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A service for biofuel industry professionals · Saturday, August 18, 2018 · 459,107,012 Articles · 3+ Million Readers

High Arctic Reports 2018 Second Quarter Results

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CALGARY, Alberta, Aug. 09, 2018 (GLOBE NEWSWIRE) --  High Arctic Energy Services Inc. (TSX: HWO) – “High Arctic” or the “Corporation” is pleased to announce its 2018 second quarter results.

Mr. J. Cameron Bailey, High Arctic’s CEO stated: “We are pleased to report another strong quarter during what is typically a slow period for oilfield service companies with spring break up as well as the disruption of operations due to an earthquake experienced in PNG. Concord’s well servicing operations continue to outperform resulting from our strong customer base recognizing our high quality of services offered.  High Arctic assisted with relief efforts in PNG following the earthquake and operations are now slowly returning to more normal operations.”

Highlights

The stability provided by High Arctic’s Canadian well servicing operations has helped to offset lower activity levels in the Corporation’s PNG business operations as well as reduced activity in the Corporation’s snubbing operations which continue to face headwinds in light of prolonged low natural gas pricing in the WCSB.  The Corporation continues to seek opportunities to leverage its financial position to pursue additional growth and diversification opportunities to further strengthen High Arctic’s business operations.

Second Quarter 2018:

  • High Arctic reported revenue of $47.1 million and Adjusted EBITDA of $13.9 million in the quarter.
  • Utilization for High Arctic’s 57 registered Concord Well Servicing rigs was 53% in the quarter versus industry utilization of 30% (source: Canadian Association of Oilwell Drilling Contractors “CAODC”).
  • The Corporation’s PNG operations were impacted by a large earthquake in PNG on February 25, 2018, which resulted in some operating activities being suspended during the first quarter and the customer to invoke Force Majeure on the drilling activity involving Rig 405.  After assessment of Rig 405 wellsite the customer decided to defer the well and Rig 405 has been demobilized to the port for inspection and export anticipated to occur in the third quarter.
  • Consistent with prior quarters, High Arctic declared $2.6 million ($0.05 per share) in dividends during the quarter which represents 30% of funds provided from operations in the quarter.  In addition, High Arctic repurchased and cancelled 1,097,019 shares with a value of $4.3 million under the Corporation’s NCIB during the quarter resulting in a total of $6.9 million being returned to shareholders in the quarter via dividends and share repurchases.

Year to Date 2018:

  • Year to date the Corporation reported revenue of $100.8 million and Adjusted EBITDA of $27.6 million.
  • A total of $10.5 million has been returned to shareholders year to date through dividends and share buybacks.  The Corporation maintained it’s monthly dividend of $0.0165 per share resulting in year to date dividends declared of $5.2 million.  The Corporation purchased and cancelled 1,367,427 shares for a total of $5.3 million under the Corporation’s NCIB.
  • High Arctic continues to maintain a strong balance sheet with $28.1 million in cash, for a total working capital balance of $59.9 million and no amounts outstanding on its debt.

/EIN News/ -- Select Comparative Financial Information

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

           
  Three Months Ended June 30   Six Months Ended June 30
$ millions (except per share amounts) 2018   2017   % Change   2018   2017   % Change
Revenue 47.1   51.1   (8 %)   100.8   115.9   (13 %)
EBITDA(1) 12.9   14.5   (11 %)   25.6   35.5   (28 %)
Adjusted EBITDA(1) 13.9   14.3   (3 %)   27.6   35.3   (22 %)
Adjusted EBITDA % of revenue 30 % 28 % 5 %   27 % 30 % (9 %)
Operating earnings 7.2   7.8   (8 %)   13.9   22.3   (38 %)
Net earnings  1.8   5.0   (64 %)   6.2   14.0   (56 %)
  per share (basic and diluted)(2) 0.04   0.09   (56 %)   0.12   0.26   (54 %)
Adjusted Net earnings(1)  2.4   5.0   (52 %)   6.8   14.0   (51 %)
  per share (basic and diluted)(2) 0.05   0.09   (44 %)   0.13   0.26   (50 %)
Funds provided from operations(1) 8.6   9.1   (5 %)   20.5   26.1   (21 %)
  per share (basic)(2) 0.17   0.17   0 %   0.39   0.49   (20 %)
  per share (diluted)(2) 0.16   0.17   (6 %)   0.38   0.49   (22 %)
Dividends  2.6   2.7   (4 %)   5.2   5.3   (2 %)
  per share(2) 0.05   0.05   0 %   0.10   0.10   0 %
Capital expenditures  1.3   1.8   (28 %)   3.9   4.4   (11 %)
          As at
          June 30,
 2018
December 31,
 2017
% Change
Working capital(1)         59.9   53.7   12 %
Total assets         269.3   267.0   1 %
Total non-current financial liabilities         3.3   3.6   (8 %)
Net cash, end of period(1)         28.1   22.1   27 %
Shareholders’ equity         231.7   230.8   0 %
Shares outstanding(2)         52.0   53.3   (2 %)
               

(1) Readers are cautioned that EBITDA, Adjusted EBITDA, Funds provided from operations, Net cash and Working capital do not have standardized meanings prescribed by IFRS – see “Non IFRS Measures” on page 11 for calculations of these measures.

