Crew Energy Inc. Announces Third Quarter 2018 Financial and Operating Results

November 5, 2018 CNW

CALGARY, Nov. 5, 2018 /CNW/ – Crew Energy Inc. (TSX: CR) (“Crew” or the “Company”) is pleased to announce our operating and financial results for the three and nine month periods ended September 30, 2018. Our Financial Statements and Notes, as well as Management’s Discussion and Analysis (“MD&A”) for the three and nine month periods ended September 30, 2018 are available on Crew’s website and filed on SEDAR.

HIGHLIGHTS

Production of 23,680 boe per day: Volumes exceeded the midpoint of guidance with capital expenditures that were below budget. Greater Septimus production of 19,240 boe per day was 6% higher than the 18,154 boe per day produced in Q3 2017.
Montney Condensate Remains in Focus: With Q3 condensate volumes of 2,077 bbls per day, Crew continued to benefit from strong realized condensate pricing in the quarter, which averaged $81.45 per bbl, a 55% increase over the $52.71 per bbl in Q3 2017.
Adjusted Funds Flow (“AFF”) Boosted by Strong Liquids Pricing: Q3 AFF totaled $20.1 million or $0.13 per fully diluted share, compared with Q2 2018 AFF of $21.8 million or $0.14 per fully diluted share, reflecting our focus on higher-value liquids production and improved liquids pricing.
Continued Natural Gas Price Outperformance vs. AECO: Q3 average realized natural gas price of $2.40 per mcf outperformed the AECO 5A benchmark of $1.19 per mcf by 102%, driven by Crew’s high heat content natural gas and exposure to diversified, higher-priced sales hubs and gas markets.
Exceptional Operational Performance with Lower Capital Spending: Net exploration and development expenditures in Q3 2018 were $23.7 million, below the lower end of our $25 to $30 million guidance range.
Ultra Condensate Rich (“UCR”) Drilling in Greater Septimus: Completed drilling four out of five wells on Crew’s first extended length lateral pad with the last well drilled early in Q4. Three of the five wells are currently being completed for production in Q4 2018, with the balance in Q1 2019.
Fully Connected to Major Export Pipelines: Crew’s pipeline from West Septimus through Groundbirch connecting to the existing TCPL Saturn meter station was completed during the quarter, further enhancing our marketing and transportation flexibility and access to markets outside of western Canada.
Strong Balance Sheet Maintained: Quarter end net debt of $332.9 million is $12 million lower than year-end 2017, which includes $300 million of term debt due in 2024 with no financial maintenance covenants.

Financial & Operating Highlights:


FINANCIAL ($ thousands, except per share amounts)	Three months ended Sept. 30, 2018	Three months ended Sept. 30, 2017	Nine months ended Sept. 30, 2018	Nine months ended Sept. 30, 2017
Petroleum and natural gas sales	54,080	47,824	167,547	154,008
Adjusted Funds Flow⁽¹⁾	20,107	24,970	68,284	74,042
Per share – basic	0.13	0.17	0.45	0.50
– diluted	0.13	0.17	0.45	0.49
Net (loss)/income	(939)	2,127	(5,972)	32,063
Per share – basic	(0.01)	0.01	(0.04)	0.22
– diluted	(0.01)	0.01	(0.04)	0.21

Exploration and Development expenditures	23,656	90,069	70,045	201,889
Property acquisitions (net of dispositions)	9	(144)	(9,981)	(46,197)
Net capital expenditures	23,665	89,925	60,064	155,692

Capital Structure ($ thousands)			As at Sept. 30, 2018	As at Dec. 31, 2017
Working capital (surplus) / deficiency⁽²⁾			(11,025)	29,143
Bank loan			49,317	21,977
			38,292	51,120
Senior Unsecured Notes			294,639	293,862
Total Net Debt			332,931	344,982
Current Debt Capacity⁽³⁾			535,000	535,000
Common Shares Outstanding (thousands)			151,730	149,328

Notes:
(1)	Adjusted funds flow is calculated as cash provided by operating activities, adding the change in non-cash working capital, decommissioning obligation expenditures and accretion of deferred financing costs. Adjusted funds flow does not have a standardized measure prescribed by International Financial Reporting Standards and therefore may not be comparable with the calculations of similar measures for other companies. See “Non-IFRS Measures” contained within Crew’s MD&A.
(2)	Working capital (surplus)/deficiency includes cash and cash equivalents plus accounts receivable less accounts payable and accrued liabilities.
(3)	Current Debt Capacity reflects the bank facility of $235 million plus $300 million in senior unsecured notes outstanding.


