Crew Energy Inc. Announces Fourth Quarter and Full Year 2018 Financial and Operating Results


CALGARY, March 4, 2019 /CNW/ – Crew Energy Inc. (TSX: CR) (“Crew” or the “Company”) is pleased to announce our operating and financial results for the three and twelve month periods ended December 31, 2018.  Crew’s full audited consolidated Financial Statements and Notes, as well as Management’s Discussion and Analysis (“MD&A”) for the three and twelve month periods ended December 31, 2018 are available on Crew’s website and filed on SEDAR at www.sedar.com.

Q4 & FULL YEAR 2018 HIGHLIGHTS

  • Improving Capital Efficiencies and Robust Recycle Ratios1: Crew’s 2P finding and development (“F&D”) and finding, development and acquisition (“FD&A”) costs (both including changes in future development capital) were $4.72 per boe and $4.52 per boe, respectively, while F&D recycle ratios for proved developed producing, total proved and proved plus probable reserves were 1.4x, 2.3x and 3.4x respectively, demonstrating improvement over prior years and reflecting the success of the Company’s 2018 drilling program. Proved developed producing reserves were 60.2 million boe and had a net present value discounted at 10% of $508 million, including $2.3 million of future development capital, which equates to $1.10 per share after the deduction of net debt.
  • 2018 Production of 23,885 boe per day: 2018 volumes increased 4% over 2017 and were within guidance of 23,500 and 24,500 boe per day including 2,380 bbls per day of condensate, an increase of 16% over 2017. Q4 2018 production averaged 22,383 boe per day within guidance of 22,000 and 23,000 boe per day, reflecting an average of 1,790 boe per day that was curtailed in the quarter due to low prices, and condensate volumes that were 18% higher than in Q3 2018.
  • Quarterly Adjusted Funds Flow (“AFF”)2 18% Higher: Q4 AFF totaled $23.7 million or $0.16 per fully diluted share, 18% higher than the $20.1 million or $0.13 per fully diluted share in Q3 2018, reflecting improved realized natural gas prices, reduced hedging losses and a 7% decline in net operating costs. AFF was supported by a strong operating netback1 at Greater Septimus of $18.53 per boe in Q4, which reflects an 8% increase in production, improved gas prices, lower net operating and transportation costs.
  • Rising Montney Condensate Weighting: Q4 2018 condensate volumes totaled 2,446 bbls per day, representing 11% of quarterly production and 23% of quarterly revenue. Full year 2018 condensate volumes of 2,380 bbls per day contributed 29% to annual revenue as Crew’s focus on development opportunities in the higher-value Ultra-Condensate Rich (“UCR”) area at West Septimus continued.
  • Outperformed AECO Natural Gas Prices: Average realized natural gas prices for the quarter outperformed the AECO 5A benchmark by 144%, driven by the Company’s exposure to diversified natural gas markets outside of Western Canada which will continue in 2019. Crew’s Q4 2018 realized natural gas price of $3.80 per mcf represents a 44% increase over $2.64 per mcf in Q4 2017 and a 58% increase over Q3 2018.
  • Balancing Capital Expenditures with AFF to Maintain Financial Flexibility: Net capital expenditures in 2018 totaled $93.4 million and approximated AFF of $92.0 million. Year-end net debt totaled $342.8 million, which is $2.2 million lower than at year-end 2017, and includes $300 million of term debt due in 2024 with no financial maintenance covenants.
  • Non-Core Asset Disposition: Consistent with our strategy to continue high-grading our portfolio of assets, in Q1 2019, Crew has closed the sale of non-core land with no associated production or assigned reserves, for gross proceeds of $17.5 million which will be directed to debt repayment, strengthening the balance sheet.

____________________________

1 “Finding, Development and Acquisitions costs” or “FD&A costs”, “Finding and Development costs” or “F&D costs”, “recycle ratio” and “operating netback” as previously disclosed in Crew’s February 7, 2019 reserves press release, do not have standardized meanings. See “Information Regarding Disclosure on Oil and Gas Reserves and Operational Information” contained in this news release.

