Ensign Energy Services Inc. Reports 2015 Results

CALGARY, March 8, 2016 /CNW/ -

OVERVIEW

The Company's revenue for the year ended December 31, 2015 was $1,391.0 million, a 40 percent decrease from 2014 revenue of $2,321.8 million, which was the highest in the Company's history. Operating earnings, expressed as Adjusted EBITDA, for 2015 were $321.1 million ($2.11 per common share), a 40 percent decrease from Adjusted EBITDA of $537.5 million ($3.52 per common share) for the year ended December 31, 2014.

Net loss for the year ended December 31, 2015 was $104.0 million ($0.68 per common share), compared with net income of $71.1 million ($0.47 per common share) recorded in 2014. The reduction in net income in 2015 was due to lower operating activity and an increase in depreciation expense. Excluding the tax-effected impact of asset decommissioning and write-downs, share-based compensation and foreign exchange and other, Adjusted net loss for the year ended December 31, 2015 totaled $35.4 million ($0.23 per common share), compared with Adjusted net income of $148.6 million ($0.97 per common share) recorded for the year ended December 31, 2014. Funds from operations for 2015 decreased 40 percent to $296.3 million ($1.94 per common share) from $491.9 million ($3.22 per common share) in the prior year.

During the fourth quarter of 2015, the Company generated revenue of $283.9 million, a decrease of 53 percent from revenue of $602.7 million recorded in the fourth quarter of 2014.  Adjusted EBITDA was $72.3 million ($0.47 per common share) for the fourth quarter of 2015, a decrease of 49 percent from Adjusted EBITDA of $143.0 million ($0.94 per common share) recorded in the fourth quarter of 2014. The Company recorded a net loss of $41.2 million ($0.26 per common share) for the fourth quarter of 2015 compared to a net loss of $31.0 million ($0.20 per common share) for the fourth quarter of 2014.

Adjusted net loss for the fourth quarter of 2015 totaled $31.4 million ($0.20 per common share), compared with Adjusted net income of $44.2 million ($0.29 per common share) recorded in the fourth quarter of 2014. Funds from operations were $48.9 million ($0.31 per common share) for the fourth quarter of 2015, a 63 percent decrease from $132.3 million ($0.87 per common share) recorded in the fourth quarter of 2014.

The Company's decreased operating and financial results for the 2015 fiscal year resulted from a continued decline in oil prices that began in the second half of 2014. Falling energy commodity prices adversely impact the current and future cash flows of the Company's customers and, as a result, the expected levels of future demand for oilfield services, particularly in North America.

Financial results from the Company's United States and international operations improved on translation to Canadian dollars due to the strengthening of the United States dollar relative to the Canadian dollar. For the year ended December 31, 2015 a 16 percent increase in the Canadian/United States dollar exchange rate positively impacted revenues and margins generated outside Canada. Furthermore, additions to the Company's global fleet helped to mitigate the overall decrease in activity levels by adding more technologically advanced rigs that earn higher revenue rates.

The financial results for the year ended December 31, 2015 were negatively impacted by a $28.3 million non-cash charge for asset decommissioning and write-downs recorded by the Company in the third quarter of 2015. Oilfield service equipment has a finite life and, accordingly, asset decommissionings are a normal occurrence for an oilfield service company. The current uncertain market conditions resulting from lower oil and gas commodity prices prompted the Company to take a closer look at its equipment fleet. As a result of a detailed review, the Company reduced its marketed equipment fleet in the fourth quarter of 2015 by decommissioning 21 drilling rigs and two well servicing rigs. Furthermore, the Company wrote down five drilling rigs in Latin America in the third quarter. In accordance with its long standing practice, the Company will retain useful components from the decommissioned rigs for use in its current and future operations. The majority of the non-cash charge associated with the asset decommissioning and write downs in 2014 relate to the write-down of certain drilling rigs to their recoverable value.

In 2015 the Company added eight new Automated Drill Rigs ("ADR®") to its drilling rig fleet: five in the Canadian market and three in the United States market. All of the newly constructed ADRs are subject to long-term contracts. The new build program also added one new well servicing rig in Canada and two new well servicing rigs in the United States.

The Company declared total dividends of $0.48 per common share in 2015.

The Company exited 2015 with a working capital balance of $144.2 million, compared to a working capital balance of $189.7 million as at December 31, 2014. The decrease in working capital year-over-year was mainly related to reduced operating activities by the Company in 2015.

FINANCIAL AND OPERATING HIGHLIGHTS

(Unaudited, in thousands of Canadian dollars, except per share data and operating information)



Three months ended December 31


Twelve months ended December 31


2015


2014


% change


2015


2014


% change

Revenue



283,887


602,691


(53)



1,390,978



2,321,765


(40)

Revenue, net of third party 1



252,592


521,713


(52)



1,234,775



2,013,035


(39)

Adjusted EBITDA 2



72,314


143,012


(49)



321,095



537,513


(40)

Adjusted EBITDA per share 2


















Basic


$

0.47


$

0.94


(50)


$

2.11


$

3.52


(40)


Diluted


$

0.47


$

0.94


(50)


$

2.11


$

3.51


(40)

Adjusted net income (loss) 3



(31,437)



44,181


-



(35,409)



148,567


-

Adjusted net income (loss) per share 3


















Basic


$

(0.20)


$

0.29


-


$

(0.23)


$

0.97


-


Diluted


$

(0.20)


$

0.29


-


$

(0.23)


$

0.97


-

Net income (loss)



(41,175)



(31,038)


33



(104,049)



71,120


-

Net income (loss) per share


















Basic


$

(0.26)


$

(0.20)


30


$

(0.68)


$

0.47


-


Diluted


$

(0.26)


$

(0.20)


30


$

(0.68)


$

0.46


-

Funds from operations 4



48,905



132,257


(63)



296,273



491,886


(40)