(2) The number of shares used in calculating the net earnings per share and adjusted net earnings per share amounts is determined differently as explained note 14 in the Financial Statements.

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”. 

High Arctic conducts its business operations in three separate operating 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.   The Corporation also provides additional drilling services in PNG as requested by its 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 compliance consulting services.

Consolidated Results

                   
  Three Months Ended June 30   Six Months Ended June 30
($ millions) 2018   2017   Change %   2018   2017   Change %
Revenue 47.1   51.1   (4.0 ) (8 %)   100.8     115.9   (15.1 ) (13 %)
EBITDA(1) 12.9   14.5   (1.6 ) (11 %)   25.6     35.5   (9.9 ) (28 %)
Adjusted EBITDA(1) 13.9   14.3   (0.4 ) (3 %)   27.6     35.3   (7.7 ) (22 %)
Adjusted EBITDA % of Revenue 30 % 28 % 2 % 5 %   27 % 30 % (3 %) (10 %)
Net earnings 1.8   5.0   (3.2 ) (64 %)   6.2     14.0   (7.8 ) (56 %)
  per share (basic and diluted)(2) 0.04   0.09   (0.1 ) (56 %)   0.12     0.26   (0.1 ) (54 %)
Adjusted net earnings(1) 2.4   5.0   (2.6 ) (52 %)   6.8     14.0   (7.2 ) (51 %)
  per share (basic and diluted)(2) 0.05   0.09   (0.0 ) (44 %)   0.13     0.26   (0.1 ) (50 %)

(1) Readers are cautioned that EBITDA and Adjusted EBITDA do not have standardized meanings prescribed by IFRS – see “Non IFRS Measures” on page 11 for calculations of these measures.

(2) The number of shares used in calculating the net earnings per share and adjusted net earnings per share amounts is determined as explained in note 14 of the Financial Statements.

Second Quarter:

Activity for the Corporation’s well servicing operations increased quarter over quarter due to a short spring break up contributing to a 14% increase in well servicing revenue in the quarter relative to the second quarter of 2017.  This positive contribution was offset by lower drilling activity in PNG as well as lower Canadian nitrogen and snubbing activity, resulting in an 8% decline in consolidated revenue to $47.1 million in the quarter from $51.1 million in the second quarter of 2017. 

The 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 $13.9 million in the quarter from $14.3 million in the second quarter of 2017.  The reduced Adjusted EBITDA during the quarter combined with increased share-based compensation expense and foreign exchange losses resulted in a decline in net earnings to $1.8 million ($0.04 per share) in the quarter versus $5.0 million ($0.09 per share) in the second quarter of 2017.  Impacting net earnings in 2016 and 2017 was the anticipated declaration of a dividend from PNG to Canada in 2017, which resulted in income tax expense for dividend withholdings recognized in 2016, as compared to the 2018 dividend which was declared, withholding tax recognized and paid in the same financial year.

Year to Date 2018:

  • Consistent with the second quarter, increased activity from High Arctic’s Production Services segment was offset by lower drilling activity in PNG and lower Canadian nitrogen and snubbing activity, resulting in a 13% decrease in revenue to $100.8 million year to date versus $115.9 million in the first six months of 2017. 
  • The decline in revenue relative to the comparable period in 2017, combined with a greater proportion of revenue contribution from lower margin Production Services resulted in a 22% decrease in Adjusted EBITDA to $27.6 million versus $35.3 million in the first six months of 2017.
  • The Corporation generated $6.2 million ($0.12 per share) in net earnings year to date versus $14.0 million ($0.26 per share) in the first six months of 2017.
  • A total of $5.2 million has been returned to shareholders year to date through dividends which represents 25% of funds provided from operations year to date.

Operating Segments

Drilling Services

                   
  Three Months Ended June 30   Six Months Ended June 30
($ millions) 2018   2017   Change %   2018   2017   Change %
Revenue 23.2   28.3   (5.1 ) (18 %)   46.7   62.6   (15.9 ) (25 %)
Oilfield services expense (1) 12.6   16.1   (3.5 ) (22 %)   27.1   34.7   (7.6 ) (22 %)
Oilfield services operating margin (1) 10.6   12.2   (1.6 ) (13 %)   19.6   27.9   (8.3 ) (30 %)
  Operating margin (%) 46 % 43 % 3 % 6 %   42 % 45 % (3 %) (7 %)

(1) See ‘Non-IFRS Measures’ on page 11

The Corporation owns two heli-portable drilling rigs (Rigs 115 and 116) and operates two rigs (Rigs 103 and 104) on behalf of a major oil and gas exploration company in PNG.  In the fourth quarter of 2017, High Arctic added a fast-moving land based rig, Rig 405, to its PNG drilling fleet to complete a short-term drilling project.  Due to the duration of this project, the rig was leased from a non-PNG third-party contractor.  Following damage to the well site from the earthquake, the customer decided to terminate operations and Rig 405 has been moved to the port for inspection and is anticipated to return to Australia during the third quarter of 2018.

