High Arctic Reports 2017 Third Quarter Results

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| Source: High Arctic Energy Services Inc.

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CALGARY, Alberta, Nov. 09, 2017 (GLOBE NEWSWIRE) -- High Arctic Energy Services Inc. (TSX:HWO) – “High Arctic” or the “Corporation” is pleased to announce its 2017 third quarter results.

Mr. Michael Binnion, High Arctic’s Interim CEO stated: “Our strategy of focusing on niche markets with barriers to entry has really paid off. Since the downturn in world energy markets we have successfully renewed or renegotiated our customer contracts in Papua New Guinea allowing us to have three rigs currently under contract in the country. In spite of the down turn we have not only maintained our dividend but kept a payout rate of under 30%. We are looking towards growth starting again in 2018 from anticipated improving markets for Papua New Guinea and Canada.”

Highlights

Improving activity in High Arctic’s expanded Canadian operations has helped to offset lower activity levels in the Corporation’s PNG business operations.  The strength of High Arctic’s diversified business operations has contributed to a 9% growth in revenue year to date in an otherwise challenging global market for the oil and gas industry. 

Third Quarter 2017:

  • High Arctic reported Adjusted EBITDA of $10.6 million in the quarter driven from the strength of the Corporation’s diversified operations.
  • High Arctic continues to maintain a strong balance sheet with $26.6 million in cash and $9.0 million outstanding on its debt facilities for a net cash balance of $17.6 million as at September 30, 2017.
  • The Corporation has completed the renegotiation of its expiring drilling contracts for Rigs 103 and 104 resulting in three rigs operating under contract in PNG. 
  • Utilization for High Arctic’s registered Concord Well Servicing rigs was 59% in the quarter versus industry utilization of 32% (source: Canadian Association of Oilwell Drilling Contractors “CAODC”).
  • Consistent with prior quarters, High Arctic declared $2.6 million ($0.05 per share) in dividends during the quarter which represents 26% of funds provided from operations in the quarter.

Year to Date 2017:

  • Year to date the Corporation has generated $45.9 million in Adjusted EBITDA in spite of the challenges facing world markets for oil and gas.
  • Higher than anticipated utilization for the Concord service rigs in High Arctic’s Production Services segment has contributed to a 9% increase in revenue to $158.7 million year to date.
  • A total of $7.9 million has been returned to shareholders year to date through dividends which represents 22% of funds provided from operations year to date.

Select Comparative Financial Information

The following is a summary of select financial information of the Corporation.

 Three Months Ended September 30 Nine Months Ended September 30
$ millions (except per share amounts)2017 2016 % Change 2017 2016 % Change
Revenue42.8 47.5 (10%) 158.7 145.7 9%
EBITDA(1)11.0 26.5 (58%) 46.5 62.5 (26%)
Adjusted EBITDA(1)(3)10.6 15.6 (32%) 45.9 52.5 (13%)
Adjusted EBITDA % of revenue25%33%(25%) 29%36%(20%)
Operating earnings4.1 9.3 (56%) 26.4 34.4 (23%)
Net earnings 2.8 20.1 (86%) 16.8 37.6 (55%)
  per share (basic)(2)0.06 0.38 (84%) 0.32 0.71 (55%)
  per share (diluted)(2)0.05 0.37 (86%) 0.31 0.70 (56%)
Adjusted net earnings(1)(3) 2.8 8.8 (68%) 16.8 26.3 (36%)
  per share (basic)(2)0.06 0.16 (63%) 0.32 0.50 (36%)
  per share (diluted)(2)0.05 0.16 (69%) 0.31 0.49 (37%)
Funds provided from operations(1)9.8 11.6 (16%) 35.9 43.9 (18%)
  per share (basic)(2)0.18 0.22 (18%) 0.67 0.83 (19%)
  per share (diluted)(2)0.18 0.22 (18%) 0.67 0.82 (18%)
Dividends 2.6 2.7 (4%) 7.9 7.9 0%
  per share(2)0.05 0.05 0% 0.15 0.15 0%
Capital expenditures 1.1 42.9 (97%) 5.5 50.3 (89%)
     As at
     September 30,
 2017
December 31,
 2016
% Change
Working Capital(1)    55.5  28.6 94%
Total assets    272.0  305.1 (11%)
Total non-current financial liabilities    12.3  4.2 193%
Net cash, end of period(1)    17.6  3.3 433%
Shareholders’ Equity    227.9  230.2 (1%)
Shares outstanding(2)    53.3  53.2 0%

(1) Readers are cautioned that EBITDA, Adjusted EBITDA, Adjusted net earnings, Funds provided from operations, net (debt) cash and working capital do not have standardized meanings prescribed by IFRS – see “non IFRS Measures” on page 13 for calculations of these measures.
(2) The incentive shares held by a trustee under the Executive and Director Incentive Share Plan (2010) are included in the shares outstanding.  The number of shares used in calculating the net earnings per share amounts is determined differently as explained in the Financial Statements.
(3) Adjusted EBITDA and Adjusted net earnings exclude the impact of the $12.7 million gain on acquisition related to the Tervita Acquisition.

Corporate Profile

Headquartered in Calgary, Alberta, Canada, High Arctic provides oilfield services to exploration and production companies operating in Canada and Papua New Guinea (“PNG”). High Arctic is a publicly traded company listed on the Toronto Stock Exchange under the symbol “HWO”. 

On August 31, 2016, High Arctic acquired Tervita’s Production Services Division (the “Tervita Acquisition”).  Through this acquisition, High Arctic added a fleet of 85 service rigs (of which 55 are currently registered and marketed) and related support equipment, a surface equipment rentals division and an abandonment and compliance consulting division.  As a result of the expansion of the Corporation’s service offering following the Tervita Acquisition, High Arctic has organized its business into three business segments: Drilling Services; Production Services; and Ancillary Services.

Drilling Services
The Drilling Services segment consists of High Arctic’s drilling services in PNG where the Corporation has operated since 2007.  High Arctic currently operates the largest fleet of tier-1 heli-portable drilling rigs in PNG, with two owned rigs and two rigs managed under operating and maintenance contracts for one of the Corporation’s customers.  

Production Services
The Production Services segment consists of High Arctic’s well servicing and snubbing operations.  These operations are primarily conducted in the Western Canadian Sedimentary Basin (“WCSB”) through High Arctic’s fleet of well servicing rigs, operating as Concord Well Servicing, and its fleet of stand-alone and rig assist snubbing units.  In addition, High Arctic also provides work-over services in PNG with its heli-portable work-over rig.

Ancillary Services
The Ancillary Services segment consists of High Arctic’s oilfield rental equipment in Canada and PNG as well as its Canadian nitrogen and abandonment and compliance consulting services.