Funds from operations per share 4


















Basic


$

0.31


$

0.87


(64)


$

1.94


$

3.22


(40)


Diluted


$

0.31


$

0.86


(64)


$

1.94


$

3.21


(40)

Weighted average shares - basic (000s)



152,436



152,621




152,477



152,711


Weighted average shares - diluted (000s)



152,436



152,932




152,477



153,158


Drilling


2015


2014


% change


2015



2014


% change


Number of rigs



















Canada 5



83



88


(6)



83



88


(6)



United States



89



95


(6)



89



95


(6)



International 6



50



56


(11)



50



56


(11)


Operating days



















Canada 5



1,607



3,633


(56)



6,999



14,440


(52)



United States



2,417



5,860


(59)



11,895



23,577


(50)



International 6



1,914



2,649


(28)



8,553



11,339


(25)

Well Servicing


2015


2014


% change


2015


2014


% change


Number of rigs



















Canada



72



71


1



72



71


1



United States



44



45


(2)



44



45


(2)


Operating hours



















Canada



15,854



31,286


(49)



63,426



125,022


(49)



United States



20,192



29,446


(31)



78,586



120,939


(35)

1.

Revenue, net of third party is defined as "gross revenue less third party reimbursable items".

2.

Adjusted EBITDA is defined as "income before interest, income taxes, depreciation, asset decommissioning and write-downs, share-based compensation and foreign exchange and other". Management believes that, in addition to net income, Adjusted EBITDA is a useful supplemental measure as it provides 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, how the results are impacted by foreign exchange or how the results are impacted by the accounting standards associated with the Company's share-based compensation plans. Adjusted EBITDA and Adjusted EBITDA per share are not recognized measures under International Financial Reporting Standards and thus may not be comparable to measures used by other companies.

3.

Adjusted net income (loss) is defined as "net income (loss) before asset decommissioning and write-downs, share-based compensation and foreign exchange and other, tax-effected using the expected income tax rate for each item or an estimate of 35 percent". Management believes that, in addition to net income (loss), Adjusted net income (loss) is a useful supplemental measure as it provides an indication of the results generated by the Company's principal business activities prior to consideration of how the results are impacted by non-cash charges for equipment write-downs, how the results are impacted by foreign exchange and how the results are impacted by the accounting standards associated with the Company's share-based compensation plans, net of income taxes. Adjusted net income (loss) and Adjusted net income (loss) per share are not recognized measures under International Financial Reporting Standards and thus may not be comparable to measures used by other companies.

4.

Funds from operations are defined as "cash provided by operating activities before the change in non-cash working capital". Management believes that, in addition to net income (loss), funds from operations constitute a measure that provides additional information regarding the Company's liquidity and its ability to generate funds to finance its operations. Management utilizes this measure 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 International Financial Reporting Standards and thus may not be comparable to similar measures used by other companies.

5.

Excludes coring rigs. Includes coring drilling days in Q1, 2015.

6.

Includes workover rigs.

2015 HIGHLIGHTS

  • Revenue for 2015 was $1,391.0 million, a 40 percent decrease from 2014 revenue of $2,321.8 million.
  • Revenue by geographic area:
    • Canada - $307.0 million, 22 percent;
    • United States - $609.3 million, 44 percent; and
    • International - $474.7 million, 34 percent.
  • Canadian drilling (including coring days in Q1) recorded 6,999 operating days in the 2015, a 52 percent decrease from 14,440 operating days in 2014. Canadian well servicing recorded 63,426 operating hours in 2015, a 49 percent decrease from 125,022 operating hours in 2014.
  • United States drilling recorded 11,895 operating days in 2015, a 50 percent decrease from 23,577 operating days in 2014. United States well servicing recorded 78,586 operating hours in 2015, a 35 percent decrease from 120,939 operating hours in 2014.
  • International drilling recorded 8,553 operating days in 2015, a 25 percent decrease from 11,339 operating days recorded in 2014.
  • Adjusted EBITDA for 2015 was $321.1 million, a 40 percent decrease from Adjusted EBITDA of $537.5 million for 2014. Funds from operations for 2015 decreased 40 percent to $296.3 million from $491.9 million in the year prior.
  • Five new ADR® drilling rigs were added to the Company's Canadian equipment fleet and three new ADR® drilling rigs were added to the United States fleet in 2015. The Company also added three new well servicing rigs to its fleet: one in Canada and two in the United States.
  • The Company decommissioned a total of 24 drilling and workover rigs as well as three well servicing rigs during the year.
  • The Company's new build program at December 31, 2015 consisted of one new ADR® drilling rig scheduled for delivery by the end of the Q1, 2016.
  • The Company declared a first quarter cash dividend on common shares of $0.1200 per common share payable April 5, 2016. The Company declared total dividends of $0.4800 per common share in 2015.

REVENUE AND OILFIELD SERVICES EXPENSE


Three months ended December 31


Twelve months ended December 31

($ thousands)

2015



2014



% change



2015



2014



% change


Revenue













Canada

61,803



167,210



(63)



306,997



666,095



(54)



United States

132,102



271,985



(51)



609,301



1,026,605



(41)



International

89,982



163,496



(45)



474,680



629,065



(25)


Total revenue

283,887



602,691



(53)



1,390,978



2,321,765



(40)














Revenue, net of third party

252,592



521,713



(52)



1,234,775



2,013,035



(39)














Oilfield services expense

195,076



433,080



(55)



995,025



1,686,395



(41)


Gross margin

88,811



169,611



(48)



395,953



635,370



(38)


Gross margin as a percentage of revenue, net of third party

35.2



32.5





32.1



31.6




 

Revenue for the year ended December 31, 2015 totaled $1,391.0 million, a 40 percent decrease from the previous year of $2,321.8 million. This was a direct result of the decline in oil and natural gas commodity prices that began in the second half of 2014 and continued throughout 2015. Reduced demand for oilfield services resulted in lower equipment utilization rates and revenue rates in 2015 compared to 2014. The Company recorded revenue of $283.9 million for the three months ended December 31, 2015, a 53 percent decrease from the $602.7 million recorded in the three months ended December 31, 2014.