Second Quarter:

Drilling Services revenue declined 18% in the quarter to $23.2 million from $28.3 million in the second quarter of 2017.  This decline was due to a combination of lower pricing and drilling activity in the quarter.  In addition, the second quarter of 2017 benefitted from the higher rate take-or-pay contract contribution for Rig 115 which expired in June 2017.  Drilling activity was negatively impacted during the quarter by a large earthquake in PNG on February 25, 2018, which continued to curtail some of the Corporation’s operations in PNG. 

The customer for Rig 405 invoked the Force Majeure clause following the earthquake which occurred in February.  During this period of Force Majeure, the Corporation received its lower contracted Force Majeure rates which has largely been offset by lower operating costs.  Based on initial assessments, only minor damage was incurred to some of the support equipment and no personnel injuries were incurred as a result of the earthquake.  The customer decided to terminate operations at the wellsite and Rig 405 has been moved to the port for inspection and is anticipated to return to Australia during the third quarter.

Mobilization activity for Rig 104 was deferred by the customer while they focused resources on the earthquake response with the rig warm stacked awaiting its expected mobilization to its next well, Muruk 2, in the third quarter.  Rig 103 commenced mobilization and rig up at a drilling location in Barikewa during the quarter with the well spudding in June.  Rig 115 completed drilling at Kimu 2 in June and began demobilizing to Port Moresby where it will be stacked for maintenance activities to be conducted on it.  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 46% versus 43% in the second quarter of 2017.  Consistent with prior quarters, the standby revenue generated on Rig 116 skewed margins higher due to minimal operating costs being incurred while the rig is on standby. 

Year to Date 2018:

Consistent with the second quarter results, lower drilling activity combined with reduced contribution from take-or-pay contracted revenue from Rig 115 has contributed to a 25% decline in Drilling Services revenue to $46.7 million year to date versus $62.6 million generated in the first six months of 2017. The lower drilling activity in 2018 is a result of the major earthquake in the first quarter and resulting delays in drilling programs compared to the same period in 2017 when Rig 115 was under take-or-pay until June and Rig 104 was actively drilling.

Operating margin as a percentage of revenue decreased to 42% year to date versus 45% in the first six months of 2017.  Consistent with the second quarter results, the first six months of 2017 benefitted from revenue generated from take-or-pay contracts on Rig 115.

Production Services

  Three Months Ended June 30   Six Months Ended June 30
($ millions) 2018   2017   Change %   2018   2017   Change %
Revenue   18.0   16.8   1.2   7 %     41.3   39.3   2.0   5 %
Oilfield services expense (1)   14.7   14.4   0.3   2 %     33.9   33.1   0.8   2 %
Oilfield services operating margin (1) 3.3   2.4   0.9   38 %   7.4   6.2   1.2   19 %
  Operating margin (%) 18 % 14 % 4 % 28 %   18 % 16 % 2 % 14 %
                   
Operating Statistics:                  
 Service rigs                  
  Average Fleet (2) 57   55     2   4 %   57   54     3   6 %
  Utilization (3) 53 % 49 % 4 % 8 %   58 % 56 % 2 % 4 %
  Operating hours 27,420     24,514     2,906   12 %   59,604     55,178     4,426   8 %
  Revenue per hour 600   587     13   2 %   618   595     23   4 %
                   
Snubbing rigs                  
  Average Fleet (4) 8   9     (1 ) (11 %)   8   9   (1 ) (11 %)
  Utilization (3) 14 % 21 % (7 %) (33 %)   20 % 30 % (10 %) (33 %)
  Operating hours 996   1,752     (756 ) (43 %)   2,871   4,806   (1,935 ) (40 %)
                   

(1) See ‘Non-IFRS Measures’ on page 11

(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 Production Services segment also provides heli-portable workover services in PNG through Rig 102.  The net book value of Rig 102 is not material and no workover services were provided in PNG during 2017 or 2018 and as such no revenue was generated or costs have been incurred associated with this rig during the periods presented.

Second Quarter:

Increased quarter over quarter activity and pricing for High Arctic’s Concord Well Servicing rigs offset lower activity experienced from the Corporation’s snubbing operations in the quarter resulting in a 7% increase in revenue for the Production Services segment to $18.0 million in the quarter versus $16.8 million in the second quarter of 2017.  Operating hours for the Concord rigs increased 12% to 27,420 hours in the quarter from 24,514 hours in the second quarter of 2017.  Consistent with prior quarters, the Concord rigs achieved above industry utilization of 53% versus the 30% utilization generated by the industry’s registered well servicing rigs in the quarter (source: CAODC).  The increase in activity has allowed for pricing increases in certain areas, however, pricing remains competitive.  This increase in pricing combined with an increased exposure to higher rate operating areas allowed the average revenue per hour for the Concord rigs to increase to $600 per hour in the quarter from $587 per hour in the comparative quarter in 2017.

