High Arctic Reports 2019 Second Quarter Results

NOT FOR DISTRIBUTION TO U.S. NEWSWIRE SERVICES OR FOR DISSEMINATION IN THE UNITED STATES.  ANY FAILURE TO COMPLY WITH THIS RESTRICTION MAY CONSTITUTE A VIOLATION OF U.S. SECURITIES LAW

CALGARY, Alberta, Aug. 08, 2019 (GLOBE NEWSWIRE) — High Arctic Energy Services Inc. (TSX: HWO) – “High Arctic” or the “Corporation” is pleased to announce its 2019 second quarter results.

Mr. J. Cameron Bailey, High Arctic’s CEO stated: “Our High Arctic team both in North America and in Papua New Guinea continues to operate with the utmost commitment of consistently delivering the highest quality of service with industry leading safety standards at fair and reasonable prices.  I am very proud of our team and want to acknowledge their outstanding performance of operating without a single recordable injury year to date.

Our financial results have lagged primarily due to the end of the contract for Rig 116 in Papua New Guinea, slower activity in Canada and the longer than expected time to ramp-up activities in the United States.

Well Servicing in Canada achieved some modest gains during the quarter, notwithstanding a prolonged spring breakup. The acquisition of Precision Drilling snubbing assets has allowed High Arctic to consolidate 60% of the pressure services market in Canada which we will enjoy the benefits of in future periods.

In Papua New Guinea, we continue to maintain the quality and readiness of our fleet in preparation of an expected ramp up of activity in advance of the planned expansion of the LNG facilities.  A change in leadership of the government in PNG has introduced a level of uncertainty in final contracting related to the LNG expansion potentially delaying investment decisions and commencement of field activities.

We have recently made some substantial inroads to securing consistent well service work in the United States and are extremely excited to be partnering with several new customers.”

Highlights

High Arctic generated revenue of $46.6 million in the second quarter of 2019, a decrease of $0.5 million or 1% lower than the comparable second quarter of 2018. Year to date, revenue was $93.1 million compared to $100.8 million in 2018, an 8% decrease year on year. These results were driven by low customer demand in Canada carried over from 2018 and the Q4 2018 take or pay contract expiry for Rig 116. Canadian well servicing demonstrated strong performance with both operating hours and revenue per hour being marginally above the same period last year.  This increase was offset with non-recurring expenses associated with absorbing the snubbing acquisition and startup costs for two additional units deployed to the United States.

The Corporation’s strategic priorities remain targeted on:

• Regional work force development to strengthen safety, expertise, work standards and local communities.
• A strong capital structure to provide liquidity and strength throughout the energy services economic cycles.
• Specialty niche operations with noteworthy barriers to entry.
• Deep value opportunities to consolidate existing markets and diversify into new regions.
• Solidifying customer relationships to gain market share and expand when industry conditions permit.
• Disciplined capital allocation to deliver shareholder value consistent with past performance.

Execution on these strategic priorities led to the following noteworthy developments during the first half of 2019:

• Safety excellence, no recordable incidents, and further delivery on training and education initiatives.
• Preservation of a strong capital structure characterized by no long-term debt.
• High performing operating capabilities in pressure control snubbing and deep heli-portable drilling.
• Further consolidation of the pressure control snubbing business in Canada.
• Further diversification of revenue with snubbing and well servicing expansion to the United States.

Second Quarter 2019:

• High Arctic reported revenue of $46.6 million ($47.1 million in 2018), net loss of $(4.0) million ($1.8 million gain in 2018) and Adjusted EBITDA of $4.0 million ($13.9 million in 2018).
• Utilization for High Arctic’s 59 registered Concord Well Servicing rigs was 53% in the quarter versus industry utilization of 35% (source: Canadian Association of Oilwell Drilling Contractors “CAODC”) generating more hours than previous periods and increasing market share while providing safety excellence to our customers.
• Deployment of two units to the United States generated non-recurring costs of $1.5 million for move and refurbishment expenses.
• PNG activity was up slightly with two rigs working the entire quarter. The expiry of the Rig 116 take or pay contract in November 2018 represented a decrease of $6.4 million year over year in EBITDA.

Year to Date 2019:

• High Arctic reported revenue of $93.1 million ($100.8 million in 2018), net loss of $(5.0) million ($6.2 million gain in 2018) and Adjusted EBITDA of $9.5 million ($27.6 million in 2018).
• Utilization for High Arctic’s 59 registered Concord Well Servicing rigs was 55% year to date versus industry utilization of 42% (source: Canadian Association of Oilwell Drilling Contractors “CAODC”).
• High Arctic declared $5.0 million ($0.10 per share) in dividends year to date. High Arctic repurchased and cancelled 1,257,127 shares with a value of $4.7 million under the Corporation’s NCIB during 2019 resulting in a total of $9.7 million being returned to shareholders via dividends and share repurchases.
• High Arctic continues to maintain a strong financial position with $14.7 million in net cash, an undrawn $45 million credit facility and a positive working capital position of $37.5 million.