Operations	Three months ended Sept. 30, 2018	Three months ended Sept. 30, 2017	Nine months ended Sept. 30, 2018	Nine months ended Sept. 30, 2017
Daily production
Light crude oil (bbl/d)	269	553	282	528
Heavy crude oil (bbl/d)	1,819	1,902	1,832	1,846
Condensate (bbl/d)	2,077	2,102	2,358	1,856
Other natural gas liquids (bbl/d)	1,711	1,686	1,738	1,491
Natural gas (mcf/d)	106,821	102,046	109,099	99,577
Total (boe/d @ 6:1)	23,680	23,251	24,393	22,317
Average prices ⁽¹⁾
Light crude oil ($/bbl)	78.25	52.47	73.75	56.66
Heavy crude oil ($/bbl)	51.03	43.91	47.96	43.95
Condensate ($/bbl)	81.45	52.71	78.99	58.41
Other natural gas liquids ($/bbl)	28.15	23.71	26.19	20.29
Natural gas ($/mcf)	2.40	2.51	2.51	3.16
Oil equivalent ($/boe)	24.82	22.36	25.16	25.28

Notes:
(1)	Average prices are before deduction of transportation costs and do not include realized gains and losses on commodity hedging.


	Three months ended Sept. 30, 2018	Three months ended Sept. 30, 2017	Nine months ended Sept. 30, 2018	Nine months ended Sept. 30, 2017
Netback ($/boe)
Petroleum and natural gas sales	24.82	22.36	25.16	25.28
Royalties	(1.73)	(1.43)	(1.76)	(1.88)
Realized commodity hedging (loss)/gain	(2.09)	2.76	(1.40)	1.03
Marketing income⁽¹⁾	0.25	–	0.27	–
Net operating costs⁽²⁾	(6.21)	(5.86)	(6.36)	(5.78)
Transportation costs	(1.62)	(2.18)	(1.85)	(2.39)
Operating netback ⁽³⁾	13.42	15.65	14.07	16.26
G&A	(1.39)	(1.29)	(1.34)	(1.43)
Other income	–	–	0.15	–
Financing costs on long-term debt	(2.81)	(2.68)	(2.64)	(2.67)
Adjusted funds flow	9.22	11.68	10.24	12.16

Drilling Activity
Gross wells	6	13	6	35
Working interest wells	6.0	12.3	6.0	34.3
Success rate, net wells (%)	100%	100%	100%	97%

Notes:
(1)	Marketing income was recognized from the monetization of forward physical sales contracts offset by the cost of committed natural gas transportation that was not available during the period.
(2)	Net operating costs are calculated as gross operating costs less processing revenue.
(3)	Operating netback equals petroleum and natural gas sales including realized hedging gains and losses on commodity contracts less royalties, operating costs and transportation costs calculated on a boe basis. Operating netback and adjusted funds flow netback do not have a standardized measure prescribed by International Financial Reporting Standards and therefore may not be comparable with the calculations of similar measures for other companies. See “Non-IFRS Measures” contained within Crew’s MD&A

FINANCIAL Overview

Production Increase at Greater Septimus

Q3 2018 volumes of 23,680 boe per day were ahead of the midpoint of our quarterly guidance and were 2% higher than the same period in 2017, reflecting volumes from new wells completed late in Q2 2018.
Greater Septimus production averaged 19,240 boe per day in Q3 2018, a 6% increase over the same period in 2017 and 2% higher than Q2 2018, as the impact of wells completed in the prior quarter contributed to increased production.
Crew’s 2018 drilling program commenced in Q3, as prior 2018 quarters’ activities were focused on completion of 2017 drilled and uncompleted wells (“DUCs”) within the less condensate-rich area of West Septimus. Active drilling in the UCR area for the remainder of 2018 and 2019 is expected to advance Crew’s ongoing goal of increasing the relative weighting of condensate in the production mix and offset condensate declines in the weighting through the first nine months of 2018.