The positive contribution from the Concord rigs was partially offset by lower activity experienced in the Production Services snubbing operations which saw revenue decrease to $1.5 million in the quarter versus the $2.4 million generated in the second quarter of 2017.  Operating hours for the snubbing rigs in the quarter were 996 versus 1,752 hours in the second quarter of 2017.  Activity for the Corporation’s snubbing operations has been hampered over recent quarters due to prolonged low natural gas prices which is curtailing snubbing activity on natural gas completions for the Corporation’s customers.

Operating margin increased 4% since the comparative quarter in 2017, resulting in a 18% operating margin achieved in 2018 versus 14% achieved in the comparative quarter of 2017.  The increase in margin is primarily due to a decrease in operating costs in the well servicing division combined with an increase in revenue.  Operating costs in 2017 were negatively impacted by initial start-up costs associated with expanding the division into the Grande Prairie region that began to normalize in the second quarter of 2017 and onward.

Year to Date 2018:

The Production Services segment revenue increased to $41.3 million from $39.3 million in the first six months of 2017.  Year to date the Concord rigs have generated 59,604 operating hours for a 58% utilization of the Corporation’s 57 average CAODC registered service rigs versus 38% utilization achieved in the first six months for the industry’s registered service rig fleet (source: CAODC).  Year to date the Concord rigs have generated an average revenue rate of $618 per hour compared to an average revenue rate of $595 per hour for the same period in 2017.

Activity for the Corporation’s snubbing rigs has declined 40% year to date versus the first six months of 2017.  This decline in activity was due to the Corporation’s core snubbing customers directing their efforts towards completing fracturing programs during the period. 

As a result of the increased revenue, operating margin increased to $7.4 million year to date from $6.2 million in the first half of 2017.  Operating margins as a percentage of revenue increased to 18% during the period from 16% in the first six months of 2017.  The primary factors contributing to this increase are pricing increases in the industry combined with a decline in operating cost per hour resulting in higher field operating margins.

During the second quarter, the Corporation closed it’s Blackfalds facility and re-located these operations to its Acheson facility in an effort to improve cost savings and better position these operations closer to areas of field activity.  The consolidation of these operations is anticipated to result in approximately $0.6 million in annualized cost savings. 

Ancillary Services

                     
  Three Months Ended June 30   Six Months Ended June 30  
($ millions) 2018   2017   Change %   2018   2017   Change %  
Revenue 6.8     6.8   0.0   0 %   14.6     15.6   (1.0 ) (6 %)  
Oilfield services expense (1) 2.3     2.7   (0.4 ) (15 %)   5.2     5.5   (0.3 ) (5 %)  
Oilfield services operating margin (1) 4.5     4.1   0.4   10 %   9.4   10.1   (0.7 ) (7 %)  
  Operating margin (%) 66 % 60 % 6 % 10 %   64 % 65 % (1 %) (2 %)  
                   

(1) Revenue includes inter-segment revenue charged to Production Services and Drilling Services from Ancillary Services division of $0.9 million for the quarter and $1.8 million year to date.  In 2017 inter-segment revenue was $0.8 million for the quarter and $1.6 million year to date.

(2) See ‘Non-IFRS Measures’ on page 11

The Ancillary Services segment consists of High Arctic’s oilfield rental equipment in Canada and PNG as well as its Canadian nitrogen and ClearCompliance software business operations.

Second Quarter:

Growth in the segment’s Canadian and PNG rental operations offset lower nitrogen services activity during the quarter.  The growth in the Canadian rental operations over recent quarters has been due to a combination of increased well servicing operations which utilize certain rental equipment as well as successful efforts to expand the segment’s rental opportunities with new and existing customers.  The increase in PNG rental activity was due to an increase in equipment being utilized in recovery work after the earthquake.  Nitrogen activity was lower due to reduced activity from core customers in the quarter as lower natural gas pricing in the WCSB curtailed natural gas fracturing activity which is an activity driver for the Corporation’s nitrogen operations. 

Operating margin as a percentage of revenue increased to 66% in the quarter versus 60% in the second quarter of 2017.  This increase was due to the increased contribution from higher margin rental divisions in the quarter relative to the second quarter of 2017.

Year to Date 2018:

Increased rentals associated with higher activity for the Corporation’s Concord Well Servicing partially offset lower equipment rental activity in PNG and lower nitrogen services year to date.  The lower equipment rental activity was due to lower drilling activity experienced in 2018 versus 2017 as well as the expiry of the equipment rental contracts associated with Rig 115 during June 2017.

Operating margin as a percentage of revenue declined to 64% year to date from 65% in 2017.  Higher margin rental divisions in PNG and Canada made up a greater proportion of revenue in 2018, which helped offset the decline in operating margin from the nitrogen services division.