Business Acquisition

On April 15, 2019, High Arctic acquired the assets of Precision Drilling’s snubbing services equipment, entirely located in Canada, providing High Arctic with additional quality snubbing equipment and access to experienced personnel and crews. The purchase price of $8.25 million was settled in cash from cash on hand.  The acquisition provides High Arctic with twelve additional marketed snubbing units, seven of which have been active over the last twelve months. This will provide additional capacity to further strategic diversification and growth in the United States. It will also increase High Arctic’s fleet size, scale and capability in Canada to meet the needs of customers through safe and efficient services designed to increase production and lower costs. At quarter end, High Arctic owns and operates the largest snubbing fleet in Canada consisting of a total of 33 snubbing units.

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)	2019	2018	% Change		2019	2018	% Change
Revenue	46.6	47.1	(1%)		93.1	100.8	(8%)
EBITDA(1)	4.6	12.9	(64%)		10.8	25.6	(58%)
Adjusted EBITDA(1)	4.0	13.9	(71%)		9.5	27.6	(66%)
Adjusted EBITDA % of revenue	9%	30%	(70%)		10%	27%	(63%)
Operating earnings (loss)	(2.9)	7.2	(140%)		(4.7)	13.9	(134%)
Net earnings (loss)	(4.0)	1.8	(322%)		(5.0)	6.2	(181%)
per share (basic and diluted)(2)	(0.08)	0.04	(300%)		(0.10)	0.12	(183%)
Adjusted Net earnings (loss)(1)	(4.0)	2.4	(267%)		(5.0)	6.8	(174%)
per share (basic and diluted)(2)	(0.08)	0.05	(260%)		(0.10)	0.13	(177%)
Funds provided from operations(1)	2.1	8.6	(76%)		6.9	20.5	(66%)
per share (basic and diluted)(2)	0.04	0.17	(76%)		0.14	0.39	(64%)
Dividends	2.5	2.6	(4%)		5.0	5.2	(4%)
per share(2)	0.05	0.05	0%		0.10	0.10	0%
Capital expenditures	4.3	1.3	231%		6.9	3.9	77%
					As at
					June 30, 2019	December 31, 2018	% Change
Working capital(1)					37.5	56.8	(34%)
Total assets					258.0	272.4	(5%)
Total non-current financial liabilities					19.5	14.6	34%
Net cash, end of period(1)					14.7	31.5	(53%)
Shareholders’ equity					214.9	234.2	(8%)
Shares outstanding					49.8	51.0	(2%)

1. Readers are cautioned that EBITDA, Adjusted EBITDA, Adjusted net earnings (loss), Funds from operations, working capital and Net cash do not have standardized meanings prescribed by IFRS – see “Non IFRS Measures” on page 12 for calculations of these measures.
2. The number of shares used in calculating the net earnings (loss) per share and adjusted net earnings (loss) per share amounts is determined as explained in note 15 of the Financial Statements.

Corporate Profile

Headquartered in Calgary, Alberta, Canada, High Arctic provides oilfield services to exploration and production companies operating in Canada, the United States 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”) and the United States 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.  The revenue, expenses and assets related to the 2018 third quarter acquisition of Powerstroke and Saddle Well Services have been reported within the Production Services segment as have the revenue, expenses and assets related to the 2019 second quarter acquisition of Precision Drilling snubbing business.

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)	2019	2018	Change	%		2019	2018	Change	%
Revenue	46.6	47.1	(0.5)	(1%)		93.1	100.8	(7.7)	(8%)
EBITDA(1)	4.6	12.9	(8.3)	(64%)		10.8	25.6	(14.8)	(58%)
Adjusted EBITDA(1)	4.0	13.9	(9.9)	(71%)		9.5	27.6	(18.1)	(66%)
Adjusted EBITDA % of Revenue	9%	30%	(21%)	(70%)		10%	27%	(17%)	(63%)
Net earnings (loss)	(4.0)	1.8	(5.8)	(322%)		(5.0)	6.2	(11.2)	(181%)
per share (basic and diluted)(2)	(0.08)	0.04	(0.12)	(300%)		(0.10)	0.12	(0.22)	(183%)
Adjusted net earnings (loss)(1)	(4.0)	2.4	(6.4)	(267%)		(5.0)	6.8	(11.8)	(174%)
per share (basic and diluted)(2)	(0.08)	0.05	(0.13)	(260%)		(0.10)	0.13	(0.23)	(177%)

1. Readers are cautioned that EBITDA, Adjusted EBITDA and Adjusted net earnings (loss) do not have standardized meanings prescribed by IFRS – see “Non IFRS Measures” on page 12 for calculations of these measures.
2. The number of shares used in calculating the net earnings (loss) per share and adjusted net earnings (loss) per share amounts is determined as explained in note 15 of the Financial Statements.

Second Quarter:

• Revenue for the Corporation’s Drilling Services segment decreased by $2.7 million in the second quarter of 2019 compared to the second quarter of 2018 and Ancillary Services revenue decreased $0.9 million. This was offset by the Production Services revenue increase of $3.0 million year over year. Consolidated revenue decreased 1% to $46.6 million in the quarter from $47.1 million in the second quarter of 2018.
• The decrease in consolidated revenue combined with the decreased contribution from the Drilling Services segment resulted in Adjusted EBITDA decreasing to $4.0 million in the quarter from $13.9 million in the second quarter of 2018. The decreased revenue and increase in oilfield services expenses resulted in a decrease in Net earnings to $(4.0) million, (($0.08) per share (basic)) in the quarter versus $1.8 million, ($0.04 per share (basic)) in the second quarter of 2018.