Strength in Liquids Pricing Partially Offsets Natural Gas Weakness

Liquids revenue in Q3 2018 represented 56% of total revenue, while condensate revenue alone increased 53% over Q3 2017 and represented 29% of Crew’s total petroleum and natural gas sales for the period.
Compared to Q3 2017, Crew’s realized liquids prices in Q3 2018 increased meaningfully as light crude oil was 49% higher, heavy crude oil increased 16%, condensate rose 55% and other ngl was 19% higher. Crew’s Q3 2018 realized natural gas price was 4% lower than Q3 2017, reflecting continued challenges due to a lack of takeaway and egress options in the western Canadian natural gas market.
Global crude oil prices continued to rise through Q3 2018 on concerns of shrinking world crude oil inventories, the impact of sanctions on Iran and general global geopolitical unrest. However, Canada’s lack of adequate pipeline egress and crude-by-rail capacity has limited the amount of Canadian crude oil that can be moved to markets where global pricing can be realized. As a result, Canadian benchmark crude oil prices, including light sweet crude and particularly Western Canadian Select (“WCS”), began to realize wider discounts relative to global oil prices late in the quarter extending into Q4 2018.
During the quarter, Canadian natural gas prices remained challenged relative to prices in the US due to the imbalance between supply and demand, caused by the lack of takeaway and egress options which resulted in bottlenecks at Canadian price hubs. Despite the challenged markets in Canada, North American pricing provided opportunities to increase price realizations through diversification of markets. Crew’s realized sales price for natural gas averaged $2.40 per mcf, a $1.21 premium over the average AECO benchmark price of $1.19 per mcf, due to our high heat content natural gas and exposure to diversified and higher-priced gas markets.

Adjusted Funds Flow Supported by Liquids Volumes and Pricing

AFF of $20.1 million ($0.13 per diluted share) reflected strong realized pricing for crude oil, condensate and other natural gas liquids (“ngl”) offsetting lower natural gas prices. AFF was 20% lower than Q3 2017 due to weaker natural gas pricing and the impact of a realized commodity hedge loss in 2018.
Corporate operating netback of $13.42 per boe in Q3 2018 was 5% lower than Q2 2018 reflecting the impact of a realized hedging loss that was 73% higher than the previous quarter, partially offset by lower overall cash costs. Corporate Q3 operating netback was 14% lower than Q3 2017, reflecting the impact of higher overall cash costs and the impact of a realized $2.09 per boe hedging loss compared to a hedging gain of $2.76 per boe realized in Q3 2017.
Q3 2018 revenue was consistent with the second quarter of 2018 and grew 13% over the same period in 2017 due to higher volumes from NE BC and the positive impact of stronger pricing for light and heavy crude oil, condensate and other ngl, partially offset by a decline in Lloydminster production and weaker natural gas pricing.
Corporate cash costs per boe were 2% lower than Q2 2018, as higher general and administrative and financing costs were offset by lower royalties, net operating and transportation costs. Corporate cash costs per boe were 2% higher than in Q3 2017, as higher royalties, net operating costs, general and administrative and financing costs were offset by lower transportation costs.

Capital Expenditures Below Budget

Q3 2018 exploration and development expenditures totaled $23.7 million and were primarily directed to Montneydevelopment including completion of the Groundbirch to Saturn pipeline, which represented 32% of the quarterly spend. Drilling and completions activities were 56% of the total capital program and included the drilling of four (4.0 net) liquids-rich natural gas wells in the UCR area at Greater Septimus. At Lloydminster, Crew drilled two (2.0 net) multi-lateral heavy oil wells, completed one (1.0 net) heavy oil well and recompleted twelve (11.8 net) heavy oil wells.

Stable Net Debt and Continued Balance Sheet Strength

Net debt at the end of Q3 2018 of $332.9 million was 4% lower than at year end 2017. Crew’s debt includes $300 million of term debt that has no financial maintenance covenants or repayment required until 2024 and a $235 million credit facility that was 16% drawn after adjusting for a working capital surplus of approximately $11 million.

TRANSPORTATION, MARKETING & HEDGING

Realized Natural Gas Price Exceeds AECO

Given Crew’s diversified sales portfolio, the Company’s realized natural gas sales price was 102% higher than the Canadian AECO 5A benchmark. Natural gas sales reflect the following diversified markets: approximately 36% Chicago City Gate, 23% AECO 5A, 14% AECO 7A, 19% Alliance ATP, 4% Sumas and 4% Station 2.
During Q1 2018, Crew took steps to monetize the inherent value in our Dawn and Malin market exposure for Q2 and Q3, 2018. As a result, we recognized $1.7 million of marketing revenue in Q3 2018, consistent with the previous quarter. With the differential between Canadian and US natural gas prices remaining wide entering the fourth quarter, the Company further monetized our Dawn and Malin contracts, as well as a Sumas contract. This will result in additional marketing income, after deduction of transportation costs, of approximately $2.1 million being recognized in the fourth quarter.
In addition to the realization of the Dawn, Malin and Sumas contract values, Crew’s Q4 2018 natural gas sales will be exposed approximately 48% to Chicago City Gate, 19% to AECO 5A, 15% to Alliance ATP, 12% to NYMEX and 6% to Station 2.