General and Administration

                   
  Three Months Ended June 30   Six Months Ended June 30
($ millions) 2018   2017   Change %   2018   2017   Change %
General and administration 4.5   4.4   0.1   2 %   8.8   8.9   (0.1 ) (1 %)
  Percent of revenue 10 % 9 % 1 % 11 %   9 % 8 % 1 % 13 %

General and administrative costs increased $0.1 million from $4.4 million in the second quarter of 2017, however on a year to date basis general and administrative costs decreased $0.1 million to $8.8 million from $8.9 million in 2017.  Due to the decline in revenue during the quarter and year to date, general and administrative costs as a percentage of revenue increased by 1% over the 2017 respective periods resulting in 10% in the second quarter and 9% year to date as a percentage of revenue.

Depreciation

Depreciation expense decreased to $6.4 million in the quarter from $6.5 million in the second quarter of 2017.  The decrease is due to the Corporation disposing of redundant equipment combined with incurring limited capital expenditures subsequent to the second quarter of 2017.  $1.7 million remains in capital under construction for items not yet placed into operational service for which depreciation has not yet commenced.

Share-based Compensation

The increase in share-based compensation to $0.3 million in the second quarter and $0.9 million year to date from nil and $0.1 million in the respective periods in 2017, is a result of a higher number of awards granted year to date in 2018 versus 2017.  The amortization costs associated with the Corporation’s option grants and deferred share units are higher in the first year subsequent to the grant versus future years. 

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 remained strong relative to the Canadian dollar, as it increased during the second quarter compared to the first quarter, with an average exchange rate of $1.291 during the second quarter of 2018 (2017 – $1.345).  The stronger U.S. dollar benefits the Corporation as the majority of the Corporation’s PNG business is conducted in U.S. dollars.

As at June 30, 2018, the U.S. dollar exchange rate was 1.317 versus 1.255 as at December 31, 2017.  This strengthening of the U.S. dollar has resulted in a translation gain of $7.0 million recorded in other comprehensive income for the six months ended June 30, 2018 ($3.1 million gain for the three months ended June 30, 2018).

The fluctuation in exchange rates year to date also resulted in a $0.7 million foreign exchange loss being recorded on various foreign exchange transactions (2017 - $0.3 million gain).  The Corporation does not currently hedge its foreign exchange transactions or exposure.

Interest and Finance Expense

On a year to date basis, the Corporation did not have any long term debt outstanding but incurred $0.2 million in bank fees and other interest charges ($0.7 million for the six months ended June 30, 2017). 

Income Taxes

  Three Months Ended June 30   Six Months Ended June 30
($ millions) 2018   2017   Change   2018   2017   Change
Net earnings before income taxes   6.4   7.7   (1.3 )     12.6   21.9   (9.3 )
Current income tax expense   4.4   5.1   (0.7 )     6.0   8.5   (2.5 )
Deferred income tax expense (recovery)   0.2     (2.4 ) 2.6       0.4     (0.6 ) 1.0  
Total income tax expense   4.6     2.7   1.9       6.4     7.9   (1.5 )
Effective tax rate 72 % 35 %     51 % 36 %  

The Corporation’s effective tax rate increased to 51% for the first six months of 2018 from 36% in the first half of 2017. The increase in effective tax rate is largely due to an increase in tax expense associated with tax withholdings on dividend payments from PNG.  During the second quarter of 2018 the Corporation paid $2.2 million in withholding taxes on the payment of intercompany dividends from PNG to Canada versus $3.1 million paid out in the second quarter of 2017.  The increase in effective tax rate quarter over quarter, despite a decrease in the amount of tax paid, is due to the Corporation recognizing  income tax expense in a prior period, 2016, when a dividend was anticipated to be declared from PNG to Canada and paid out during the second quarter of 2017, versus the income tax expense on the dividend declared and paid in 2018 being recognized when declared and paid in 2018.  The increase in income tax expense related to dividend withholding payments combined with the decrease in revenue resulted in the 37% increase in effective tax rate quarter over quarter.  

As at June 30, 2018, High Arctic had $73.0 million in unrecognized tax pools, consisting of $35.1 million in non-capital loss pools and $37.9 million in capital loss pools, which may be utilized to offset future taxable earnings generated by the Corporation’s Canadian business operations. These losses expire no earlier than 2025.

Other Comprehensive Income

As discussed above under Foreign Exchange Transactions, the Corporation recorded a $7.0 million foreign currency translation gain in other comprehensive income year to date due to the weakening of the Canadian dollar, as compared to the US dollar, at June 30, 2018 relative to December 31, 2017. 

During the six months ended June 30, 2018, the Corporation also recognized a $0.5 million unrealized loss on its strategic investments, which increased $0.2 million during the three months ended June 30, 2018 due to fluctuations in investment share prices. 