Year to Date 2019:

• Revenue for the Corporation’s Drilling Services segment decreased by $7.4 million in the first half of 2019 compared to the same period in 2018 while Ancillary Services revenue decreased by $3.0 million. This was partially offset by the revenue increase provided by Production Services. Consolidated revenue decreased 8% to $93.1 million year to date from $100.8 million in the same period of 2018.
• Adjusted EBITDA decreased to $9.5 million in the first half of 2019 from $27.6 million in the same period of 2018. Net Earnings decreased to $(5.0) million, (($0.10) per share (basic)) for the six months ended June 30, 2019 versus $6.2 million, ($0.12 per share (basic)) in the same period of 2018.

Operating Segments

Segmented Financial Results

($ millions)	2019	2018	Change	%		2019	2018	Change	%
Revenue:
Drilling Services	20.5	23.2	(2.7)	(12%)		39.3	46.7	(7.4)	(16%)
Production Services	21.0	18.0	3.0	17%		43.8	41.3	2.5	6%
Ancillary Services	5.9	6.8	(0.9)	(13%)		11.6	14.6	(3.0)	(21%)
Inter-segment eliminations	(0.8)	(0.9)	0.1	(11%)		(1.6)	(1.8)	0.2	(11%)
	46.6	47.1	(0.5)	(1%)		93.1	100.8	(7.7)	(8%)
Oilfield Service Operating Margin (1)
Drilling Services	4.3	10.6	(6.3)	(59%)		8.5	19.6	(11.1)	(57%)
Production Services	0.0	3.3	(3.3)	(100%)		2.1	7.4	(5.3)	(72%)
Ancillary Services	3.8	4.5	(0.7)	(16%)		6.7	9.4	(2.7)	(29%)
	8.1	18.4	(10.3)	(56%)		17.3	36.4	(19.1)	(52%)
Oilfield Service Operating Margin Percentage (1)
Drilling Services	21%	46%	(25%)	(54%)		22%	42%	(20%)	(48%)
Production Services	0%	18%	(18%)	(100%)		5%	18%	(13%)	(73%)
Ancillary Services	64%	66%	(2%)	(3%)		58%	64%	(6%)	(9%)
	17%	39%	(22%)	(56%)		19%	36%	(18%)	(49%)

1. See ‘Non-IFRS Measures’ on page 12

Drilling Services

	Three Months Ended June 30					Six Months Ended June 30
($ millions)	2019	2018	Change	%		2019	2018	Change	%
Revenue	20.5	23.2	(2.7)	(12%)		39.3	46.7	(7.4)	(16%)
Oilfield services expense (1)	16.2	12.6	3.6	29%		30.8	27.1	3.7	14%
Oilfield services operating margin (1)	4.3	10.6	(6.3)	(59%)		8.5	19.6	(11.1)	(57%)
Operating margin (%)	21%	46%	(25%)	(54%)		22%	42%	(20%)	(48%)

  ⁽¹⁾ See ‘Non-IFRS Measures’ on page 12

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.

Second Quarter:
Drilling Services revenue decreased 12% in the quarter to $20.5 million from $23.2 million in the second quarter of 2018. This decrease was due primarily to the end of the take or pay contract for Rig 116 which generated $6.4 million in the second quarter of 2018.

Rig 103 operated continuously during the quarter while Rig 104 operated at the Muruk 2 exploration wellsite for two months and then commenced disassembly and movement back to Moro Base in June. Rig 115 and Rig 116 were preserved in cold stack during the quarter and remain ready to redeploy.

Year to Date 2019:

Drilling Services revenue decreased 16% to $39.3 million from $46.7 million year to date. This decrease was again due to lower drilling activity and the end of the take or pay contract for Rig 116 in the fourth quarter of 2018 which is reflected in the 2018 year to date numbers.

Rig 115 and Rig 116 have been in cold stack throughout 2019 and remain ready to redeploy.

Production Services

	Three Months Ended June 30					Six Months Ended June 30
($ millions)	2019	2018	Change	%		2019	2018	Change	%
Revenue	21.0	18.0	3.0	17%		43.8	41.3	2.5	6%
Oilfield services expense (1)	21.0	14.7	6.3	43%		41.7	33.9	7.8	23%
Oilfield services operating margin (1)	0.0	3.3	(3.3)	(100%)		2.1	7.4	(5.3)	(72%)
Operating margin (%)	0%	18%	(18%)	(100%)		5%	18%	(13%)	(72%)
Operating Statistics – Canada:
Service rigs
Average Fleet (2)	57	57	–	0%		57	57	–	0%
Utilization (3)	54%	53%	1%	2%		54%	58%	-4%	(7%)
Operating hours	27,889	27,420	469	2%		55,299	59,604	(4,305)	(7%)
Revenue per hour	606	600	6	1%		620	618	2	0%
Snubbing rigs
Average Fleet (4)	18	8	10	125%		18	8	10	125%
Utilization (3)	10%	14%	(4%)	(30%)		14%	20%	(6%)	(30%)
Operating hours	1,565	996	569	57%		4,490	2,871	1,619	56%
Operating Statistics – United States:
Service rigs
Average Fleet	2	–	2	0%		2	–	2	0%
Utilization (3)	51%	–	51%	0%		40%	–	40%	0%
Operating hours	932	–	932	0%		1,435	–	1,435	0%
Revenue per hour	997	–	997	0%		1001	–	1,001	0%
Snubbing rigs
Average Fleet (4)	5	–	5	0%		5	–	5	0%
Utilization (3)	23%	–	23%	0%		24%	–	24%	0%
Operating hours	1,063	–	1,063	0%		2,144	–	2,144	0%

1. See ‘Non-IFRS Measures’ on page 12
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 and includes acquisition of Precision Drilling snubbing units in 2019.