Consolidated Results

 Three Months Ended September 30 Nine Months Ended September 30
($ millions)20172016Change% 20172016Change%
Revenue42.847.5(4.7)(10%) 158.7  145.713.0 9%
EBITDA(1)11.026.5(15.5)(58%) 46.5  62.5(16.0)(26%)
Adjusted EBITDA(1)(3)10.615.6(5.0)(32%) 45.9  52.5(6.6)(13%)
Net earnings2.820.1(17.3)(86%) 16.8  37.6(20.8)(55%)
  per share (basic)(2)0.060.38(0.3)(84%) 0.32  0.71(0.4)(55%)
  per share (diluted)(2)0.050.37(0.3)(86%) 0.31  0.70(0.4)(56%)
Adjusted net earnings(1)(3)2.88.8(6.0)(68%) 16.8  26.3(9.5)(36%)
  per share (basic)(2)0.060.16(0.1)(63%)   0.32  0.50(0.2)(36%)
  per share (diluted)(2)0.050.16(0.1)(69%)   0.31  0.49(0.2)(37%)

(1) Readers are cautioned that EBITDA, Adjusted EBITDA and Adjusted net earnings do not have standardized meanings prescribed by IFRS – see “non IFRS Measures” on page 13 for calculations of these measures.
(2) The incentive shares held by a trustee under the Executive and Director Incentive Share Plan (2010) are included in the shares outstanding.  The number of shares used in calculating the net earnings per share amounts is determined differently as explained in the Financial Statements.
(3) Adjusted EBITDA and Adjusted net earnings exclude the impact of the $12.7 million gain on acquisition related to the Tervita Acquisition.

Third Quarter:

The expansion of High Arctic’s Production Services segment helped to mitigate the impact of lower PNG drilling and rentals activity resulting in $42.8 million in revenue in the quarter versus $47.5 million in the third quarter of 2016.  This reduction in consolidated revenue, combined with the increased contribution from the Production Services segment which has a lower operating margin, resulted in Adjusted EBITDA declining to $10.6 million in the quarter from $15.6 million in the third quarter of 2016. 

Consistent with the reduced Adjusted EBITDA during the quarter, as well as increased depreciation expense associated with the assets acquired in the Tervita Acquisition, Adjusted net earnings declined to $2.8 million ($0.06 per share (basic)) in the quarter versus $8.8 million ($0.16 per share (basic)) in the third quarter of 2016.  On a net earnings basis, the Corporation generated $2.8 million in net earnings in the quarter versus $20.1 million in the third quarter of 2016.  The third quarter of 2016 benefited from a one-time recognition of a $12.7 million gain related to the Tervita Acquisition.  This gain represents the difference in appraised value of the net assets acquired in the transaction versus the $42.8 million paid to acquire them.  This gain as well as transaction costs associated with the acquisition have been excluded from the Corporation’s Adjusted net earnings as these costs are not representative of the earnings associated with the Corporation’s ongoing business operations.

Year to Date:

Consistent with the third quarter, the expansion of High Arctic’s Production Services segment has contributed to a 9% increase in revenue to $158.7 million year to date versus $145.7 million in the first nine months of 2016.  This increased revenue contribution as well as the Corporation’s contracted drilling revenue helped to offset lower drilling activity in PNG year to date relative to the comparative period in 2016.  While revenue increased in the period relative to the comparable period in 2016, the increased contribution from lower margin Production Services revenue resulted in a 13% decrease in Adjusted EBITDA to $45.9 million versus $52.5 million in the first nine months of 2016.  

Consistent with the third quarter, lower Adjusted EBITDA and increased depreciation expense contributed to a decline in year to date Adjusted net earnings to $16.8 million ($0.32 per share (basic)) from $26.3 million ($0.50 per share (basic)) in the first nine months of 2016.  On a net earnings basis, the Corporation has generated $16.8 million in net earnings year to date versus $37.6 million in the comparative period in 2016 which benefited from the acquisition gain discussed above.

Operating Segments

Drilling Services

 Three Months Ended September 30 Nine Months Ended September 30
($ millions)2017 2016 Change% 2017 2016 Change%
Revenue17.7 32.9 (15.2)(46%) 80.3 107.8 (27.5)(26%)
Oilfield services expense (1)10.5 20.8 (10.3)(50%) 45.2 66.6 (21.4)(32%)
Oilfield services operating margin (1)7.2 12.1 (4.9)(40%) 35.1 41.2 (6.1)(15%)
  Operating margin (%)41%37%4%11% 44%38%6%16%

(1) See ‘non-IFRS Measures’ on page 13

The Corporation owns two heli-portable drilling rigs (Rigs 115 and 116) which were added to High Arctic’s fleet during 2015.  These rigs are in addition to Rigs 103 and 104 which High Arctic operates on behalf of a major oil and gas exploration company in PNG. 

Third Quarter:

Revenue declined 46% in the quarter to $17.7 million from $32.9 million in the third quarter of 2016.  This decline was due to a combination of lower drilling activity in the quarter as well as the take-or-pay contract for Rig 115 ending in June 2017.  Activity during the quarter was focused on preparing Rig 103 for its drilling assignment in P’nyang.  Following completion of rig maintenance and preparation activities, mobilization of the rig to its drilling site commenced in late August and continued throughout the remainder of the quarter.  Preventative maintenance activities were conducted on Rig 104, which remained stacked in Muruk awaiting its next drilling assignment anticipated in the first quarter of 2018.  Rig 116 continued to generate standby revenue under its take-or-pay contract.

Operating margin as a percentage of revenue increased quarter over quarter to 41% versus 37% in the third quarter of 2016.  Consistent with prior quarters, the standby revenue generated on Rig 116 skewed operating margins higher due to minimal operating costs being incurred while the rig is on standby.  Standby revenue accounted for approximately 35% of Drilling Services revenue in the quarter versus 19% in the comparative quarter in 2016.  Excluding the impact of standby revenue, operating margin as a percentage of revenue would have been 13% in the quarter versus 25% in the third quarter of 2016.  This decline in operating margin, excluding standby revenue contribution, was due to increased costs associated with maintenance activities as well as lower revenue contribution towards fixed operating costs for the Drilling Services division. 

Year to Date 2017:

Consistent with the third quarter results, lower drilling activity combined with reduced contribution from take-or-pay contracted revenue has contributed to a 26% decline in Drilling Services revenue to $80.3 million year to date versus $107.8 million generated in the first nine months of 2016.  The prior period benefited from the take-or-pay contracted revenue for Rigs 115 and 116 throughout the first nine months of 2016 as well as higher drilling activity for Rigs 103 and 104.