Liquidity and Capital Resources

                     
  Three Months Ended June 30   Six Months Ended June 30      
($ millions) 2018   2017   Change   2018   2017   Change      
Cash provided by (used in):                    
Operating activities   15.9     31.4     (15.5 )     20.7     26.5     (5.8 )      
Investing activities   (1.0 )   (1.6 )   0.6       (3.7 )   (3.5 )   (0.2 )      
Financing activities   (6.9 )   (22.1 )   15.2       (11.5 )   (23.4 )   11.9        
Effect of exchange rate changes   0.4     (0.7 )   1.1       0.5     (0.8 )   1.3        
Increase (decrease) in cash and cash equivalents   8.4     7.0     1.4       6.0     (1.2 )   7.2        
          As At      
          June 30,
 2018
December 31, 2017 Change      
Working capital(1)         59.9   57.6   2.3        
  Working capital ratio(1)         3.5:1 3.3:1 0.2:1      
Net cash(1)         28.1   19.7   8.4        
Undrawn availability under debt facilities         45.0   45.0   0.0        

(1) See ‘Non-IFRS Measures’ on page 11

High Arctic continues to maintain a strong balance sheet with $28.1 million in cash and no debt outstanding on its credit facility as at June 30, 2018. 

Management believes High Arctic’s current capital resources, plus anticipated cash generated from operating activities in 2018, will be sufficient to meet its planned 2018 capital expenditure program of $13.3 million and anticipated dividends and share repurchases under the Corporation’s Normal Course Issuer Bid (“NCIB”) for 2018.  Management will reassess the Corporation’s capital resource needs as changes occur in its business operations and as future growth opportunities arise.

The Bank of PNG policy continues to encourage the use of the local market currency (Kina).  Due to High Arctic’s requirement to transact with international suppliers and customers, High Arctic has received approval from the Bank of PNG 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
Funds provided from operations decreased to $8.6 million in the quarter from $9.1 million in the second quarter of 2017.  This decrease was the result of a 3% decline in Adjusted EBITDA during the quarter as well as $2.2 million paid in withholding taxes related to the intercompany dividend paid in the quarter. 

Year to date, funds provided from operations decreased 21% to $20.5 million from $26.1 million in the first six months of 2018, which is also due to lower Adjusted EBITDA and increased dividend withholding tax payments.  After working capital adjustments, net cash generated from operating activities was $20.7 million compared to $26.5 million for the first six months of 2017.

Investing Activities
High Arctic incurred $1.3 million in capital expenditures during the second quarter and $3.9 million year to date (2017 - $4.4 million) 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 quarter, the Corporation generated $0.4 million in cash from the sale of redundant equipment and $0.5 million year to date (2017 - $0.1 million). 

Financing Activities
Year to date the Corporation declared monthly dividends of $0.0165 per share, resulting in total dividends paid to shareholders of $5.2 million (2017 - $5.3 million).  In addition, the Corporation purchased and cancelled 1,367,427 shares for a total of $5.3 million under its NCIB, resulting in a total of $10.5 million being returned to shareholders via dividends and share buybacks year to date. 

Credit Facility
In the first quarter of 2017, High Arctic renewed its existing credit facility.  As at June 30, 2018, 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 June 30, 2018, no amounts were drawn on the facility and total credit available to draw was $45.0 million.

Outlook

Activity for the Corporation’s Concord well servicing operations continues to show strength after a shorter than normal second quarter slow down when weather and road bans impact operations, commonly referred to as spring breakup. Year to date, operating hours for the Concord service rigs are approximately 8% above the hours generated in the same period in 2017.  This increase in hours demonstrates the strength of High Arctic’s customer base and exposure to certain operating areas which are less impacted by seasonal spring breakup conditions. 

Similar to prior quarters, attraction and retention of sufficient field staff to meet demand continues to remain an industry challenge and has resulted in the Corporation implementing various compensation initiatives in an effort to attract and retain staff.  As seen in the second quarter results, these compensation programs have added additional costs to the Corporation’s Canadian operations, however, management believes this investment in enhanced field compensation plans, which is beginning to show results through reduced field staff turnover rates, will improve High Arctic’s ability to respond to activity demands while retaining High Arctic’s strong safety and operational performance.

While activity levels for the Corporation’s well servicing operations remain strong, low natural gas prices continue to hamper activity for the Corporation’s snubbing and N2 operations.  Management continues exploring opportunities to expand into markets with increased activity levels which may help to improve the financial contribution from these operations. 

In PNG, Rig 405 and associated equipment has been moved off the well and has been mobilized to a yard in Port Moresby for non-destructive testing inspections on equipment, CAT IV inspection of pipe and preparation for hand back to its owner and export to Australia.  The rig and equipment suffered superficial damage only in the earthquake.  Rig 103 is drilling at Barikewa in place of Rig 115 which is being moved to Port Moresby to be stacked and undergo maintenance activities. Rig 104 has commenced mobilization with a skeleton crew to its next well in Muruk in anticipation of commencing drilling late in the third quarter. Rig 116 remains stacked under contract in Port Moresby until November 2, 2018.

High Arctic and its key customer in PNG have agreed to suspend any further discussion on the formation of a jointly owned drilling company, however they have not ruled-out revisiting discussion on a commercial arrangement regarding the ownership and operations management of the drilling rigs in PNG again in the future.