High Arctic’s well servicing and snubbing operations are provided through its Production Services segment.  These operations are primarily conducted in the WCSB and United States 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 2019 or 2018 and as such no revenue was generated or costs incurred associated with this rig during the periods presented.

Second Quarter:

Increased quarter over quarter activity for High Arctic’s Concord Well Servicing rigs and the Corporation’s snubbing operations resulted in a 17% increase in revenue for the Production Services segment to $21.0 million in the quarter versus $18.0 million in the second quarter of 2018.  Operating hours for the Concord rigs increased 5% to 28,821 hours in the quarter from 27,420 hours in the second quarter of 2018.  Consistent with prior quarters, the Concord rigs achieved above industry utilization of 53% versus the 35% utilization generated by the industry’s registered well servicing rigs in the quarter (source: CAODC). Pricing remains competitive but with an increased exposure to higher rate operating areas, rig mix allowed the average revenue per hour for the Concord rigs to increase to $606 per hour in the quarter from $600 per hour in the comparative quarter in 2018.

The contribution from the Powerstroke acquisition and Precision Drilling snubbing acquisition resulted in an increase in the Production Services snubbing operations which saw revenue increase to $3.2 million in the quarter versus the $1.5 million generated in the second quarter of 2018.  Operating hours for the snubbing rigs in the quarter were 2,628 versus 996 hours in the second quarter of 2018.

Operating margin decreased 100% compared to the same quarter in 2018.  The decrease in margin is primarily due to extra costs related to expansion into the US and higher costs associated with repairs and maintenance programs undertaken in the quarter during slower activity early in the quarter with spring breakup.

Year to Date 2019:

Increased overall activity for High Arctic’s Concord Well Servicing rigs and the Corporation’s snubbing operations resulted in a 6% increase in revenue for the Production Services segment to $43.8 million year to date versus $41.3 million in 2018.  Operating hours for the Concord rigs decreased 5% to 56,734 hours year to date from 59,604 hours in 2018. Concord rigs achieved above industry utilization of 55% versus the 42% utilization generated by the industry’s registered well servicing rigs (source: CAODC). Average revenue per hour for the Concord rigs increased to $620 per hour year to date from $618 per hour in 2018.

Ancillary Services

	Three Months Ended June 30					Six Months Ended June 30
($ millions)	2019	2018	Change	%		2019	2018	Change	%
Revenue	5.9	6.8	(0.9)	(13%)		11.6	14.6	(3.0)	(21%)
Oilfield services expense (1)	2.1	2.3	(0.2)	(9%)		4.9	5.2	(0.3)	(6%)
Oilfield services operating margin (1)	3.8	4.5	(0.7)	(16%)		6.7	9.4	(2.7)	(29%)
Operating margin (%)	64%	66%	(2%)	(3%)		58%	64%	(6%)	(9%)

1. Revenue includes inter-segment revenue charged to Production Services and Drilling Services from Ancillary Services division of $0.9 million for the quarter.  In 2018 inter-segment revenue was $0.9 million for the quarter.
2. See ‘Non-IFRS Measures’ on page 12

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:

All contributing divisions of this segment showed decreases during the quarter relative to the second quarter in 2018 driven by lower activity levels.

Operating margin as a percentage of revenue decreased slightly to 64% in the quarter versus 66% in the second quarter of 2018.  Despite the decline in revenue, margins held up well due to firm revenue pricing.

Year to Date:

Operating margin as a percentage of revenue has decreased to 58% year to date versus 64% in 2018. Again, the decrease is due to the decreased contribution from higher margin divisions.

General and Administration

	Three Months Ended June 30					Six Months Ended June 30
($ millions)	2019	2018	Change	%		2019	2018	Change	%
General and administration	4.1	4.5	(0.4)	(9%)		7.8	8.8	(1.0)	(11%)
Percent of revenue	9%	10%	(1%)	(10%)		8%	9%	(1%)	(11%)

General and administrative costs decreased $0.4 million to $4.1 million in the second quarter 2019 compared to 2018 and $1.0 million year over year as a result of cost reduction initiatives taken through out 2018. General and administrative costs as a percentage of revenue decreased 1% quarter over quarter and 1% year over year.

Depreciation

Depreciation expense increased to $6.8 million in the second quarter from $6.4 million in the second quarter 2018 due to additional depreciation resulting from the Precision Drilling asset acquisition and the adoption of IFRS 16, Leases (“IFRS 16”).