Operating margin as a percentage of revenue increased to 44% year to date versus 38% in the comparative period in 2016.  Consistent with the third quarter results, operating margins in the first nine months of 2017 have benefited from revenue generated from take-or-pay contracts.  In addition, margins have also benefited from lower rig lease costs on Rig 103 and 104 associated with the lower activity for these rigs in the year.  Year to date, 30% of the Drilling Services revenue has been generated by take-or-pay standby revenue versus 17% in the comparative period in 2016.

Production Services

 Three Months Ended September 30 Nine Months Ended September 30
($ millions)2017 2016 Change% 2017 2016 Change%
Revenue  20.8  8.1 12.7 157%   60.1  16.4 43.7 266%
Oilfield services expense (1)  15.8  6.2 9.6 155%   48.9  11.9 37.0 311%
Oilfield services operating margin (1)5.0 1.9 3.1  163% 11.2 4.5 6.7  149%
  Operating margin (%)24%23%1%4% 19%27%(8%)(30%)
          
Operating Statistics:         
 Service rigs         
  Average Fleet (2)55 68 (13)(19%) 55 68 (13)(19%)
  Utilization (3)59%38%21%55% 57%38%19%50%
  Operating hours29,993 7,823 22,170 283% 85,171 7,823 77,348 989%
  Revenue per hour583 602 (19)(3%) 590 602 (12)(2%)
          
Snubbing rigs         
  Average Fleet (4)9 8 1 13% 9 8 1 13%
  Utilization (3)29%33%(4%)(12%) 29%37%(8%)(22%)
  Operating hours2,406 2,449 (43)(2%) 7,212 8,414 (1,202)(14%)

(1) See ‘non-IFRS Measures’ on page 13
(2) Average service rig fleet represents the average number of rigs registered with the CAODC during the period.
(3) Utilization is calculated on a 10-hour day using the number of rigs registered with the CAODC during the period.
(4) Average snubbing fleet represents the average number of rigs marketed during the period.

High Arctic’s well servicing and snubbing operations are provided through its Production Services segment.  These operations are primarily conducted in the WCSB through High Arctic’s fleet of well servicing rigs, operating as Concord Well Servicing, and its fleet of stand-alone and rig assist snubbing units.  The Concord Well Servicing operations were added to the Production Services segment through the Tervita Acquisition, which closed on August 31, 2016. 

The Production Services segment also provides heli-portable workover services in PNG through Rig 102, however, no workover services were provided in PNG during 2016 or year to date in 2017 and as such no revenue was generated or costs have been incurred associated with this rig during the periods presented.

Third Quarter:

The 157% increase in revenue quarter over quarter is due to the addition of the Concord Well Servicing operations added on August 31, 2016.  The Concord Well Servicing operations contributed $17.5 million in revenue during the quarter versus $4.7 million in the third quarter of 2016.  The higher revenue generated in the third quarter of 2017 is due to the full quarter contribution of the Concord Well Servicing operations in 2017 versus only one month contribution in the third quarter of 2016.  During the quarter the Concord rigs were able to generate 29,993 operating hours for a 59% utilization of its registered rigs.  Concord’s 59% utilization compares favorably to the 32% utilization generated by the industry’s registered well servicing rigs in the third quarter of 2017 (source: CAODC).  Market pricing pressures resulted in average revenue per hour declining 3% to $583 per hour from $602 per hour in the comparative quarter.  While activity has begun to increase, pricing remains competitive.

Revenue contribution from the Production Services snubbing rig operations was flat quarter over quarter at $3.3 million versus $3.4 million in the third quarter of 2016.  Operating hours for the snubbing rigs was consistent quarter over quarter with 2,406 hours which was 43 hours less than the comparative period in 2016 with no significant change in average pricing quarter over quarter.

While average service rig pricing was lower during the quarter, cost savings derived through the Corporation’s integration efforts following the Tervita Acquisition allowed operating margin as a percentage of revenue to increase to 24% in the quarter from 23% in the third quarter of 2016.  In addition, margins for the Concord Service rig operations in Grande Prairie have begun to normalize following the initial start-up costs associated with the division’s expansion into Grande Prairie.

Year to Date 2017:

The addition of the Concord Well Servicing operations has resulted in a 266% growth in Production Services segment revenue to $60.1 million in the first nine months of 2017 from $16.4 million in the comparative period in 2016.  Year to date the Concord rigs have generated 85,171 operating hours for a 57% utilization of the Corporation’s 55 average CAODC registered service rigs versus 31% utilization achieved in the first nine months for the industry’s registered service rig fleet (source: CAODC).  Year to date the Concord rigs have generated an average revenue rate of $590/hour. 

Activity for the Corporation’s snubbing rigs has declined 14% year to date versus the first nine months of 2016.   This decline in activity was due to the Corporation’s core snubbing customers directing their efforts towards completing fracturing programs in the first half of 2017.  Snubbing services are typically provided subsequent to fracturing of a well.  Snubbing activity increased in the third quarter, however, a shortage of crews impaired the Corporation’s ability to service the increased activity level.  Ongoing recruiting efforts are allowing the Corporation to increase its available crews and it is expected that High Arctic’s activity will increase in the fourth quarter.

As a result of the increased revenue, operating margin increased to $11.2 million year to date from $4.5 million in the first nine months of 2016.  Competitive pricing pressure as well as the non-recurring integration and Grande Prairie start-up costs for the Concord Well Servicing operations resulted in operating margin as a percentage of revenue declining to 19% year to date from 27% in the first nine months of 2016.  During the first and second quarters, the Corporation consolidated its Red Deer and Blackfalds operations and centralized its core maintenance activities in its Acheson maintenance facility.  The consolidation of these operations is anticipated to result in approximately $1.0 million in annualized cost savings, excluding severance costs.  The Corporation incurred approximately $1.0 million in non-recurring costs associated with these integration activities as well as the expansion of the Concord Well Servicing operations into Grande Prairie.  Excluding these non-recurring costs, operating margin as a percentage of revenue is 20%.

Ancillary Services

 Three Months Ended September 30 Nine Months Ended September 30
($ millions)2017 2016 Change% 2017 2016 Change%
Revenue5.2   7.1 (1.9)(27%) 20.8   22.1 (1.3)(6%)
Oilfield services expense (1)2.6   1.7 0.9 53% 8.1   4.8 3.3 69%
Oilfield services operating margin (1)2.6   5.4  (2.8)(52%) 12.7 17.3 (4.6)(27%)
  Operating margin (%)50%76%(26%)(34%) 61%78%(17%)(22%)

(1) Revenue includes inter-segment revenue charged to Production Services and Drilling Services from Ancillary Services division of $0.6 million for the quarter and $1.6 million year to date.  In 2016 inter-segment revenue was $0.7 million for the quarter and year to date.
(2) See ‘non-IFRS Measures’ on page 13.