Financial results from the Company's United States and international operations were positively impacted upon translation, as the stronger United States dollar relative to the Canadian dollar in 2015 served to reduce the impact of some of the revenue rate declines experienced during the year.

Revenue, net of third party, for the year ended December 31, 2015 totaled $1,234.8 million, a decrease of 39 percent from the previous year of $2,013.0 million. Revenue, net of third party, for the three months ended December 31, 2015 decreased 52 percent to $252.6 million from $521.7 million in the fourth quarter of 2014.

As a percentage of revenue, net of third party, gross margin was essentially unchanged year-over-year at 32 percent. For the three months ended December 31, 2015 gross margin as a percentage of revenue, net of third party, increased to 35 percent from 33 percent. As a result of weaker commodity prices, the Company has reduced its operating cost structure by obtaining vendor discounts and making changes to its administrative and supervisory structure.

In addition to gross margin as a percentage of revenue, gross margin as a percentage of revenue, net of third party, can be more effective in showing the Company's performance based on activity levels, as third party items, if significant, may reduce margin comparability between periods.

CANADIAN OILFIELD SERVICES


Three months ended December 31


Year ended December 31



2015


2014


% change


2015


2014


% change


Drilling rigs







Opening balance

90


103



88


121





Additions

1


1



5


1





Transfers

1


2




(2)





Decommissions/Disposals

(9)


(18)



(10)


(32)





Ending balance

83


88


(6)


83


88


(6)


Drilling operating days 1

1,607


3,633


(56)


6,999


14,440


(52)


Drilling rig utilization (%) 1

19.9


40.3


(51)


21.5


38.7


(44)


Well servicing rigs







Opening balance

72


92



71


95





Additions




1


1





Decommissions/Disposals


(21)




(25)





Ending balance

72


71



72


71


1


Well servicing operating hours

15,854


31,286


(49)


63,426


125,022


(49)


Well servicing utilization (%)

23.9


40.0


(40)


24.2


38.2


(37)


1.  Excludes coring rigs.  Includes coring drilling days in Q1, 2015

The Company recorded revenue of $307.0 million in Canada for the year ended December 31, 2015, a decrease of 54 percent from $666.1 million recorded for the year ended December 31, 2014. Revenue generated in Canada decreased 63 percent to $61.8 million for the three months ended December 31, 2015, from $167.2 million for the three months ended December 31, 2014.  In the fourth quarter of 2015, Canadian revenues accounted for 22 percent of the total revenue (2014 – 28 percent), and during the year ended December 31, 2015, Canadian revenues were 22 percent of total revenue (2014 – 29 percent).

The Company recorded 6,999 operating days in 2015, a 52 percent decrease from 14,440 operating days in the previous year. During the fourth quarter of 2015 the Company recorded 1,607 operating days in Canada, a decrease of 56 percent from 3,633 operating days recorded during the fourth quarter of the prior year. Canadian well servicing hours decreased by 49 percent in the year ended December 31, 2015 from the prior year. Well servicing hours in the fourth quarter of 2015 were down 49 percent compared to the fourth quarter of the prior year.

The 2015 fiscal year was a challenging year for crude oil and natural gas producers, as the price of both commodities continued to decline throughout the year. The weakened commodity pricing negatively affected the demand for oilfield services. Utilization and revenue rates for the Company's Canadian oilfield services decreased as the Company's customers actively reduced planned levels of capital expenditures in reaction to the steep decline in crude oil prices. In the first two quarters of the prior year, Canadian activity levels had been positively impacted by favorable price differentials for Canadian oil and gas commodities and the impact of a particularly drier spring break-up. Those positive impacts were offset by the abrupt decline of crude oil prices beginning in the third quarter of 2014, which led to further reduced activity levels.

The Company continues to transition its Canadian drilling fleet from shallow drilling rigs to deeper drilling rigs in response to changing market dynamics. In Canada, the Company added five new ADR® drilling rigs and one new well servicing rig; transferred in one existing drilling rig from the United States fleet; repurposed one existing drilling rig; and decommissioned ten inactive drilling rigs during 2015.

UNITED STATES OILFIELD SERVICES


Three months ended December 31


Year ended December 31



2015


2014


% change


2015


2014


% change


Drilling rigs







Opening balance

98


110



95


117





Additions


1



3


2





Transfers

(1)


(2)



(1)


(3)





Decommissions/Disposals

(8)


(14)



(8)


(21)





Ending balance

89


95


(6)


89


95


(6)


Drilling operating days

2,417


5,860


(59)


11,895


23,577


(50)


Drilling rig utilization (%)

27.7


60.9


(55)


33.7


59.3


(43)


Well servicing rigs







Opening balance

46


44



45


45





Additions


1



2


2





Decommissions/Disposals

(2)




(3)


(2)





Ending balance

44


45



44


45


(2)


Well servicing operating hours

20,192


29,446


(31)


78,586


120,939


(35)


Well servicing utilization (%)

46.7


71.1


(34)


46.1


73.8


(38)


The Company's United States operations recorded revenue of $609.3 million for the year ended December 31, 2015, a decrease of 41 percent from the $1,026.6 million recorded for the year ended December 31, 2014. Revenues recorded in the United States were $132.1 million in the fourth quarter of 2015, a 51 percent decrease from the $272.0 million recorded in the corresponding period of the prior year. United States operations accounted for 46 percent of the Company's revenue in the fourth quarter of 2015 (2014 - 45 percent); and 44 percent of the Company's revenue in 2015 (2014 - 44 percent), making it the largest contributor to the Company's consolidated revenues in 2015, consistent with the prior year.