Year to date, the Corporation incurred depreciation costs of $13.8 million versus $12.8 million year to date 2018. The Corporation has incurred depreciation costs of $0.8 million associated with right of use assets in 2019 as a result of the adoption of IFRS 16 offset by a reduction in operating lease expense by the same amount.

Share-based Compensation

The decrease in share-based compensation to $0.1 million in the second quarter and $0.4 million year to date from $0.3 million and $0.9 million in the respective periods in 2018 is a result of the reduction in the number of shares granted under share-based incentive programs.

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 currency 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 with an average exchange rate of $1.3375 during the second quarter of 2019 (2018 – $1.2912).  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, 2019, the U.S. dollar exchange rate was 1.3087 versus 1.3363 at the end of Q1 2019 and 1.3168 as at June 30, 2018.  Although year on year the US dollar strengthened against the Canadian dollar, the U.S. dollar weakened from the end of 2018 through Q2 resulting in a translation loss of $2.0 million recorded in other comprehensive income for the quarter ended and $5.0 million loss for the six months ended June 30, 2019 ($3.1 million gain for the three months ended June 30, 2018 and $7.0 million gain for the six months ended June 30, 2018).

The small change in exchange rates for the period resulted in a foreign exchange gain of $0.2 million being recorded on the various foreign exchange transactions (2018 – $0.7 million loss).  The Corporation does not currently hedge its foreign exchange transactions or exposure.

Interest and Finance Expense

During the quarter, the Corporation did not have any long term debt outstanding but incurred $0.2 million in bank fees and other interest charges and have incurred $0.4 million year to date ($0.1 million in Q2 2018 and $0.2 million year to date 2018).

Income Taxes

	Three Months Ended June 30				Six Months Ended June 30
($ millions)	2019	2018	Change		2019	2018	Change
Net earnings (loss) before income taxes	(2.4)	6.4	(8.8)		(3.4)	12.6	(16.0)
Current income tax expense	1.7	4.4	(2.7)		2.2	6.0	(3.8)
Deferred income tax expense (recovery)	(0.1)	0.2	(0.3)		(0.6)	0.4	(1.0)
Total income tax expense	1.6	4.6	(3.0)		1.6	6.4	(4.8)
Effective tax rate	-67%	72%			-47%	51%

During the second quarter of 2018 the Corporation paid $1.0 million in withholding taxes on the payment of intercompany dividends from PNG to Canada versus $2.2 million paid out in the second quarter of 2018.  The deferred income tax recovery is due to changes in timing differences between tax and accounting depreciation in PNG.

As at June 30, 2019, High Arctic had $161.1 million in unrecognized tax pools, consisting of $122.8 million in non-capital loss pools and $38.3 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.

In 2019, the Province of Alberta announced reductions to corporate income tax rates, that when fully implemented will decrease the provincial corporate income tax rate from 12% to 8% by 2022.

Other Comprehensive Income (Loss)

As discussed above under Foreign Exchange Transactions, the Corporation recorded a $2.0 million foreign currency translation loss in other comprehensive income (loss) in the second quarter as compared to a gain of $3.1 million in the second quarter of 2018.

During the six months ended June 30, 2019, the Corporation recognized realized losses on its short-term investments in the second quarter through the sale of the total outstanding owned shares.

Liquidity and Capital Resources

 

	Three Months Ended June 30				Six Months Ended June 30
($ millions)	2019	2018	Change		2019	2018	Change
Cash provided by (used in):
Operating activities	8.9	15.9	(7.0)		8.9	20.7	(11.8)
Investing activities	(12.3)	(1.0)	(11.3)		(13.7)	(3.7)	(10.0)
Financing activities	(4.8)	(6.9)	2.1		(10.6)	(11.5)	0.9
Effect of exchange rate changes	(0.1)	0.4	(0.5)		(1.4)	0.5	(1.9)
Increase (decrease) in cash and cash equivalents	(8.3)	8.4	(16.7)		(16.8)	6.0	(22.8)
					As At
					June 30, 2019	December 31, 2018	Change
Working capital(1)					37.5	56.8	(19.3)
Working capital ratio(1)					2.6 : 1	3.4 : 1	0.8:1
Net cash(1)					14.7	31.5	(16.8)
Undrawn availability under debt facilities					45.0	45.0	0.0

  ⁽¹⁾ See ‘Non-IFRS Measures’ on page 12

As at June 30, 2019, the Corporation had $nil outstanding on its debt facilities and $14.7 million in cash.

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 with its key customers 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 in future, 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
The decrease in net earnings and working capital, offset by the increase in deferred tax recovery and depreciation has resulted in funds provided from operations to decrease to $8.9 million from $15.9 million quarter on quarter 2019 to 2018.

The reduced year to date net earnings combined with increased depreciation offset by reduced share-based compensation, increased gain on sale of assets, increase in foreign exchange gain and deferred tax recovery has resulted in funds provided from operations to decrease to $8.9 million from $20.7 million in the first six months of 2019.

Investing Activities
In the second quarter the Corporation has invested $4.3 million (2018 – $1.3 million) in capital expenditures primarily related to maintenance capital and upgrades to the Corporation’s well servicing rigs. During the second quarter, High Arctic completed the acquisition of Precision Drilling snubbing business valued at $8.3 million.