The Ancillary Services segment consists of High Arctic’s oilfield rental equipment in Canada and PNG as well as its Canadian nitrogen and abandonment and compliance consulting services, acquired in the Tervita Acquisition.

Third Quarter:

Increased nitrogen services activity in the quarter combined with the additional rental and compliance consulting services added through the Tervita Acquisition partially offset slightly lower equipment rental activity in PNG during the quarter.  The lower PNG rental activity was due to lower drilling activity experienced in 2017 versus 2016 as well as the expiry of the equipment rental contracts for Rig 115 at the end of the second quarter and Rig 116 during the quarter.  The Corporation continues to explore additional geographic and industry markets to redeploy inactive rental equipment in PNG, however, no contribution from alternative markets was generated in the quarter.

Operating margin as a percentage of revenue declined to 50% in the quarter versus 76% in the third quarter of 2016.  This decline is associated with the increased contribution from lower margin service lines in the quarter as well lower rig mat rentals in PNG which generate a higher operating margin due to the low operating costs associated with the rental of the mats. 

Year to Date 2017:

Consistent with the third quarter results, increased contribution from the segment’s Canadian rentals, nitrogen services and compliance consulting partially offset lower revenue contribution from the Corporation’s PNG rentals.  Nitrogen services has benefited from increased well fracturing activity in the WCSB year to date resulting in a 60% increase in revenue year to date versus the first nine months of 2016.

The increased contribution from lower margin services has contributed to the decline in operating margin as a percentage of revenue year to date in comparison to the first nine months of 2016.

General and Administration

 Three Months Ended September 30 Nine Months Ended September 30
($ millions)2017 2016 Change% 2017 2016 Change%
General and administration4.2 3.8 0.4 11% 13.1 10.5 2.6 25%
  Percent of revenue10%8%2%25% 8%7%1%14%

Relative to the comparable periods in 2016, general and administrative costs have increased due to the additional support infrastructure added following the Tervita Acquisition.  The $4.2 million incurred in general and administrative costs in the quarter is $0.2 million lower than the average cost incurred in the first and second quarter of 2017 which incurred higher costs associated with the Corporation’s integration activities and other Corporate initiatives.  Due to the decline in revenue during the quarter, general and administrative costs increased to 10% of revenue versus 8% in the third quarter of 2016 and 8% year to date in 2017. 

Depreciation

Depreciation expense was higher in the quarter versus the comparative quarter in 2016 due to the third quarter of 2017 incurring a full three months of depreciation associated with the $64.0 million in operating assets added through the Tervita Acquisition in the third quarter of 2016.  The increased depreciation associated with these additions has also resulted in an increase in depreciation expense year to date to $19.3 million from $17.2 million in the first nine months of 2016. 

The Corporation amended its depreciation estimate for non-rig assets in the first quarter of 2017 to straight-line depreciation methodology from declining balance.  Management believes this change in depreciation methodology provides a more accurate reflection of the pattern in which the Corporation’s asset’s future economic benefits are expected to be consumed.  Additional details on this change in depreciation methodology can be found in note 3 of the September 30, 2017 unaudited condensed consolidated financial statements.  Had the Corporation continued to depreciate its assets using declining balance, depreciation expense would have been approximately $6.2 million for the third quarter of 2017 and $19.5 million year to date versus the $6.4 million and $19.3 million recorded in the respective periods under the adopted straight-line depreciation methodology.

Share-based Compensation

The decrease in share-based compensation expense to $0.1 million in the third quarter and $0.2 million year to date from $0.3 million and $0.9 million in the respective periods in 2016, is a result of less stock options being granted in 2017, as well as higher costs associated with options granted in prior years which had been fully amortized prior to 2017. 

Foreign Exchange Transactions

The Corporation has exposure to the U.S. dollar and other currencies such as the PNG Kina through its international operations.  As a result, the Corporation is exposed to foreign exchange gains and losses through the settlement of foreign denominated transactions as well as the conversion of the Corporation’s U.S. dollar based subsidiaries into Canadian dollars for financial reporting purposes. 

Gains and losses recorded by the Canadian parent on its U.S. denominated cash accounts, receivables, payables and intercompany balances are recognised as a foreign exchange gain or loss in the statement of earnings. 

High Arctic is further exposed to foreign currency fluctuations through its net investment in foreign subsidiaries.  The value of these net investments will increase or decrease based on fluctuations in the U.S. dollar relative to the Canadian dollar.  These gains and losses are unrealized until such time that High Arctic divests its investment in a foreign subsidiary and are recorded in other comprehensive income as foreign currency translation gains or losses for foreign operations.

The U.S. dollar declined in the third quarter relative to the first half of 2017; however, it remained strong relative to the Canadian dollar, with an average exchange rate of $1.253 during the third quarter of 2017 (2016 – $1.305).  This strong U.S. dollar benefited the Corporation as the majority of the Corporation’s PNG business is conducted in U.S. dollars.

As at September 30, 2017, the U.S. dollar exchange rate was 1.248 versus 1.343 as at December 31, 2016.  This decline in exchange rate has resulted in a translation loss of $10.3 million recorded in other comprehensive income for the nine months ended September 30, 2017 ($5.0 million for the three months ended September 30, 2017). 

The fluctuation in exchange rates year to date also resulted in a $0.8 million foreign exchange gain being recorded on various foreign exchange transactions.  The Corporation does not currently hedge its foreign exchange transactions or exposure.

Interest and Finance Expense

On a year to date basis, the Corporation had an average debt balance outstanding of $16.5 million, resulting in $0.9 million being incurred in interest costs ($0.2 million for the three months ended September 30, 2017).  In the third quarter of 2016 High Arctic utilized $40.0 million of its debt facility to fund the closing of the Tervita Acquisition, which was subsequently paid down from the Corporation’s available cash resources. 

Income Taxes

 Three Months Ended September 30 Nine Months Ended September 30
($ millions)2017 2016 Change 2017 2016 Change
Net earnings before income taxes  4.4  20.3 (15.9)   26.3  44.9 (18.6)
Current income tax expense  0.5  2.0 (1.5)   9.0  6.4 2.6 
Deferred income tax expense  1.1  (1.8)2.9    0.5  0.9 (0.4)
Total income tax expense  1.6    0.2 1.4    9.5    7.3 2.2 
Effective tax rate36%1%  36%16% 

The Corporation’s effective tax rate increased to 36% for the first nine months of 2017 from 16% in the comparable period of 2016.  The increased effective tax rate in 2017 is due to a combination of an increase in certain foreign tax rates effective January 1, 2017 as well as withholding taxes related to intercompany dividends declared during the year.  The low effective tax rate in the third quarter of 2016 was due to the Corporation recording $4.7 million in additional deferred tax assets through the recognition of $17.3 million in previously unrecognized tax pools associated with the Corporation’s Canadian tax pools.  As a result of the additional taxable income projected from the Tervita Acquisition, the Corporation is able to utilize a greater portion of its existing tax pools resulting in the recognition of the additional tax pools in the third quarter of 2016.   A further $1.3 million in deferred tax assets was recorded in the third quarter of 2017 as a result of improved financial performance for the Corporation’s Canadian operations.