Flexibility on Major Export Pipelines

Completion of the strategic pipeline from our West Septimus facility through Groundbirch connecting to the existing TCPL Saturn meter station fulfills Crew’s objective of accessing all three major export pipelines in BC. When this line is commissioned on January 1, 2019, Crew’s Greater Septimus gas processing complex will have access to the Alliance Pipeline System, Enbridge T-North System, and the TCPL/Nova system, which allows the Company to manage exposure to different pricing markets and take advantage of relative pricing opportunities on all three pipelines.

Natural Gas & Liquids Hedging

Approximately 24% of budgeted 2018 natural gas volumes are hedged at an average of $2.54 per GJ or approximately $2.68 per mcf which increases to approximately $3.15 per mcf after adjusting for Crew’s heat conversion.
Through 2018, 2,648 bbls per day of WTI is hedged at a minimum average price of C$72.57 per bbl, 750 bbls per day of WCS for the second half of 2018 at an average price of C$56.62 per bbl and 400 bbls per day of OPIS Conway propane hedged at US$0.7863 per gallon or US$33.03 per bbl.
Crew’s 2019 risk management program currently has 1,874 barrels per day of WTI hedged at an average price of C$75.99 per barrel and 500 barrels per day of WCS for the first half of 2019 at an average price of C$52.93 per bbl. With some positive indications in the forward curve for natural gas, we have layered on incremental natural gas hedges and have 15,000 mmbtu per day of Chicago City Gate gas at C$3.35 per mmbtu, 2,500 mmbtu per day of Dawn gas at C$3.30 per mmbtu and 2,500 mmbtu per day of NYMEX gas at US$2.80 per mmbtu.

OPERATIONS & AREA Overview

NE BC Montney – Greater Septimus

In Q3, four wells of a five well extended length horizontal pad were drilled in the UCR area using a revised well design with the fifth well drilled early in Q4. Completion of three of the wells is currently underway using a higher intensity ‘plug and perf’ completion design to optimize condensate recovery.
Each horizontal well features lengths 30-50% greater than previous Crew wells. The longest lateral length totaled over 2,700 metres which compares to an average length of 1,840 metres on previous wells. In total, 13,000 metres of reservoir was accessed through these wells.
Crew executed this program on budget, while reducing drilling days from 21 for the first well to 12 days for the pacesetter well, with an average spud to rig release across the pad of 15.6 days.
Commencing in Q4,drilling of additional extended length lateral wells in the UCR area is planned, with five to six wells expected to be drilled by the end of 2018 and up to 22 wells available to be drilled on this pad.

Greater Septimus


Production & Drilling	Q3 2018	Q2 2018	Q1 2018	Q4 2017	Q3 2017
Average daily production (boe/d)	19,240	18,953	20,467	20,193	18,154
Wells drilled (gross / net)	4 / 4.0	–	–	5 / 3.9	13 / 12.3
Wells completed (gross / net)	0 / 0	2 / 1.6	9 / 7.7	3 / 3.0	14 / 14.0

Operating Netback ($ per boe)	Q3 2018	Q2 2018	Q1 2018	Q4 2017	Q3 2017
Revenue	22.83	22.70	25.40	24.43	20.05
Royalties	(1.15)	(1.35)	(1.50)	(1.19)	(0.89)
Realized commodity hedge (loss) / gain	(2.01)	(1.32)	(1.01)	1.74	2.97
Marketing income ⁽¹⁾	0.34	0.34	0.37	–	–
Net operating costs⁽²⁾	(4.61)	(4.71)	(4.45)	(3.67)	(3.38)
Transportation costs	(1.22)	(1.40)	(1.51)	(1.51)	(1.65)
Operating netback⁽³⁾	14.18	14.26	17.30	19.80	17.10

Notes:
(1)	Marketing income was recognized from the monetization of forward physical sales contracts offset by the cost of committed natural gas transportation that was not available during the period.
(2)	Net operating costs are calculated as gross operating costs less processing revenue.
(3)	Operating netback equals petroleum and natural gas sales including realized hedging gains and losses on commodity contracts less royalties, net operating costs and transportation costs calculated on a boe basis. Operating netback and adjusted funds flow netback do not have a standardized measure prescribed by International Financial Reporting Standards and therefore may not be comparable with the calculations of similar measures for other companies. See “Non-IFRS Measures” contained within Crew’s MD&A.