Year to date the Corporation has invested an additional $6.9 million (2018 – $3.9 million) in capital expenditures 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 and the acquisition of the Precision Drilling assets. The Corporation has also generated $1.0 million on the sale of short-term investments and $1.4 million on the disposal of assets.

Financing Activities

During the quarter, the Corporation distributed $2.5 million in dividends to its shareholders. In addition, the Corporation purchased and cancelled 486,976 shares for a total of $1.8 million under its NCIB, resulting in a total of $4.3 million being returned to shareholders via dividends and share buybacks during the quarter.

For the six months ended June 30, the Corporation distributed $5.0 million in dividends to its shareholders. In addition, the Corporation purchased and cancelled 1,257,127 shares for a total of $4.7 million under its NCIB, resulting in a total of $9.7 million being returned to shareholders via dividends and share buybacks year to date.

Credit Facility 
As at June 30, 2019, High Arctic’s credit facility consisted of a $45.0 million revolving loan facility which matures on August 31, 2020. 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, 2019, there was no amount drawn on the facility and total credit available to draw was $45.0 million.

The Corporation’s loan facilities are subject to three financial covenants, which are reported to the lender on a quarterly basis:

Covenant	Required	June 30, 2019
Funded debt to EBITDA(1)(4)	2.50 : 1 Maximum	0.22 : 1
Current ratio(2)	1.25 : 1 Minimum	2.59 : 1
Fixed charge coverage ratio(3)	1.25 : 1 Minimum	5.91 : 1

1. Funded debt to EBITDA is defined as the ratio of consolidated Funded Debt to the aggregate EBITDA for the trailing 4 quarters.
2. Current ratio is defined as the ratio of consolidated current assets to consolidated net current liabilities (excluding current portion of long-term debt and other debt, if any).
3. Fixed charge coverage ratio is defined as covenant EBITDA less cash taxes, dividends, distributions and unfunded capital expenditures divided by the total of principal payments on long-term debt and capital leases plus interest, in which principal payments means the total principal amount of the loan outstanding at the end of the quarter amortized over a 7-year period.
4. EBITDA for the purposes of calculating the covenants, “covenant EBITDA,” is defined as net income plus interest expense, current tax expense, depreciation, amortization, future income tax expense (recovery), share based compensation expense less gains from foreign exchange and sale or purchase of assets.

There have been no changes to these financial covenants subsequent to June 30, 2019 and the Corporation remains in compliance with the financial covenants under its credit facility as at June 30, 2019.

Outlook

The uncertainty surrounding the addition of takeaway capacity and the mandated crude oil production cuts in Alberta, have resulted in reduced capital budgets for many Canadian oil and gas operators for 2019.  Extreme cold weather in January and February and prolonged spring breakup in certain operating areas also affected oil field activity in the first half of 2019. Overall activity levels in Canada are expected to be lower year over year for the balance of 2019. Maintaining a strong balance sheet and strict cost control are priorities for the Company, to continue operating effectively in an environment with surplus equipment and low prices for High Arctic services. High Arctic recognizes the unique challenges faced by the industry and our clients and will continue to focus on providing the highest quality of service delivered with industry leading safety standards at fair and reasonable prices.

High Arctic continues to examine opportunities to deploy existing assets from Canada into more active resource plays in the United States. High Arctic now has two well service packages and five Snubbing Units providing completion and production well servicing in the DJ Basin and the Williston Basin. Although start-up cost and establishing market share has been challenging to date, we are gaining steady work with leading operators as we build the scale necessary for sustainable operations.

The acquisition of Powerstroke opened a new market for snubbing and well services in the United States. The subsequent acquisition of Precision Drilling’s snubbing assets provides High Arctic with additional quality equipment and access to experienced personnel and crews to continue to move under utilized assets in Canada into the United States where there is better utilization and day rates.  The acquisitions result in High Arctic consolidating Canada Snubbing services and is the largest snubbing provider in Canada with 33 units estimated to represent 60% of the Canada market.  Furthermore, High Arctic is now the largest snubbing operator in the DJ Basin with five active units.

In Papua New Guinea activity has continued to be light as the oil price and associated LNG pricing has remained subdued and with the prolonged negotiations between the State and the partners in the Papua LNG project for a gas agreement.  However, we see strong potential for increasing activity depending on the specific timing of the expansion of LNG export capacity and in the maturation of exploration licences and the associated seismic exploration and drilling obligations in those licence blocks.  The announcement made that a gas sales agreement was signed between the State of Papua New Guinea and Papua LNG in April 2019 was encouraging, however a change of Prime Minister and new ministerial appointments have seen the gas agreement be referred to ministerial review as the State looks to optimise its returns from future projects. Combined with the parallel project of co-habited PNG-LNG expansion train, the proposed Papua LNG facility is expected to double LNG export capacity in PNG and project partners have indicated they still target timing for commencement of LNG shipments from expansion production in 2024.  Based on exploration license well commitments and increased optimism ahead of the LNG expansion, we expect drilling activity to increase in PNG from 2020.