As at September 30, 2017 High Arctic had $67.2 million in unrecognized tax pools, consisting of $30.1 million in non-capital loss pools and $37.1 million in capital loss pools, which may be utilized to offset future taxable earnings generated by the Corporation’s Canadian business operations.  With the increasing profitability of the Corporation’s Canadian business operations, the Corporation will continue to evaluate the appropriateness of recognizing additional tax pools in future reporting periods. 

Other Comprehensive Income

As discussed above under Foreign Exchange Transactions, the Corporation recorded a $10.3 million foreign currency translation loss in other comprehensive income year to date due to the strengthening of the Canadian dollar at September 30, 2017 relative to December 31, 2016.  

During the nine months ended September 30, 2017, the Corporation also recognized a $1.1 million loss on its strategic investments.  Included in the loss is the recognition of a $0.5 million loss on sale of investments year to date which had an original cost of $1.4 million, for proceeds of $0.9 million.

Liquidity and Capital Resources

 Three Months Ended September 30 Nine Months Ended September 30
($ millions)2017 2016 Change 2017 2016 Change
Cash provided by (used in):       
Operating activities  2.0    1.1   0.9    28.5    48.0   (19.5)
Investing activities  (0.7)  (42.3)  41.6    (4.2)  (49.1)  44.9 
Financing activities  0.1    27.8   (27.7)   (23.3)  11.9   (35.2)
Effect of exchange rate changes  (0.9)  0.5   (1.4)   (1.7)  (1.5)  (0.2)
Increase (decrease) in cash and cash equivalents  0.5    (12.9)  13.4    (0.7)  9.3   (10.0)
     As At
     September 30,
 2017
 December 31,
2016
 Change
Working capital(1)    55.5 28.6 26.9 
  Working capital ratio(1)    3.6:1 1.5:1 2.0:1 
Net cash(1)    17.6 3.3 14.3 
Undrawn availability under debt facilities    36.0 21.0 15.0 

(1) See ‘non-IFRS Measures’ on page 13  

High Arctic continues to maintain a strong balance sheet with $26.6 million in cash and $9.0 million outstanding on its debt facilities for a net cash balance of $17.6 million as at September 30, 2017.  Subsequent to quarter end, the Corporation paid an intercompany dividend to repatriate cash from PNG in the amount of $12.9 million less dividend withholding taxes of $1.9 million.  The net proceeds received from the intercompany dividend were applied to extinguish the Corporation’s outstanding bank debt.  

The Bank of PNG policy continues to encourage the local market in PNG Kina.  In the fourth quarter of 2016, the Bank of PNG commenced a review of all foreign currency accounts in PNG to ensure they had a legitimate business purpose.  Due to High Arctic’s requirement to transact with international suppliers and customers, High Arctic received approval to continue to maintain its U.S. dollar account within the conditions of the Bank of PNG currency regulations.  The Corporation has taken steps to increase its use of PNG Kina for local transactions when practical.  Included in the Bank of PNG’s conditions, is for future PNG drilling contracts to be settled in PNG Kina, unless otherwise approved by the Bank of PNG for the contracts to be settled in U.S. dollars.  The Corporation has received such approval for its existing contracts as well as extensions or amendments of its existing contracts with its key customer in PNG.  The Corporation will continue to seek Bank of PNG approval for future customer contracts to be settled in U.S. Dollars on a contract by contract basis, however, there is no assurance the Bank of PNG will continue to grant these approvals.

If such approvals are not received, the Corporation’s PNG drilling contracts will be settled in PNG Kina which would expose the Corporation to exchange rate fluctuations related to the PNG Kina. In addition, this may delay the Corporation’s ability to receive U.S. Dollars which may impact the Corporation’s ability to settle U.S. Dollar denominated liabilities and repatriate funds from PNG on a timely basis.  The Corporation also requires the approval from the PNG Internal Revenue Commission (“IRC”) to repatriate funds from PNG and make payments to non-resident PNG suppliers and service providers.  While delays can be experienced for the IRC approvals, such approvals have been received in the past. 

Operating Activities
As a result of the decline in Adjusted EBITDA in the quarter, funds provided from operations decreased to $9.8 million in the quarter from $11.6 million in the third quarter of 2016.  The reduced year to date Adjusted EBITDA combined with dividend withholding tax payments and increased interest expense has caused funds provided from operations to decrease 18% to $35.9 million from $43.9 million in the first nine months of 2016.

Investing Activities
High Arctic incurred $1.1 million in capital expenditures during the quarter and $5.5 million year to date primarily related to maintenance capital and upgrades to the Corporation’s well servicing rigs to enhance the efficiencies and marketability of rigs in the Corporation’s various operating areas.  Further capital investment and rig enhancements will be made as driven by customer demand and operating requirements.

During the nine months ended September 30, 2017, the Corporation generated $0.9 million in cash from the sale of a portion of its short-term investments. 

Financing Activities
During the third quarter of 2017, the Corporation increased its outstanding debt balance by $2.9 million and distributed $2.6 million in dividends.  Year to date, the Corporation has distributed $7.9 million in dividends and repaid $15.0 million on its outstanding debt balance.

Credit Facility
In the first quarter of 2017, High Arctic renewed its existing credit facility.  As at September 30, 2017, High Arctic’s credit facility consisted of a $45.0 million revolving loan facility which matures on August 31, 2019. The facility is renewable with the lender’s consent and is secured by a general security agreement over the Corporation’s assets. 

The available amount under the $45.0 million revolving loan facility is limited to 60% of the net book value of the Canadian fixed assets plus 75% of acceptable accounts receivable (85% for investment grade receivables), plus 90% of insured receivables, less priority payables as defined in the loan agreement.  As at September 30, 2017, approximately $9.0 million was drawn on the facility and total credit available to draw was approximately $36.0 million.

Outlook

After experiencing historic activity lows in 2016, the oilfield services industry continues to show signs of improvement in 2017 relative to 2016.  Drilling rig activity in the WCSB is up year to date relative to the comparable period in 2016 with a total of 4,583 wells drilled year to date in 2017 versus 2,610 wells in the comparable period in 2016 (source: CAODC).

The recent increase in activity levels has been a positive sign for the industry, however, shortages of skilled labor are impairing High Arctic’s and the industry’s ability to respond to the increasing activity levels.  In addition, the prolonged industry downturn has curtailed investment in maintenance capital which may limit the available industry fleet capacity.  In order to capitalize on these potential capacity shortages, High Arctic continues to evaluate further opportunities to expand its Canadian operations both organically through the marketing and reallocation of its existing equipment fleet, and also through potential acquisitions.  High Arctic has continued to reinvest in its fleet and is actively recruiting to expand its labour force to meet demand.