Drilling operating  days decreased  by 50 percent  from 23,577 operating days in 2014 to 11,895 operating days in 2015. During the fourth quarter of 2015, the Company recorded 2,417 operating days in the United States, a decrease of 59 percent from 5,860 operating days recorded during the fourth quarter of the prior year.  Well servicing activity expressed in operating hours decreased by 35 percent in 2015 compared to 2014. Well servicing hours in the fourth quarter of 2015 were down 31 percent compared to the fourth quarter of the prior year.

Overall operating and financial results for the Company's United States operations were negatively impacted by the decline in demand for oilfield services due to falling oil and gas commodity prices.  Activity levels and revenue rates in the United States oilfield service operations started to decline in the fourth quarter of 2014.  The decline continued throughout 2015, resulting in lower activity levels compared to the prior year.  The reduced activity and associated pricing declines were partially offset by a strengthening of the United States dollar, which increased 16 percent versus the Canadian dollar when compared to 2014.

During 2015, the Company added three new build ADR® drilling rigs and two new well servicing rigs to its United States fleet; transferred one drilling rig to its Canadian fleet; and decommissioned eight drilling rigs and three well servicing rigs.

INTERNATIONAL OILFIELD SERVICES


Three months ended December 31


Year ended December 31



2015


2014


% change


2015


2014


% change


Drilling and workover rigs








Opening balance

54


59



56


54





Additions





2





Transfers





3





Decommissions/Disposals

(4)


(3)



(6)


(3)





Ending balance

50


56


(11)


50


56


(11)


Drilling operating days

1,914


2,649


(28)


8,553


11,339


(25)


Drilling rig utilization (%)

39.5


49.4


(20)


43.1


53.6


(20)


The Company's international operations recorded revenue of $474.7 million for the year ended December 31, 2015, a 25 percent decrease from $629.1 million for the year ended December 31, 2014. International revenue totaled $90.0 million in the fourth quarter of 2015, a 45 percent decrease from $163.5 million recorded in the corresponding period of the prior year. The Company's international operations contributed 32 percent of the Company's fourth quarter revenue in 2015 (2014 - 27 percent) and 34 percent in the year ended December 31, 2015 (2014 - 27 percent).

The Company's international operations recorded 8,553 operating days in 2015, down 25 percent from 11,339 operating days recorded in 2014. International operating days for the three months ended December 31, 2014 decreased 28 percent to 1,914 operating days in the fourth quarter of 2014.

The reduction in oil and gas prices that commenced in the second half of 2014 affected all geographical areas, but had a less significant negative impact on the demand for international oilfield services compared to North American markets due to the longer term nature of international projects. However, the lower crude oil prices are particularly challenging for Venezuela, due to the heavy economic reliance on energy revenues in that country.

Similar to the Company's United States operations, international operations were positively impacted by the strengthening United States dollar versus the Canadian dollar on translation into Canadian dollars for reporting purposes in 2015 compared to the prior year.  During the year ended December 31, 2015 the Company decommissioned six rigs from its international fleet.

DEPRECIATION


Three months ended December 31



Twelve months ended December 31


($ thousands)

2015



2014



% change



2015



2014



% change


Depreciation

120,756



79,257



52



335,513



298,854



12




















Depreciation expense increased by 12 percent to $335.5 million for the year ended December 31, 2015 compared with $298.9 million for the year ended December 31, 2014. Depreciation expense totaled $120.8 million for the fourth quarter of 2015 compared with $79.3 million for the fourth quarter of 2014, an increase of 52 percent. Depreciation expense was higher year-over-year due to the revisions to the residual values of certain equipment from 15%-25% to 10% effective in 2015, additional depreciation charges relating to idle rigs, the impact of higher dollar value equipment being utilized and the negative translational impact of a stronger United States dollar compared to the Canadian dollar. The increase was partially offset by the overall decrease in operating activity during the year.

GENERAL AND ADMINISTRATIVE EXPENSE


Three months ended December 31


Twelve months ended December 31

($ thousands)

2015


2014


% change


2015


2014


% change

General and administrative

16,497


26,599


(38)


74,858


97,857


(24)


% of revenue

5.8


4.4




5.4


4.2





















General and administrative expense decreased 24 percent to $74.9 million (5.4 percent of revenue) for the year ended December 31, 2015 compared to $97.9 million (4.2 percent of revenue) in the prior year. General and administrative expense decreased 38 percent to $16.5 million (5.8 percent of revenue) for the fourth quarter of 2014. The decrease in general and administrative expense arose from the Company's initiatives to reduce costs in reaction to lower oil and gas commodity prices. The decrease was partially offset by one-time restructuring costs incurred during the year, as well as the negative translational impact of the strengthening United States dollar versus the Canadian dollar.

ASSET DECOMMISSIONING AND WRITE-DOWNS


Three months ended December 31


Twelve months ended December 31

($ thousands)

2015


2014


% change


2015


2014


% change

Asset decommissioning and write-downs


89,495


NM


28,281


89,495


(68)


















As a result of a detailed review of its equipment fleet in light of the persistent downturn in market conditions throughout 2015, the Company assessed future prospects for its drilling equipment fleet. The assessment resulted in a non-cash charge of $28.3 million to asset decommissioning and write-down expense relating to specific assets in its international operations in the third quarter of 2015. In accordance with its longstanding practice, the Company retains useful components from decommissioned rigs for use in its current and future operations.

SHARE-BASED COMPENSATION


Three months ended December 31


Twelve months ended December 31

($ thousands)

2015


2014


% change


2015


2014


% change

Share-based compensation

121


(5,913)


NM


37


(13,573)


NM

















Share-based compensation expense (recovery) expense arises from the Black-Scholes valuation accounting associated with the Company's share-based compensation plans, whereby the liability associated with share-based compensation is adjusted for the effect of granting and vesting of employee stock options and changes in the underlying market price of the Company's common shares.