In PNG, Rig 103 and 104 remained active through the quarter.  Rig 103 continued with infield well works and we expect it to continue to do so into 2020.  Rig 104 completed operations working on the Muruk 2 appraisal and commenced demobilization back to Moro where it being preserved for a short period of storage, this activity will continue through Q3. Rig 116 and Rig 115 are cold stacked in Port Moresby maintained in ready to deploy condition.  Both Rig 115 and 116 continue to be offered for services both within PNG and abroad.

High Arctic continues to be active examining acquisitions domestically and abroad, that are consistent with our strategic objective of specialty niche operations with noteworthy barriers to entry, deep value opportunities to consolidate existing markets and diversify into new regions, solidifying customer relationships to gain market share and expand when industry conditions permit.

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, 2018, 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 (loss) to EBITDA and Adjusted EBITDA for the three and six months ended June 30, 2019 and 2018:

$ millions	Three Months Ended June 30, 2019		Three Months Ended June 30, 2018		Six Months Ended June 30, 2019		Six Months Ended June 30, 2018
Net earnings (loss) for the period	(4.0)		1.8		(5.0)		6.2
Add:
Interest and finance expense	0.2		0.1		0.4		0.2
Income taxes	1.6		4.6		1.6		6.4
Depreciation	6.8		6.4		13.8		12.8
EBITDA	4.6		12.9		10.8		25.6
Adjustments to EBITDA:
Other income	(0.7)		–		(0.7)		–
Other expenses	–		0.6		–		0.6
Share-based compensation	0.1		0.3		0.4		0.9
Gain on sale of assets	–		(0.2)		(0.8)		(0.2)
Foreign exchange (gain) loss	–		0.3		(0.2)		0.7
Adjusted EBITDA	4.0		13.9		9.5		27.6

Adjusted Net Earnings (Loss)

Adjusted net earnings (loss) 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 (loss) as presented is not intended to represent net earnings (loss) or other measures of financial performance calculated in accordance with IFRS.  Adjusted net earnings (loss) per share and Adjusted net earnings (loss) per share – diluted are calculated as Adjusted net earnings (loss) divided by the number of weighted average basic and diluted shares outstanding, respectively.  The following tables provide a quantitative reconciliation of net earnings (loss) to Adjusted net earnings (loss) for the three and six months ended June 30, 2019 and 2018:

$ millions	Three Months Ended June 30, 2019		Three Months Ended June 30, 2018		Six Months Ended June 30, 2019		Six Months Ended June 30, 2018
Net earnings (loss) for the period	(4.0)		1.8		(5.0)		6.2
Adjustments to net earnings (loss):
Other expenses	–		0.6		–		0.6
Adjusted net earnings (loss)	(4.0)		2.4		(5.0)		6.8

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 (loss) 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, 2019		Three Months Ended June 30, 2018		Six Months Ended June 30, 2019		Six Months Ended June 30, 2018
Revenue	46.6		47.1		93.1		100.8
Less:
Oilfield services expense	38.5		28.7		75.8		64.4
Oilfield Services Operating Margin	8.1		18.4		17.3		36.4
Oilfield Services Operating Margin (%)	17%		39%		19%		36%

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 (used in) 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 (used in) operations) is a useful supplemental measure as it provides an indication of the funds generated (used in) 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 (used in) 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 (used in) 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 (used in) operations for the three and six months ended June 30:

$ millions	Three Months Ended June 30, 2019		Three Months Ended June 30, 2018		Six Months Ended June 30, 2019		Six Months Ended June 30, 2018
Net cash generated from operating activities	8.9		15.9		8.9		20.7
Less:
Net changes in items of non-cash working capital	(6.8)		(7.3)		(2.0)		(0.2)
Funds provided from operations	2.1		8.6		6.9		20.5

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, 2019	December 31, 2018
Current assets	61.1	80.4
Less:
Current liabilities	(23.6)	(23.6)
Working capital	37.5	56.8

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, 2019	December 31, 2018
Cash and cash equivalents	14.7	31.5
Less:
Long-term debt	–	–
Net cash	14.7	31.5

 

High Arctic Energy Services Inc.
Consolidated Statements of Financial Position
As at June 30, 2019 and December 31, 2018
Unaudited – Canadian $ Millions

		June 30, 2019		December 31, 2018
Assets
Current assets
Cash and cash equivalents		14.7		31.5
Accounts receivable		33.9		36.5
Short term investments		–		1.0
Inventory		9.7		10.6
Prepaid expenses		1.4		0.8
Income taxes receivable		1.4		–
		61.1		80.4
Non-current assets
Property and equipment		181.4		184.4
Right-of-use asset		7.9		–
Deferred tax asset		7.6		7.6
Total assets		258.0		272.4
Liabilities
Current liabilities
Accounts payable and accrued liabilities		20.3		21.6
Dividend payable		0.8		0.8
Current portion of lease liability		1.8		–
Deferred revenue		0.4		0.2
Contingent liability		0.3		1.0
		23.6		23.6
Non-current liabilities
Finance lease obligation		–		0.5
Lease liability		9.3		2.8
Deferred tax liability		10.2		11.3
Total liabilities		43.1		38.2
Shareholders’ equity		214.9		234.2
Total liabilities and shareholders’ equity		258.0		272.4

High Arctic Energy Services Inc.
Consolidated Statements of Earnings and Comprehensive Income
For the three and six months ended June 30, 2019 and 2018
Unaudited – Canadian $ Millions, except per share amounts