Business Risks and Uncertainties

In addition to the financial risks discussed above under “Financial Risk Management”, below under “Forward Looking Statements” and elsewhere in this MD&A, 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 MD&A should carefully consider the risks described under the heading “Risk Factors” in the Corporation’s recently filed AIF for the year ended December 31, 2017, which are specifically incorporated by reference herein.  The AIF is 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 MD&A 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, other costs related to consolidating facilities, 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 six months ended June 30:

               
$ millions Three Months Ended
 June 30, 2018
  Three Months Ended
 June 30, 2017
  Six Months
 Ended
 June 30, 2018
  Six Months
 Ended
 June 30, 2017
Net earnings for the period   1.8       5.0       6.2       14.0  
Add:              
Interest and finance expense   0.1       0.3       0.2       0.7  
Income taxes   4.6       2.7       6.4       7.9  
Depreciation   6.4       6.5       12.8       12.9  
EBITDA   12.9       14.5       25.6       35.5  
Adjustments to EBITDA:              
Other expenses   0.6       -        0.6       -   
Share-based compensation   0.3       -        0.9       0.1  
Gain on sale of assets   (0.2 )     -        (0.2 )     -   
Foreign exchange (gain) loss   0.3       (0.2 )     0.7       (0.3 )
Adjusted EBITDA   13.9       14.3       27.6       35.3  

Adjusted Net Earnings
Adjusted net earnings is calculated based on net earnings prior to the effect of costs not incurred in the normal course of business, such as consolidating facilities, 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 six months ended June 30:

               
$ millions Three Months Ended
 June 30, 2018
  Three Months Ended
 June 30, 2017
  Six Months Ended
 June 30, 2018
  Six Months Ended
 June 30, 2017
Net earnings for the period 1.8     5.0   6.2   14.0
Adjustments to net earnings:              
Other expenses   0.6     -      0.6     - 
Adjusted net earnings   2.4     5.0     6.8   14.0

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.

               
$ millions Three Months
Ended
 June 30, 2018
  Three Months
Ended
 June 30, 2017
  Six Months
 Ended
 June 30, 2018
  Six Months
 Ended
 June 30, 2017
Revenue 47.1     51.1     100.8     115.9  
Less:              
Oilfield services expense 28.7     32.4     64.4     71.7  
Oilfield Services Operating Margin 18.4     18.7     36.4     44.2  
Oilfield Services Operating Margin (%) 39 %   37 %   36 %   38 %

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 six months ended June 30:

               
$ millions Three Months Ended
 June 30, 2018
  Three Months Ended
 June 30, 2017
  Six Months
 Ended
 June 30, 2018
  Six Months
 Ended
 June 30, 2017
Net cash generated from operating activities   15.9       31.4       20.7       26.5  
Less:              
Net changes in items of non-cash working capital   (7.3 )     (22.3 )     (0.2 )     (0.4 )
Funds provided from operations   8.6       9.1       20.5       26.1  

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
$ millions June 30,
  2018
  December 31, 2017  
Current assets 83.9   77.1  
Less:    
Current liabilities   (24.0 )   (23.4 )
Working capital 59.9   53.7  

Net cash
Net 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 cash as follows:

  As At
$ millions June 30,
2018
December 31, 2017
Cash and cash equivalents   28.1   22.1
Less:    
Long-term debt   -    - 
Net cash   28.1   22.1


 
High Arctic Energy Services Inc.
Consolidated Statements of Financial Position
As at June 30, 2018 and December 31, 2017
Unaudited - Canadian $ Millions  


         
    June 30, 2018   December 31, 2017
Assets        
Current assets        
  Cash and cash equivalents     28.1     22.1
  Accounts receivable     40.7     40.4
  Short term investments     1.9     2.4
  Inventory     10.7     10.0
  Income taxes receivable     1.1     1.3
  Prepaid expenses     1.4     0.9
      83.9     77.1
Non-current assets        
  Property and equipment   178.1   182.9
  Deferred tax asset   7.3   7.0
Total assets   269.3   267.0
         
Liabilities        
Current liabilities        
  Accounts payable and accrued liabilities   22.6   21.5
  Dividend payable   0.9   0.9
  Deferred revenue   0.5   1.0
    24.0   23.4
Non-current liabilities        
  Finance lease obligation     0.4     0.5
  Unfavourable lease liability     2.9     3.1
  Deferred tax liability     10.3     9.2
Total liabilities   37.6   36.2
         
Shareholders' equity   231.7   230.8
         
Total liabilities and shareholders' equity   269.3   267.0
 


 
High Arctic Energy Services Inc.
Consolidated Statements of Earnings and Comprehensive Income
For the three and six months ended June 30, 2018 and 2017
Unaudited - Canadian $ Millions, except per share amounts