For the year ended December 31, 2015 share-based compensation was an expense of $37 thousand compared with a recovery of $13.6 million for the year ended December 31, 2014.  For the three months ended December 31, 2015, share based compensation was an expense of $0.1 million compared with a recovery of $5.9 million recorded for the fourth quarter of 2014. The change in share-based compensation expense for the three and twelve months ended December 31, 2015 was a result of the amortization of stock options, offset by changes in the fair value of the share-based compensation. The fair value of share-based compensation is impacted by both the input assumptions used to estimate the fair value and the price of the Company's common shares during the period.  The closing price of the Company's common shares was $7.38 at December 31, 2015 compared with $10.20 at December 31, 2014.

INTEREST EXPENSE


Three months ended December 31



Twelve months ended December 31



($ thousands)

2015


2014

% change



2015


2014

% change



Interest expense

6,493


5,331

22



25,333


21,546

18



Interest income

(145)


(85)

71



(420)


(859)

(51)




6,348


5,246

21



24,913


20,687

20



Interest is incurred on the Company's $10.0 million Canadian-based revolving credit facility (the "Canadian Facility"), the $600.0 million global revolving credit facility (the "Global Facility") and the United States dollar $300.0 million senior unsecured notes (the "Notes") issued in February 2012.  The amortization of deferred financing costs associated with the issuance of the Notes is included in interest expense.

Interest expense increased by 18 percent for the year ended December 31, 2015 compared to the same period in 2014 despite an overall net decrease of $121.5 million in the bank credit facilities in fiscal 2015.  For the three months ended December 31, 2015, interest expense increased 22 percent to $6.5 million compared to the comparative period in 2014. The increased interest expense was due to the negative translational impact of a strengthening United States dollar versus the Canadian dollar.

FOREIGN EXCHANGE AND OTHER


Three months ended December 31



Twelve months ended December 31


($ thousands)

2015



2014



% change



2015



2014



% change


Foreign exchange and other

14,861



19,748



(25)



62,105



30,836



101




















Included in this amount is the impact of foreign currency fluctuations in the Company's subsidiaries that have functional currencies other than Canadian dollars. During the year ended December 31, 2015 the Australian dollar weakened by approximately 11 percent  against the United States dollar causing a foreign currency loss on translation of the Company's United States dollar denominated debt into Australian dollars (2014 -  eight percent). In general, the United States dollar strengthened when compared to other world currencies in 2015 compared to the same period of 2014.

Effective July 1, 2015, as a result of amendments to a number of currency arrangements the Company had in place in Venezuela, the Company changed the estimated foreign exchange rate it used in translating Venezuelan Bolivars from the Venezuelan Central Bank "official rate" to the exchange mechanism rate newly created in February 2015 called "SIMADI" or the Marginal Currency System.  On a prospective basis, revenues and expenses are translated using the new rate. The change to the new rate resulted in a revaluation to the assets and liabilities recorded by the Company's international operations, and a $2.3 million charge to foreign exchange and other expense.

INCOME TAXES


Three months ended December 31


Twelve months ended December 31


($ thousands)

2015


2014


% change


2015


2014


% change


Current income tax

9,937


3,023


229


153


25,020


(99)


Deferred income tax

(38,534)


(16,806)


129


(25,858)


15,074


NM


Total income tax

(28,597)


(13,783)


107


(25,705)


40,094


NM


Effective income tax rate (%)

41.0


30.8




19.8


36.1





















The effective income tax rate for the year ended December 31, 2015 was 19.8 percent compared with 36.1 percent for the year ended December 31, 2014. The effective income tax rate for the three months ended December 31, 2015 was 41 percent compared with 30.8 percent for the three months ended December 31, 2014. The effective tax rate in 2015 was lower than the effective tax rate in 2014 due to a higher proportion of pretax losses in lower rate jurisdictions in 2015. This was further reduced by an offsetting tax expense to recognize the increase in the Alberta corporate tax rate, effective July 1, 2015.

The effective income tax rate in the fourth quarter of 2015 was significantly higher in comparison to the effective tax rate for the three months ended December 31, 2014 due to a higher proportion of the current quarter's pretax losses arising in higher rate jurisdictions.

FINANCIAL POSITION

Significant changes in the consolidated statement of financial position from December 31, 2014 to December 31, 2015 are outlined below:

($ thousands)

Change

Explanation

Cash and cash equivalents

(13,611)


See consolidated statements of cash flows.




Accounts receivable

(248,397)


Decrease is due to an increase in collections, a decline in activity in the fourth quarter of 2015 compared to the fourth quarter of 2014, and to the revaluation of Bolivar-denominated receivables in Venezuela.




Inventories and other

6,944


Increase is due to the impact of an increase in the year-end foreign exchange rate on the translation of the inventory and prepaid balances of the Company's foreign subsidiaries as well as additional expenditures on prepaid expenses, offset by normal course usage of consumables and amortization of prepaid expenses during the year.




Income taxes receivable

(10,894)


Decrease is due to the current year income tax provision, net of refunds during the year.




Property and equipment

140,653


Increase is due to additions from the new build and major retrofit program and the impact of an increase in the foreign exchange rate on the translation of the property and equipment of the Company's foreign subsidiaries. The increase is offset by depreciation as well as asset decommissioning and write-downs.




Accounts payable and accruals

(220,677)


Decrease is due to a reduction in operating activity in the fourth quarter of 2015, a reduction in the size of the Company's new build and major retrofit program, and the revaluation of Bolivar-denominated payables in Venezuela.




Share-based compensation

436


Increase was a result of the amortization of stock options offset by changes in the fair value of the share-based compensation.  The fair value of share-based compensation expense is impacted by both the input assumptions used to estimate the fair value and the price of the Company's common shares during the period.




