,531) 1,976
————- ————- ————- ————-
Increase (decrease)
in cash and cash
equivalents
during the period (7,840) 71,220 39,248 93,965
Cash and cash
equivalents –
beginning of
period 142,993 24,685 95,905 1,940
————- ————- ————- ————-
Cash and cash
equivalents –
end of period $ 135,153 $ 95,905 $ 135,153 $ 95,905
————- ————- ————- ————-
————- ————- ————- ————-
Supplemental
information
Interest paid $ 543 $ 1,879 $ 2,332 $ 7,464
Income taxes paid $ 12,880 $ 11,975 $ 43,334 $ 105,002
————- ————- ————- ————-
————- ————- ————- ————-
For further information: Glenn Dagenais, Executive Vice President Finance and Chief Financial Officer, (403) 262-1361