2 Non-IFRS measure that does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures presented by other entities.  Refer to the section entitled “Non-IFRS Measures” contained within the Company’s MD&A filed on SEDAR. 

FINANCIAL & OPERATING HIGHLIGHTS:

FINANCIAL

($ thousands, except per share amounts)

Three months
ended

Dec. 31, 2018

Three months
ended

Dec. 31, 2017

Year ended

Dec. 31, 2018

Year ended

Dec. 31, 2017

Petroleum and natural gas sales

50,838

60,146

218,385

214,154

Adjusted Funds Flow(1)

23,712

34,087

91,996

108,129

Per share  – basic

0.16

0.23

0.61

0.73

– diluted

0.16

0.22

0.61

0.72

Net income

18,771

2,342

12,799

34,405

Per share  – basic

0.12

0.02

0.08

0.23

– diluted

0.12

0.02

0.08

0.23

Exploration and Development expenditures

33,174

36,413

103,219

238,302

Property acquisitions (net of dispositions)

175

(1,709)

(9,806)

(47,906)

Net capital expenditures

33,349

34,704

93,413

190,396

Capital Structure

($ thousands)

As at

Dec. 31, 2018

As at
Dec. 31, 2017

Working capital (surplus) / deficiency(2)

(11,984)

29,143

Bank loan

59,904

21,977

47,920

51,120

Senior Unsecured Notes

294,885

293,862

Total Net Debt

342,805

344,982

Current Debt Capacity(3)

535,000

535,000

Common Shares Outstanding (thousands)

151,730

149,328

Notes:

(1)

AFF 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 on the senior unsecured notes.  AFF does not have a standardized measure prescribed by International Financial Reporting Standards, (“IFRS”) 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 for details including a reconciliation of AFF to its most closely related IFRS measure.

(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

Dec. 31, 2018

Three months
ended

Dec. 31, 2017

Year ended

Dec. 31, 2018

Year ended

Dec. 31, 2017

Daily production

Light crude oil (bbl/d)

260

399

276

495

Heavy crude oil (bbl/d)

1,634

1,808

1,782

1,836

Condensate (bbl/d)

2,446

2,617

2,380

2,048

Other natural gas liquids (bbl/d)

1,832

1,823

1,761

1,575

Natural gas (mcf/d)

97,265

111,737

106,116

102,642

Total (boe/d @ 6:1)

22,383

25,270

23,885

23,061

Average prices (1)

Light crude oil ($/bbl)

38.18

64.91

65.32

58.34

Heavy crude oil ($/bbl)

10.38

48.73

39.27

45.14

Condensate ($/bbl)

52.85

69.60

72.22

62.03

Other natural gas liquids ($/bbl)

14.71

34.58

23.18

24.45

Natural gas ($/mcf)

3.80

2.64

2.80

3.01

Oil equivalent ($/boe)

24.69

25.87

25.05

25.44

Notes:

(1)

Average prices are before deduction of transportation costs and do not include realized gains and losses on financial instruments.   

Three months
ended

Dec. 31, 2018

Three months
ended

Dec. 31, 2017

Year ended

Dec. 31, 2018

Year ended

Dec. 31, 2017

Netback ($/boe)

Petroleum and natural gas sales

24.69

25.87

25.05

25.44

Royalties

(1.67)

(1.59)

(1.73)

(1.80)

Realized commodity hedging (loss)/gain

(0.63)

1.60

(1.22)

1.19

Marketing income(1)

1.03

0.45

Net operating costs(2)

(5.78)

(5.90)

(6.22)

(5.82)

Transportation costs

(1.81)

(1.94)

(1.84)

(2.27)

Operating netback (3)

15.83

18.04

14.49

16.74

G&A

(1.55)

(1.36)

(1.39)

(1.42)

Other income

0.43

0.11

0.12

Financing costs on long-term debt

(2.77)