Long-term debt

7,782


Increase is due to the strengthening of the United States dollar from December 31, 2014 to December 31, 2015, offset by repayments of $121.5 million during 2015.




Deferred income taxes

45,795


Increase is primarily due to accelerated tax depreciation of assets added during the year, utilization of non-capital losses and the corporate income tax rate increase enacted in Alberta, effective July 1, 2015.




Shareholders' equity

41,359


Increase is due to the impact of foreign exchange rate fluctuations on net assets of foreign subsidiaries, offset by the net loss incurred and the amount of dividends declared in the year.

FUNDS FROM OPERATIONS AND WORKING CAPITAL

($ thousands, except per share amounts)

Three months ended December 31


Twelve months ended December 31


2015



2014



% change


2015



2014



% change


Funds from operations

48,905



132,257



(63)


296,273



491,886



(40)


Funds from operations per share

$

0.32



$

0.87



(63)


$

1.94



$

3.22



(40)


Working capital

144,239



189,698



(24)


144,239



189,698



(24)























Funds from operations totaled $296.3 million ($1.94 per common share) for 2015, a decrease of 40 percent from $491.9 million ($3.22 per common share) generated in 2014. The Company generated Funds from operations of $48.9 million ($0.32 per common share) in the three months ended December 31, 2015 compared with $132.3 million ($0.87 per common share) for the three months ended December 31, 2014, a decrease of 63 percent. The decrease in Funds from operations in 2015 compared to 2014 is due to the decline in demand for both North American and international oilfield services, attributed to the decline in global energy prices.

At December 31, 2015, the Company's working capital totaled $144.2 million, compared to $189.7 million at December 31, 2014.  The decrease in working capital year-over-year was mainly related to a reduction in operating levels by the Company in 2015.  The Company expects funds generated by operations, combined with current and future credit facilities, to fully support current operating and capital requirements.  Existing revolving credit facilities provide for total borrowings of $610.0 million, of which $220.1 million was undrawn and available at December 31, 2015.

INVESTING ACTIVITIES


Three months ended December 31


Twelve months ended December 31


($ thousands)

2015



2014



% change


2015



2014



% change


Purchase of property and equipment

(13,159)



(165,914)



(92)


(168,281)



(600,566)



(72)


Proceeds from disposals of property and equipment

4,982



8,580



(42)


9,248



17,567



(47)


Net change in non-cash working capital

(5,413)



29,258



NM


(61,037)



32,080



NM


Cash used in investing activities

(13,590)



(128,076)



(89)


(220,070)



(550,919)



(60)


Net purchases of property and equipment for the year ended December 31, 2015 totaled $159.0 million (2014 - $583.0 million) and for the three months ended December 31, 2015 totaled $8.2 million (2014 - $157.3 million). The purchase of property and equipment relates predominantly to expenditures made pursuant to the Company's new build and major retrofit program. Significant additions in 2015 as a result of the new build program include:

  • Completed five new ADR® drilling rigs for Canada and one new well servicing rig was added to the Canadian fleet.
  • Completed three new ADR® drilling rigs for the United States and added two new well servicing rigs to the United States fleet.

FINANCING ACTIVITIES


Three months ended December 31


Twelve months ended December 31


($ thousands)

2015



2014



% change


2015



2014



% change


Net (decrease) increase in bank credit facilities

(27,556)



14,934



NM


(121,458)



82,331



NM


Purchase of shares held in trust

(313)



(581)



(46)


(6,781)



(5,863)



16


Repurchase of shares



(3,579)



NM




(3,579)



NM


Dividends

(18,367)



(18,367)




(73,469)



(72,423)



1


Net change in non-cash working capital

(4,730)



(1,973)



140


257



1,093



(76)


Cash provided by (used in) financing activities

(50,966)



(9,566)



433


(201,451)



1,559



NM


The Company's available bank credit facilities consist of a $600.0 million Global Facility and a $10.0 million Canadian Facility. The Global Facility is available to the Company and certain of its wholly owned subsidiaries, and may be drawn in Canadian, United States or Australian dollars, up to the equivalent value of $600.0 million Canadian dollars. The amount available under the Canadian Facility is $10.0 million or the equivalent in United States dollars.

On September 25, 2014 the Company received approval from the Toronto Stock Exchange to acquire for cancellation up to three percent of the Company's issued and outstanding common shares under a Normal Course Issuer Bid (the "Bid"), under which the Company could purchase up to 4,600,477 common shares for cancellation. The Bid commenced on September 29, 2014 and the Company purchased 289,100 common shares under the Bid, for a total cost of $3.6 million in 2014. The Bid terminated on September 28, 2015.

The Company declared dividends of $0.48 per common share in the 2015 fiscal year, an increase of two percent over dividends of $0.4725 per common share declared in 2014. No stock options were exercised to acquire common shares in 2015 or 2014.

Subsequent to December 31, 2015, the Company declared a dividend for the first quarter of 2016. A quarterly dividend of $0.1200 per common share is payable April 5, 2016 to all Common Shareholders of record as of March 24, 2016. The dividend is pursuant to the quarterly dividend policy adopted by the Company. Pursuant to subsection 89(1) of the Canadian Income Tax Act ("ITA"), the dividend being paid is designated as an eligible dividend, as defined in subsection 89(1) of the ITA.

NEW BUILDS AND MAJOR RETROFITS

During the year ended December 31, 2015, the Company commissioned five new ADR® drilling rigs in Canada and three new ADR® drilling rigs in the United States. In addition, one new well servicing rig was added to the Canadian fleet and two new well servicing rigs were added to the United States fleet.

The Company continues to selectively build new ADR® drilling rigs and upgrade existing rigs to meet the increasing technical demands of its customers.  The decline in oil and natural gas commodity prices resulted in the Company proactively and aggressively reducing the rig build program during the year. As of December 31, 2015, the Company had plans to commission one new ADR® drilling rig in early 2016.