                 
      Three Months Ended
June 30
  Six Months Ended
 June 30
 
      2018   2017     2018   2017    
                 
  Revenue     47.1     51.1       100.8     115.9    
                 
  Expenses              
    Oilfield services     28.7     32.4       64.4     71.7    
    General and administration     4.5     4.4       8.8     8.9    
    Depreciation     6.4     6.5       12.8     12.9    
    Share-based compensation     0.3     -        0.9     0.1    
        39.9     43.3       86.9     93.6    
  Operating earnings for the period     7.2     7.8       13.9     22.3    
    Other expenses     0.6     -        0.6     -     
    Foreign exchange (gain) loss     0.3     (0.2 )     0.7     (0.3 )  
    Gain on sale of property and equipment     (0.2 )   -        (0.2 )   -     
    Interest and finance expense     0.1     0.3       0.2     0.7    
  Net earnings before income taxes     6.4     7.7       12.6     21.9    
                 
    Current income tax expense     4.4     5.1       6.0     8.5    
    Deferred income tax expense (recovery)     0.2     (2.4 )     0.4     (0.6 )  
        4.6     2.7       6.4     7.9    
  Net earnings for the period     1.8     5.0       6.2     14.0    
                 
  Earnings per share:              
    Basic   0.04   0.09     0.12   0.26    
    Diluted   0.04   0.09     0.12   0.26    
                 
      Three Months Ended
 June 30
  Six Months Ended
 June 30
 
      2018   2017     2018   2017    
  Net earnings for the period     1.8     5.0       6.2     14.0    
  Other comprehensive income:              
  Items that may be reclassified to profit or loss:              
  Foreign currency translation gains (losses) for foreign operations     3.1     (3.2 )     7.0     (4.6 )  
  Items that may not be reclassified subsequently to net income:              
  Gains (losses) on short term investments,
net of tax
    0.2     (0.3 )     (0.5 )   (1.0 )  
  Comprehensive income for the period     5.1     1.5       12.7     8.4    
                 
  See accompanying notes to these consolidated financial statements.          
                 


 
High Arctic Energy Services Inc.
Consolidated Statements of Cash Flows
For the three and six months ended June 30, 2018 and 2017
Unaudited - Canadian $ Millions


             
    Three Months Ended
 June 30
  Six Months Ended
 June 30
    2018   2017     2018   2017  
  Net earnings for the period   1.8     5.0       6.2     14.0  
  Adjustments for non-cash items:          
    Depreciation   6.4     6.5       12.8     12.9  
    Amortization for onerous lease   (0.1 )   (0.1 )     (0.2 )   (0.2 )
    Share-based compensation   0.2     0.1       0.8     0.1  
    Gain on sale of property and equipment   (0.2 )   -        (0.2 )   -   
    Foreign exchange (gain) loss   0.3     -        0.7     (0.1 )
    Deferred income tax expense (recovery)   0.2     (2.4 )     0.4     (0.6 )
      8.6     9.1       20.5     26.1  
  Net changes in items of working capital   7.3     22.3       0.2     0.4  
  Net cash generated from operating activities   15.9     31.4       20.7     26.5  
             
  Investing activities          
    Additions of property and equipment   (1.3 )   (1.8 )     (3.9 )   (4.4 )
    Disposal of short term investments   -      -        -      0.6  
    Disposal of property and equipment   0.4     -        0.5     0.1  
  Net changes in items of working capital   (0.1 )   0.2       (0.3 )   0.2  
  Net cash used in investing activities   (1.0 )   (1.6 )     (3.7 )   (3.5 )
             
  Financing activities          
    Long-term debt proceeds   -      0.6       -      8.2  
    Long-term debt repayments   -      (20.0 )     -      (26.1 )
    Dividend payments   (2.6 )   (2.7 )     (5.2 )   (5.3 )
    Purchase of common shares for cancellation   (4.3 )   -        (5.3 )   -   
    Issuance of common shares, net of costs   0.1     0.1       0.1     0.1  
    Capital lease obligation payments   (0.1 )   (0.1 )     (1.1 )   (0.3 )
  Net cash used in financing activities   (6.9 )   (22.1 )     (11.5 )   (23.4 )
  Effect of exchange rate changes   0.4     (0.7 )     0.5     (0.8 )
  Net change in cash and cash equivalents   8.4     7.0       6.0     (1.2 )
  Cash and cash equivalents - beginning of period   19.7     19.1       22.1     27.3  
  Cash and cash equivalents - end of period   28.1     26.1       28.1     26.1  
             
  Cash paid for:          
  Interest   0.1     0.3       0.2     0.7  
  Income taxes   5.0     6.6       5.7     7.4  
             

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 with its key customer in PNG related to a commercial arrangement regarding the ownership and operations management of the drilling rigs in PNG; future acquisitions and growth opportunities; commodity prices and the impact that they have on industry activity; estimated capital expenditure programs for fiscal 2018 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:

J. Cameron Bailey            
Chief Executive Officer     
Phone: 587-318-3826
Email: cam.bailey@haes.ca

Jim Hodgson
Chief Financial Officer
Phone: 587-318-2218
Email: jim.hodgson@haes.ca

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