The tightening of supply has provided the Corporation opportunities to improve pricing for its services in Canada, however, increasing labor and supply costs are partially offsetting the impact of these pricing gains.  These pricing gains are largely limited to the Corporation’s non-contracted services as the Corporation is limited to provisions within the various customer contracts to adjust pricing for its contracted pricing arrangements with its key customers. 

High Arctic continues to seek opportunities to improve its operational efficiency and reduce operating costs which is demonstrated through the consolidation of its operating facilities and support functions in the second quarter.  These initiatives as well as improved pricing and increased activity are anticipated to result in improved operating margins for the Corporation’s Production Services division in upcoming quarters.

In PNG, Rig 103 commenced drilling in P’nyang at the end of October and is expected to remain active on this well into the first quarter of 2018.  Rigs 104 and 115 are anticipated to commence drilling programs in the first quarter of 2018 with preparation and mobilization activities beginning in the fourth quarter of 2017.  The fast-moving land rig arrived in PNG in late October and is currently mobilizing to its first well location with drilling anticipated to commence in December.  High Arctic is leasing this rig from a foreign service provider in order to complete a six to twelve-month drilling program.

High Arctic continues to progress discussions with its primary customer in PNG in regards to the formation of a joint drilling services company as announced on July 10, 2017.  This joint company will own and operate High Arctic’s PNG rigs (Rigs 102, 115 and 116) as well as the customer’s rigs (Rigs 101, 103 and 104) under a minimum three-year exclusive call rig services agreement.  The parties continue to work collectively towards finalizing negotiations and terms.

Subsequent to quarter end, the Corporation completed negotiations with its customer, a super major operator in PNG, related to the ongoing take-or-pay commitment for Rig 116.  In recognition of the spirit of the original drilling services agreement signed with InterOil Corporation (“InterOil”), which was acquired by its customer in February 2017, the Corporation has agreed to commence the two year take-or-pay drilling services term for the contract effective November 2, 2016.  This effective start date coincides with the commencement of drilling on Antelope 7 which was completed with Rig 115 due to its proximity to the wellsite location, however, this well could have been drilled with Rig 116 which would have resulted in the commencement of the two year take-or-pay drilling services term.  As a result, the existing contract for Rig 116 will expire on November 2, 2018 resulting in approximately three years of take-or-pay commitment generated on this rig since entering PNG. 

In conjunction with the customer’s acquisition of InterOil and the associated drilling contracts, the customer conducted a contractor qualification review for High Arctic related to future work in PNG.  As a result of this review, supported by High Arctic’s strong track record in PNG, the Corporation is pleased to announce that High Arctic has been recognized as a qualified vendor providing High Arctic with the opportunity to participate in the bidding process for additional drilling and related services in PNG beyond the contract for Rig 116.  

While High Arctic has recently experienced lower activity levels in its PNG based operations, management believes PNG’s vast reserves of natural gas combined with recent additional investments from ExxonMobil and Oil Search in PNG continues to support the long-term development of PNG’s natural gas resources.  However, the current low commodity price environment as well as the resulting economic challenges in PNG may continue to curtail industry activity levels in PNG over the short term.

Business Risks and Uncertainties

In addition to the financial risks discussed above under “Financial Risk Management” in the Corporation’s September 30, 2017 Management Discussion and Analysis (“MD&A”), below under “Forward Looking Statements” and elsewhere in this Press Release, High Arctic is exposed to a number of business risks and uncertainties that could have a material impact on the Corporation. Readers of the Corporation’s Press Release should carefully consider the risks described under the heading “Risk Factors” in the Corporation’s recently filed Annual Information Form for the year ended December 31, 2016 (the “AIF”), which are specifically incorporated by reference herein. The AIF and MD&A are available on SEDAR at www.sedar.com, a copy of which can be obtained on request, without charge, from the Corporation.

Non-IFRS Measures

This Press Release contains references to certain financial measures that do not have a standardized meaning prescribed by IFRS and may not be comparable to the same or similar measures used by other companies.  High Arctic uses these financial measures to assess performance and believes these measures provide useful supplemental information to shareholders and investors. These financial measures are computed on a consistent basis for each reporting period and include the following:

EBITDA
Management believes that, in addition to net earnings reported in the consolidated statement of earnings and comprehensive income, EBITDA (earnings before interest, taxes, depreciation and amortization) is a useful supplemental measure of the Corporation’s performance prior to consideration of how operations are financed or how results are taxed or how depreciation and amortization affects results.  EBITDA is not intended to represent net earnings calculated in accordance with IFRS.

Adjusted EBITDA
Adjusted EBITDA is calculated based on EBITDA (as referred to above) prior to the effect of share-based compensation, gains or losses on sales or purchases of assets or investments, business acquisition costs, excess of insurance proceeds over costs and foreign exchange gains or losses. Management believes the addback for these items provides a more comparable measure of the Corporation’s operational financial performance between periods.  Adjusted EBITDA as presented is not intended to represent net earnings or other measures of financial performance calculated in accordance with IFRS. 

The following tables provide a quantitative reconciliation of consolidated net earnings to EBITDA and Adjusted EBITDA for the three and nine months ended September 30:

$ millionsThree Months
Ended
 September 30, 2017
 Three Months
Ended
 September 30, 2016
 Nine Months
 Ended
 September 30, 2017
 Nine Months
 Ended
 September 30, 2016
Net earnings for the period  2.8     20.1    16.8     37.6 
Add:       
Interest and finance expense  0.2     0.2    0.9     0.4 
Income taxes  1.6     0.2    9.5     7.3 
Depreciation  6.4     6.0    19.3     17.2 
EBITDA  11.0     26.5    46.5     62.5 
Adjustments to EBITDA:       
Gain on acquisition  -      (12.7)   -      (12.7)
Acquisition costs expensed  -      1.4    -      1.4 
Share-based compensation  0.1     0.3    0.2     0.9 
Gain on sale of assets  -      -     -      (0.1)
Foreign exchange (gain) loss  (0.5)   0.1    (0.8)   0.5 
Adjusted EBITDA  10.6     15.6    45.9     52.5 

Adjusted Net Earnings   
Adjusted net earnings is calculated based on net earnings prior to the effect of gains and transaction costs incurred for acquisitions.  Management utilizes Adjusted net earnings to present a measure of financial performance that is more comparable between periods.  Adjusted net earnings as presented is not intended to represent net earnings or other measures of financial performance calculated in accordance with IFRS.  Adjusted net earnings per share and Adjusted net earnings per share – diluted are calculated as Adjusted net earnings divided by the number of weighted average basic and diluted shares outstanding, respectively.  The following tables provide a quantitative reconciliation of net earnings to Adjusted net earnings for the three and nine months ended September 30:

$ millionsThree Months
 Ended
 September 30, 2017
 Three Months
 Ended
 September 30, 2016
 Nine Months
 Ended
 September 30, 2017
 Nine Months
 Ended
 September 30, 2016
Net earnings for the period2.8 20.1  16.8 37.6 
Adjustments to net earnings:       
Gain on acquisition -   (12.7)  -   (12.7)
Acquisition costs expensed  -    1.4    -    1.4 
Adjusted net earnings  2.8  8.8    16.8  26.3 
 

Oilfield Services Operating Margin
Oilfield services operating margin is used by management to analyze overall operating performance.  Oilfield services operating margin is not intended to represent operating income nor should it be viewed as an alternative to net earnings or other measures of financial performance calculated in accordance with IFRS.  Oilfield services operating margin is calculated as revenue less oilfield services expense.

Oilfield Services Operating Margin %
Oilfield services operating margin % is used by management to analyze overall operating performance.  Oilfield services operating margin % is calculated as oilfield services operating margin divided by revenue.

$ millionsThree Months
Ended
 September 30, 2017
 Three Months
Ended
 September 30, 2016
 Nine Months
 Ended
 September 30, 2017
 Nine Months
 Ended
 September 30, 2016
Revenue42.8  47.5  158.7  145.7 
Less:       
Oilfield services expense28.0  28.1  99.7  82.7 
Oilfield Services Operating Margin14.8  19.4  59.0  63.0 
Oilfield Services Operating Margin (%)35% 41% 37% 43%
            

Percent of Revenue
Certain figures are stated as a percent of revenue and are used by management to analyze individual components of expenses to evaluate the Corporation’s performance from prior periods and to compare its performance to other companies.

Funds Provided from Operations
Management believes that, in addition to net cash generated from operating activities as reported in the consolidated statements of cash flows, cash flow from operating activities before working capital adjustments (funds provided from operations) is a useful supplemental measure as it provides an indication of the funds generated by High Arctic’s principal business activities prior to consideration of changes in items of working capital.

This measure is used by management to analyze funds provided from operating activities prior to the net effect of changes in items of non-cash working capital, and is not intended to represent net cash generated from operating activities as calculated in accordance with IFRS.

The following tables provide a quantitative reconciliation of net cash generated from operating activities to funds provided from operations for the three and nine months ended September 30:

$ millionsThree Months
Ended
 September 30, 2017
 Three Months
Ended
 September 30, 2016
 Nine Months
 Ended
 September 30, 2017
 Nine Months
 Ended
 September 30, 2016
Net cash generated from operating activities  2.0    1.1   28.5    48.0 
Less:       
Net changes in items of non-cash working capital  7.8    10.5   7.4    (4.1)
Funds provided from operations  9.8    11.6   35.9    43.9 
         

Working capital
Working capital is used by management as another measure to analyze the operating liquidity available to the Corporation.  It is defined as current assets less current liabilities and is calculated as follows:

 As At
$ millionsSeptember 30,
  2017
 December 31,
2016
 
Current assets77.0 90.7 
Less:  
Current liabilities  (21.5)  (62.1)
Working capital55.5 28.6 
     

Net (debt) cash
Net (debt) cash is used by management to analyze the amount by which cash and cash equivalents exceed the total amount of long-term debt and bank indebtedness or vice versa.  The amount, if any, is calculated as cash and cash equivalents less total long-term debt.  The following tables provide a quantitative reconciliation of cash and cash equivalents to net (debt) cash as follows:

 As At
$ millionsSeptember 30,
2017
 December 31,
2016
 
Cash and cash equivalents  26.6    27.3 
Less:  
Long-term debt  (9.0)  (24.0)
Net (debt) cash  17.6    3.3 

 

High Arctic Energy Services Inc.
Consolidated Statements of Financial Position
As at September 30, 2017 and December 31, 2016
Unaudited - Canadian $ Millions  

 

  September 30, 2017 December 31, 2016
Assets    
Current assets    
  Cash and cash equivalents 26.6 27.3
  Accounts receivable 36.7 49.1
  Short term investments 2.8 4.8
  Inventory 9.7 8.8
  Prepaid expenses 1.2 0.7
  77.0 90.7
Non-current assets    
  Property and equipment 188.1 209.2
  Deferred tax asset 6.9 5.2
Total assets 272.0 305.1
     
Liabilities    
Current liabilities    
  Accounts payable and accrued liabilities 17.1 33.8
  Income taxes payable 0.9 0.1
  Dividend payable 0.9 0.9
  Current portion of finance lease obligation 1.3 1.7
  Current portion of deferred revenue 1.3 1.6
  Current portion of long-term debt   -  24.0
  21.5 62.1
Non-current liabilities    
  Deferred revenue   -    0.9
  Finance lease obligation   0.2   - 
  Unfavourable lease liability   3.1   3.3
  Long-term debt   9.0   - 
  Deferred tax liability   10.3   8.6
Total liabilities 44.1 74.9
     
Shareholders' equity 227.9 230.2
     
Total liabilities and shareholders' equity 272.0 305.1


High Arctic Energy Services Inc.
Consolidated Statements of Earnings and Comprehensive Income
For the three and nine months ended September 30, 2017 and 2016
Unaudited - Canadian $ Millions, except per share amounts  


  Three Months Ended
September 30
 Nine Months Ended
 September 30
  2017 2016  2017 2016 
       
Revenue   42.8   47.5    158.7   145.7 
       
Expenses      
  Oilfield services   28.0   28.1    99.7   82.7 
  General and administration   4.2   3.8    13.1   10.5 
  Depreciation   6.4   6.0    19.3   17.2 
  Share-based compensation   0.1   0.3    0.2   0.9 
    38.7   38.2    132.3   111.3 
Operating earnings for the period   4.1    9.3     26.4    34.4  
  Acquisition costs   -     1.4    -     1.4 
  Gain on acquisition   -     (12.7)   -     (12.7)
  Foreign exchange (gain) loss   (0.5)  0.1    (0.8)  0.5 
  Gain on sale of property and equipment   -    -     -    (0.1)
  Interest and finance expense   0.2   0.2    0.9   0.4 
Net earnings before income taxes   4.4    20.3     26.3    44.9  
       
  Current income tax expense   0.5   2.0    9.0   6.4 
  Deferred income tax expense (recovery)   1.1   (1.8)   0.5   0.9 
    1.6   0.2    9.5   7.3 
Net earnings for the period   2.8    20.1     16.8    37.6  
       
Earnings per share:      
  Basic 0.06 0.38  0.32 0.71 
  Diluted 0.05 0.37  0.31 0.70 
       