OUTLOOK

After a difficult 2015 that endured a steep decline in energy commodity prices, another difficult year is underway. The oil and natural gas industry is looking back through history, searching to find a playbook to help navigate these difficult times. In 2016, the industry is expected to continue to seek adjustments to its business model to lower break-even costs, reduce capital expenditures, and work with suppliers and partners in order to return to stability.

Energy supply has continued to grow, but weakening global economic conditions are raising doubts regarding the extent to which energy demand will expand. The energy sector continues to watch for some sort of confirmation that it has reached a bottoming in pricing and supply growth, which should allow a correction to more balanced supply-demand levels. The delay in reaching such bottoming can partially be attributed to the impact of completing projects that had commenced before the industry downturn. Rebalancing of global supply and demand, previously anticipated to occur in mid-2016, is now not expected until at least late 2016 or possibly sometime in 2017.

Despite slow but steady growth in the United States economy and labor markets, regions elsewhere around the world continue to struggle with heightened concern generated by negative signals from China. The United States Federal Reserve's decision to increase the federal funds target interest rate in mid-December 2015 has contributed to increased volatility and currency weaknesses in other economies.

The supply and demand imbalance in oil markets has been the main focus for the industry in 2015 and will continue into the future. Production of oil in the United States continued to grow in 2015. However, the United States Department of Energy expects a decline of 7.4 percent in 2016 and, as new capital is being deferred, the decline will likely continue into 2017. The decline in United States oil production is generally offset by increased production from Iran, following the lifting of economic sanctions in early 2016. Reservoir production declines and minimal capital investments should further engender supply reductions over time.

The continuing and protracted period of low energy commodity prices has dramatically reduced our customers' cash flows, driving ongoing reductions in expenditures on drilling and reduced demand for oilfield services. Average WTI crude oil prices in the fourth quarter of 2015 were $42, down 31 percent from one year ago. Henry Hub natural gas prices averaged $2.12, down 44 percent from the corresponding quarter in 2014. Lower crude oil prices and the resulting decreased gasoline prices have benefited consumers, but increased savings and debt reductions have been the unexpected results in as much as the small increase in miles driven has not spurred significant demand increases.

The late January 2016 conclusion of the Alberta government royalty review should finally provide Canadian operators the ability to determine the feasibility of new projects. Although the immense uncertainty that prevailed during the review period had exacerbated local industry conditions, the resolution itself illustrates the risk that political and environmental policies around the world have on our industry. While the Paris climate accord will push the industry to reduce carbon emissions, likely a positive for the natural gas industry, the prospects for harsher regulations for the industry as a whole may serve to dampen development in the sector.

As expected, the number of active drilling rigs in all markets has dropped significantly, particularly in North America. Incremental to the 2015 year-over-year activity reduction of 51 percent in Canada, the Canadian Association of Oilwell Drilling Contractors is forecasting a further reduction of 13 percent in 2016. As of mid-February, active land-based rigs operating in Canada had declined by 42 percent year-over-year to 222 rigs. The warmer than average winter this year in Western Canada is also expected to lead to an early spring "break-up" and  further curtailment of  drilling in the first half of 2016.

The Company's Canadian drilling days in the fourth quarter of 2015 were down seven percent sequentially, with a decline of 56 percent from the corresponding quarter in 2014. Although rig rate pressures from operators are ongoing, the deeper rigs deployed in the Company's Canadian fleet have served to somewhat offset day rate reductions in spot markets. Future expectations are for the Company's Canadian operations to track with lower industry levels.

Baker Hughes' estimates of United States land drilling rig activity continue to decline below lows previously expected, and represent new troughs for the sector. As of mid-February, active land-based rigs operating in the United States had declined by 60 percent year-over-year to 514 rigs. The Company's United States operations have fared comparably well, other than in California, and our market share has either held or increased somewhat. However, pressures on day rates and contract retention persist. The Company is witnessing activity reductions in the Rocky Mountain regions, with more stability in southern regions.

Operating days in the Company's international equipment fleet for 2015 were down 25 percent when compared to 2014. Consistent with global industry trends, oilfield services activity levels in the Company's operations outside of North America have declined less than those in Canada and the United States. Subsequent to the activity drop in Australia during the first half of 2015, the Company's international operations have remained relatively stable, with Middle East activity supported by long-term contracts. However, the region is not immune to the negative impacts from the protracted downturn and customers are seeking pricing concessions and cost reduction measures to be included in contract negotiations and renewals.

With the headwinds of 2015 continuing into 2016, the Company remains focused on operational improvements, close attention to customer credit conditions, and safeguarding its balance sheet. We have continued to reduce capital expenditures where possible and have deferred major capital projects. We have assessed our operating structure and are generating efficiencies where possible. These assessments have led to headcount reductions, wage rollbacks, and negotiations with suppliers to reduce costs.

Our customers will continue to look to reduce operating costs and we will continue to support this objective with our deeper high-specification drilling rigs. The size of the global rig fleet going forward will likely be smaller, with fewer rigs than historically required drilling more wells. This reduction in the size of the market will lead to capitulation for some companies.

The Company is prepared for what is now expected to be a slow recovery and is actively monitoring and reacting to this "new normal" for the industry. The Company believes its proactive measures in response to market conditions, coupled with the additions and improvements to its equipment fleet resulting from its new build and major refurbishment program during prior years, have positioned Ensign to respond to customers' demands for premium oilfield services equipment and services around the world in the challenging prevailing market environment.

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, economic and market conditions, crude oil and natural gas prices, foreign currency fluctuations, weather conditions, the Company's defense of lawsuits and the ability of oil and gas companies to pay accounts receivable balances and 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 fourth quarter 2015 results at 2:00 p.m. MST (4:00 p.m. EST) on Tuesday, March 8, 2016.  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 15, 2016 by dialing 1-416-849-0833 (in Toronto) or 1-855-859-2056 (outside Toronto) and entering the reservation number 50592035.  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.