Other NE BC Montney

Tower: Production at Tower averaged 843 boe per day in Q3 2018 and was impacted by third-party offset fracturing activity in the early part of the quarter. Crew continues to evaluate the relative economics of Tower development as well as encouraging nearby Lower Montney well results.
Attachie: Crew owns 97 sections of land in this area with approximately 45 sections in the liquids-rich hydrocarbon window. An offsetting operator has been actively testing wells with condensate rates of over 1,000 bbls per day. Crew plans on drilling one well in this area in 2019.
Oak / Flatrock: Crew has over 60 sections of land in this area where drilling activity is gaining momentum for liquids-rich gas. We will continue to monitor well results from this area.
Inga: Crew has eight sections of Montney rights in this area, which is prospective for highly liquids-rich gas.

AB / SK Heavy Oil – Lloydminster

Drilling and completions activity in Q3 included drilling two, four-leg multilateral wells and one completion. This supplemented our successful 12-well recompletion program at Lloydminster, resulting in average production volumes of 1,819 bbls per day. Volumes were 5% lower than the same quarter in the prior year after minimal capital was invested during the first nine months of 2018.
Crew’s third quarter heavy oil drilling program has out-paced expectations. Production from these new wells is supported by the Company’s risk management program, with 750 boe per day of WCS hedged at $56.62 per boe and operating costs on new wells forecasted at $5.00 per boe.
WCS pricing differentials widened significantly in the latter part of the third quarter with operating netbacks at Lloydminster averaging $18.16 per boe in the period. Wider differentials have persisted into the fourth quarter. With current differentials reaching unprecedented levels, Crew has elected to reduce activity levels and shut-in higher-cost production to preserve economics while differentials remain prohibitively wide.

OUTLOOK

Operations Target Condensate Growth

With over 280,000 net acres of premium Montney land, connectivity to major export pipelines, increasing condensate production and a positive outlook for LNG development in Canada, Crew remains committed to managing through a challenging market for Canadian oil and gas commodities. Our focus on increasing liquids production from our ultra condensate-rich area at West Septimus and prudently managing our balance sheet will continue to underpin our strategy.
Crew’s successful and focused operating strategy, combined with established infrastructure and market access continues to positively impact our results. We have taken steps that enable the Company to benefit from our diversified marketing strategy, whether it be moving production to new markets that offer higher pricing or having the ability to advantageously monetize physical delivery contracts to crystalize value.

2018 Production Guidance Maintained

In Q4, Crew has been affected by third party pipeline outages and limited western Canadian egress creating low, volatile and occasionally negative natural gas prices and extremely low WCS prices. In response, Crew has elected to shut-in production volumes to preserve value and forecasts Q4 production to average 22,000 to 23,000 boe per day, with production capability of greater than 24,500 boe per day. Production to the end of September exceeded Crew’s original forecast, averaging 24,393 boe per day, positioning the Company to maintain our annual guidance of 23,500 to 24,500 boe per day.

Increased AFF Yields Additional Drilled and Uncompleted Wells (“DUCs”)

Crew’s 2018 net capital expenditure budget is expected to approximate the Company’s annual estimated AFF, which was forecast at $80 to $85 million based on the Company’s original budget. Stronger production and liquids prices earlier in the year, higher condensate production forecasted for Q4 and a significant proportion of our gas sold outside the AECO market in Q4 has resulted in Crew increasing our forecast 2018 AFF to $90 to $95 million.
The increase in forecast AFF has allowed the Company to continue drilling operations on the 4-21 pad in the UCR area during the fourth quarter, which was previously planned for 2019. As a result, Crew will be positioned to enter 2019 with seven to eight DUCs compared to two that were initially planned. This drilling program will also permit the Company to accelerate condensate production into Q1, 2019 from Q3, 2019, which based on current strip pricing, is expected to generate significant incremental AFF in 2019.
Q4 2018 capital expenditures are expected to be $30 to $35 million with annual net capital expenditures, after acquisitions and dispositions, forecast at $90 to $95 million.

We would like to thank our employees and Board of Directors for their contribution and commitment to Crew, as well as our shareholders and bondholders for their ongoing support.