				Three months ended  June 30					Six months ended  June 30
				2019		2018			2019		2018
	Revenue			46.6		47.1			93.1		100.8
	Expenses
	Oilfield services			38.5		28.7			75.8		64.4
	General and administration			4.1		4.5			7.8		8.8
	Depreciation			6.8		6.4			13.8		12.8
	Share-based compensation			0.1		0.3			0.4		0.9
				49.5		39.9			97.8		86.9
	Operating earnings (loss)			(2.9	)	7.2			(4.7	)	13.9
	Other (income) expenses			(0.7	)	0.6			(0.7	)	0.6
	Foreign exchange (gain) loss			–		0.3			(0.2	)	0.7
	Gain on sale of property and equipment			–		(0.2	)		(0.8	)	(0.2	)
	Interest and finance expense			0.2		0.1			0.4		0.2
	Net earnings (loss) before income taxes			(2.4	)	6.4			(3.4	)	12.6
	Current income tax expense			1.7		4.4			2.2		6.0
	Deferred income tax expense (recovery)			(0.1	)	0.2			(0.6	)	0.4
				1.6		4.6			1.6		6.4
	Net earnings (loss) for the period			(4.0	)	1.8			(5.0	)	6.2
	Earnings (loss) per share:
	Basic			(0.08	)	0.04			(0.10	)	0.12
	Diluted			(0.08	)	0.04			(0.10	)	0.12
				Three months ended  June 30					Six months ended  June 30
				2019		2018			2019		2018
	Net earnings (loss) for the period			(4.0	)	1.8			(5.0	)	6.2
	Other comprehensive income (loss):
	Items that may be reclassified subsequently to net income:
	Foreign currency translation (losses) gains for foreign operations			(2.0	)	3.1			(5.0	)	7.0
	Items that may not be reclassified subsequently to net income:
	Gains (losses) on short term investments, net of tax (note 5)			–		0.2			–		(0.5	)
	Comprehensive income (loss) for the period			(6.0	)	5.1			(10.0	)	12.7

High Arctic Energy Services Inc.
Consolidated Statements of Cash Flows
For the three and six months ended June 30, 2019 and 2018
Unaudited – Canadian $ Millions

				Three months ended  June 30					Six months ended  June 30
				2019		2018			2019		2018
	Net earnings (loss) for the period			(4.0	)	1.8			(5.0	)	6.2
	Adjustments for:
	Depreciation			6.8		6.4			13.8		12.8
	Provision for onerous lease			–		(0.1	)		–		(0.2	)
	Share-based compensation			0.1		0.2			0.4		0.8
	Gain on sale of property and equipment			–		(0.2	)		(0.8	)	(0.2	)
	Foreign exchange (gain) loss			–		0.3			(0.2	)	0.7
	Deferred income tax expense (recovery)			(0.1	)	0.2			(0.6	)	0.4
	Gain on other income			(0.7	)	–			(0.7	)	–
				2.1		8.6			6.9		20.5
	Net changes in items of working capital			6.8		7.3			2.0		0.2
	Net cash generated from operating activities			8.9		15.9			8.9		20.7
	Investing activities
	Additions of property and equipment			(4.3	)	(1.3	)		(6.9	)	(3.9	)
	Business acquisition			(8.3	)	–			(8.3	)	–
	Proceeds on sale of short term investments			0.9		–			1.0		–
	Disposal of property and equipment			–		0.4			1.4		0.5
	Net changes in items of working capital			(0.6	)	(0.1	)		(0.9	)	(0.3	)
	Net cash used in investing activities			(12.3	)	(1.0	)		(13.7	)	(3.7	)
	Financing activities
	Long-term debt proceeds			5.0		–			5.0		–
	Long-term debt repayments			(5.0	)	–			(5.0	)	–
	Dividend payments			(2.5	)	(2.6	)		(5.0	)	(5.2	)
	Purchase of common shares for cancellation			(1.8	)	(4.3	)		(4.7	)	(5.3	)
	Issuance of common shares, net of costs			–		0.1			–		0.1
	Finance lease payments			(0.5	)	(0.1	)		(0.9	)	(1.1	)
	Net cash used in financing activities			(4.8	)	(6.9	)		(10.6	)	(11.5	)
	Effect of exchange rate changes			(0.1	)	0.4			(1.4	)	0.5
	Net change in cash and cash equivalents			(8.3	)	8.4			(16.8	)	6.0
	Cash and cash equivalents – beginning of period			23.0		19.7			31.5		22.1
	Cash and cash equivalents – end of period			14.7		28.1			14.7		28.1
	Cash paid for:
	Interest			0.2		0.1			0.4		0.2
	Income taxes			–		5.0			0.5		5.7

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; commodity prices and the impact that they have on industry activity; estimated capital expenditure programs for fiscal 2019 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 is a market leader providing drilling and specialized well completion services and supplies rig matting, camps and drilling support equipment on a rental basis in Papua New Guinea.  The Canadian and US operations provides well servicing, well abandonment, snubbing and nitrogen services and equipment on a rental basis to a large number of oil and natural gas exploration and production companies operating in Western Canada and the United States.

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