 


Ensign Energy Services Inc.
Consolidated Statements of Financial Position

















As at


December 31
 2015



December 31
 2014


(Unaudited - in thousands of Canadian dollars)





Assets





Current assets






Cash and cash equivalents


$

40,386



$

53,997



Accounts receivable


215,421



463,818



Inventories and other


71,806



64,862



Income taxes receivable


4,947



15,841


Total current assets


332,560



598,518


Property and equipment


3,265,580



3,124,927


Total assets


$

3,598,140



$

3,723,445







Liabilities





Current liabilities






Accounts payable and accruals


$

167,881



$

388,558



Dividends payable


18,367



18,367



Share-based compensation


2,073



1,895


Total current liabilities


188,321



408,820


Long-term debt


794,109



786,327


Share-based compensation


935



677


Deferred income taxes


528,179



482,384


Total liabilities


1,511,544



1,678,208







Shareholders' equity






Share capital


169,171



169,215



Contributed surplus


2,538



1,967



Foreign currency translation reserve


332,230



113,880



Retained earnings


1,582,657



1,760,175


Total shareholders' equity


2,086,596



2,045,237


Total liabilities and shareholders' equity


$

3,598,140



$

3,723,445


 

 

Ensign Energy Services Inc.
Consolidated Statements of Income












Three months ended


Twelve Months Ended




December 31
 2015



December 31
 2014


December 31
 2015



December 31
 2014


(Unaudited - in thousands of Canadian dollars, except per share data)








Revenue


$

283,887



$

602,691


$

1,390,978



$

2,321,765


Expenses









Oilfield services


195,076



433,080


995,025



1,686,395



Depreciation


120,756



79,257


335,513



298,854



General and administrative


16,497



26,599


74,858



97,857



Asset decommissioning and

write-downs




89,495


28,281



89,495



Share-based compensation


121



(5,913)


37



(13,573)



Foreign exchange and other


14,861



19,748


62,105



30,836


Total expenses


347,311



642,266


1,495,819



2,189,864


Income (loss) before interest and income taxes


(63,424)



(39,575)


(104,841)



131,901


Interest income


145



85


420



859


Interest expense


(6,493)



(5,331)


(25,333)



(21,546)


Income (loss) before income taxes


(69,772)



(44,821)


(129,754)



111,214


Income taxes









Current tax


9,937



3,023


153



25,020



Deferred tax


(38,534)



(16,806)


(25,858)



15,074


Total income taxes


(28,597)



(13,783)


(25,705)



40,094


Net income (loss)


$

(41,175)



$

(31,038)


$

(104,049)



$

71,120


Net income (loss) per share









Basic


$

(0.26)



$

(0.20)


$

(0.68)



$

0.47



Diluted


$

(0.26)



$

(0.20)


$

(0.68)



$

0.46


 

 


Ensign Energy Services Inc.
Consolidated Statements of Cash Flows














Three months ended


Twelve months ended




December 31
 2015



December 31
 2014


December 31
 2015



December 31
 2014


(Unaudited - in thousands of Canadian dollars)








Cash provided by (used in)








Operating activities








Net income (loss)


$

(41,175)



$

(31,038)


$

(104,049)



$

71,120


Items not affecting cash









Depreciation


120,756



79,257


335,513



298,854



Asset decommissioning and write-downs




89,495


28,281



89,495



Share-based compensation, net of cash paid


1,441



(5,217)


7,237



(10,657)



Unrealized foreign exchange and other


6,311



16,475


54,742



27,648



Accretion on long-term debt


106



91


407



352



Deferred income tax


(38,534)



(16,806)


(25,858)



15,074


Funds provided by operations


48,905



132,257


296,273



491,886


Net change in non-cash working capital


24,627



24,248


115,971



29,246


Cash provided by operating activities


73,532



156,505


412,244



521,132


Investing activities








Purchase of property and equipment


(13,159)



(165,914)


(168,281)



(600,566)


Proceeds from disposals of property and equipment


4,982



8,580


9,248



17,567


Net change in non-cash working capital


(5,413)



29,258


(61,037)



32,080


Cash used in investing activities


(13,590)



(128,076)


(220,070)



(550,919)


Financing activities








Net (decrease) increase in bank credit facilities


(27,556)



14,934


(121,458)



82,331


Purchase of shares held in trust


(313)



(581)


(6,781)



(5,863)


Repurchase of shares




(3,579)




(3,579)


Dividends


(18,367)



(18,367)


(73,469)



(72,423)


Net change in non-cash working capital


(4,730)



(1,973)


257



1,093


Cash (used in) provided by financing activities


(50,966)



(9,566)


(201,451)



1,559


Net (decrease) increase in cash and cash equivalents


8,976



18,863


(9,277)



(28,228)


Effects of foreign exchange on cash and cash equivalents


(12,486)



12,404


(4,334)



3,367


Cash and cash equivalents – beginning of period


43,896



22,730


53,997



78,858


Cash and cash equivalents – end of period


$

40,386



$

53,997


$

40,386



$

53,997


Supplemental information









Interest paid


$

10,210



$

8,367


$

25,036



$

21,008



Income taxes (recovered) paid


$

(2,285)



$

4,349


$

(10,741)



$

32,289


SOURCE Ensign Energy Services Inc.

Image with caption: "Ensign Logo (CNW Group/Ensign Energy Services Inc.)". Image available at: http://photos.newswire.ca/images/download/20160308_C2992_PHOTO_EN_637454.jpg

For further information: Timothy Lemke, Vice President Finance and Chief Financial Officer, (403) 262-1361

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http://www.ensignenergy.com

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