  Three Months Ended
 September 30
 Nine Months Ended
 September 30
  2017 2016  2017 2016 
Net earnings for the period   2.8   20.1    16.8   37.6 
Other comprehensive income (loss):      
Items that may be reclassified to profit or loss:     
Foreign currency translation (losses) gains for foreign operations   (5.7)  2.3    (10.3)  (7.8)
Items that will not be reclassified to profit or loss:     
Gains (losses) on short term investments,
net of tax (note 5)
   (0.1)  (1.6)   (1.1)  1.0 


High Arctic Energy Services Inc.
Consolidated Statements of Cash Flows
For the three and nine months ended September 30, 2017 and 2016
Unaudited - Canadian $ Millions  


 Three Months Ended
 September 30
 Nine Months Ended
 September 30
 2017 2016  2017 2016 
Net earnings for the period  2.8   20.1    16.8   37.6 
Adjustments for non-cash items:     
  Depreciation  6.4   6.0    19.3   17.2 
  Provision for onerous lease  (0.1)  -     (0.3)  -  
  Share-based compensation  0.1   0.3    0.2   0.9 
  Gain on acquisition  -    (12.7)   -    (12.7)
  Gain on sale of property and equipment  -    -     -    (0.1)
  Foreign exchange (gain) loss  (0.5)  (0.3)   (0.6)  0.1 
  Deferred income tax expense (recovery)  1.1   (1.8)   0.5   0.9 
   9.8   11.6    35.9   43.9 
Net changes in items of working capital  (7.8)  (10.5)   (7.4)  4.1 
Net cash generated from operating activities  2.0   1.1    28.5   48.0 
      
Investing activities     
  Additions of property and equipment  (1.1)  (0.1)   (5.5)  (7.5)
  Business acquisition  -    (42.8)   -    (42.8)
  Disposal of short term investments  0.3   0.6    0.9   1.1 
  Disposal of property and equipment  0.1   -     0.2   0.1 
Net changes in items of working capital  -    -     0.2   -  
Net cash used in investing activities  (0.7)  (42.3)   (4.2)  (49.1)
      
Financing activities      
  Long-term debt proceeds  3.5   40.6    11.7   42.6 
  Long-term debt repayments  (0.6)  (10.0)   (26.7)  (16.0)
  Dividend payments  (2.6)  (2.7)   (7.9)  (7.9)
  Purchase of common shares for cancellation  -    -     -    (6.5)
  Issuance of common shares, net of costs  -    -     0.1   0.3 
  Capital lease obligation payments  (0.2)  (0.1)   (0.5)  (0.6)
Net cash generated from (used in) financing activities  0.1   27.8    (23.3)  11.9 
Effect of exchange rate changes  (0.9)  0.5    (1.7)  (1.5)
Net change in cash and cash equivalents  0.5   (12.9)   (0.7)  9.3 
Cash and cash equivalents - beginning of period  26.1   37.7    27.3   15.5 
Cash and cash equivalents - end of period  26.6    24.8     26.6    24.8  
      
Cash paid for:     
Interest  0.2   0.2    0.9   0.4 
Income taxes  0.8   1.0    8.1   3.9 

Forward-Looking Statements

This Press Release contains forward-looking statements.  When used in this document, the words “may”, “would”, “could”, “will”, “intend”, “plan”, “anticipate”, “believe”, “seek”, “propose”, “estimate”, “expect”, and similar expressions are intended to identify forward-looking statements.  Such statements reflect the Corporation’s current views with respect to future events and are subject to certain risks, uncertainties and assumptions.  Many factors could cause the Corporation’s actual results, performance or achievements to vary from those described in this Press Release.  Should one or more of these risks or uncertainties materialize, or should assumptions underlying forward-looking statements prove incorrect, actual results may vary materially from those described in this Press Release as intended, planned, anticipated, believed, estimated or expected. Specific forward-looking statements in this Press Release include, among others, statements pertaining to the following: general economic and business conditions which will, among other things, impact demand for and market prices for the Corporation’s services; expectations regarding the Corporation’s ability to raise capital and manage its debt obligations; the Corporation’s ability to negotiate and execute agreements to effect the proposed joint company with its customer for business operations in PNG; future acquisitions and growth opportunities; the impact of the Tervita Acquisition on the Corporation’s financial and operational performance and growth activities; commodity prices and the impact that they have on industry activity; estimated capital expenditure programs for fiscal 2017 and subsequent periods; projections of market prices and costs; factors upon which the Corporation will decide whether or not to undertake a specific course of operational action or expansion; the Corporation’s ongoing relationship with major customers; treatment under governmental regulatory regimes and political uncertainty and civil unrest; the Corporation’s ability to maintain a U.S. dollar bank account and conduct its business in U.S. dollars in PNG; and the Corporation’s ability to repatriate excess funds from PNG as approval is received from the Bank of PNG and the PNG Internal Revenue Commission.

With respect to forward-looking statements contained in this Press Release, the Corporation has made assumptions regarding, among other things, its ability to: obtain equity and debt financing on satisfactory terms; market successfully to current and new customers; the general continuance of current or, where applicable assumed industry conditions; activity and pricing; assumptions regarding commodity prices, in particular oil and gas; the Corporation’s primary objectives, and the methods of achieving those objectives; obtain equipment from suppliers; construct property and equipment according to anticipated schedules and budgets; remain competitive in all of its operations; and attract and retain skilled employees.

The Corporation’s actual results could differ materially from those anticipated in these forward-looking statements as a result of the risk factors set forth above and elsewhere in this Press Release, along with the risk factors set out in the most recent Annual Information Form filed on SEDAR at www.sedar.com.

The forward-looking statements contained in this Press Release are expressly qualified in their entirety by this cautionary statement.  These statements are given only as of the date of this Press Release.  The Corporation does not assume any obligation to update these forward-looking statements to reflect new information, subsequent events or otherwise, except as required by law.

About High Arctic
High Arctic is a publicly traded company listed on the Toronto Stock Exchange under the symbol “HWO”.  The Corporation’s principal focus is to provide drilling and specialized well completion services, equipment rentals and other services to the oil and gas industry.

High Arctic’s largest operation is in Papua New Guinea where it provides drilling and specialized well completion services and supplies rig matting, camps and drilling support equipment on a rental basis.  The Canadian operation provides well servicing, snubbing services, nitrogen supplies and equipment on a rental basis to a large number of oil and natural gas exploration and production companies operating in Western Canada. 

For more information, please contact:

Michael Binnion 
Interim President & CEO 
Phone: 403-807-7375 
Email: michael.binnion@haes.ca 
Brian Peters
Chief Financial Officer
Phone: 587-318-2218
Email: brian.peters@haes.ca