(2.45)

(2.67)

(2.61)

Adjusted funds flow

11.51

14.66

10.54

12.83

Drilling Activity

Gross wells

8.0

5

14

40

Working interest wells

8.0

3.9

14

38.2

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, marketing income, 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 IFRS 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 In Line with Guidance

  • Volumes for the quarter and full year averaged 22,383 boe per day and 23,885 boe per day, respectively, in line with our guidance for both periods of 22,000 to 23,000 boe per day and of 23,500 to 24,500 boe per day, respectively despite curtailing an average of 1,790 boe per day of production in the fourth quarter. Annual volumes increased 4% over 2017, due to our successful West Septimus drilling and completions program.
  • In the interests of preserving value, during Q4, 2018 an average of 1,340 boe per day of non-Montney natural gas production and 450 bbls per day of Lloydminster heavy crude oil volumes were shut-in due to low pricing. Improvements in the oil differential have supported bringing these volumes back on line earlier than anticipated in 2019.
  • Greater Septimus production averaged 18,447 boe per day in Q4 2018 compared to 19,240 boe per day in Q3 2018 and 20,193 boe per day in Q4 2017 as wells were shut-in for offsetting completion operations during the quarter.

Revenue Contributions Reflect Pricing Environment

  • Through most of 2018, world crude oil prices outperformed 2017 as production curtailments implemented by the Organization of the Petroleum Exporting Countries (“OPEC”) in early 2018 helped reduce global supply and bolster benchmark oil prices. The overall price Crew received for our liquids production over the first three quarters of 2018 outperformed the same period of 2017 by 26%.
  • During Q4, Canada’s lack of adequate pipeline egress and crude-by-rail capacity caused a severe and sudden widening of the Canadian crude oil price differential relative to US prices. In addition, the continued strengthening of US shale oil production and a slowing global economy led to a return to an oversupplied world oil market, resulting in benchmark world prices declining significantly at the end of the year. As a result, Canadian benchmark crude oil prices, including light sweet crude and particularly Western Canadian Select (“WCS”), were subject to significantly wider discounts relative to declining global oil prices in the fourth quarter.
  • Due to the severely depressed crude oil and liquids benchmark pricing during Q4, 2018, liquids contributed 33% to Crew’s total revenue compared to 56% in Q3 2018, and 55% in Q4 2017.
  • As condensate prices are linked to the price of Canadian light crude prices, and also impacted by the demand for Canadian heavy oil, realized condensate prices in Q4 declined 35% compared to the previous quarter, and 24% compared to Q4 2017. Overall, 2018 condensate prices benefited from stronger world oil prices and hence were 16% higher than in 2017, averaging $72.22 per bbl.
  • In 2018, Canadian natural gas prices continued to be impacted by oversupply and the lack of egress outside of the major natural gas producing areas of western Canada. As a result, the Canadian benchmark AECO price declined 31% over 2017 to average $1.50 per mcf compared to $2.16 per mcf in 2017. With approximately 40% of 2018 natural gas sold at Chicago pricing and another 21% sold into the strong Alliance spot market, Crew’s 2018 natural gas sales price averaged $2.80 per mcf, representing a decline of 7% compared to 2017.
  • In the fourth quarter, the Company continued to diversify our gas marketing portfolio with the addition of a contract at NYMEX-linked pricing. With 56% of our fourth quarter natural gas sales tied to US pricing hubs, the Company benefited from a spike in US prices due to early winter cold weather experienced in the gas-consuming regions of the midwest and eastern US. The early cold pushed Chicago prices to average C$4.13 per mcf in Q4 compared to C$2.92 per mcf in the third quarter.
  • Crew’s Q4 2018 realized natural gas price of $3.80 per mcf was 58% higher than in Q3 2018 and 44% higher than Q4 2017 and represents a $2.24 premium over the average AECO benchmark price of $1.56 per mcf.

Improving Gas Prices and Lower Operating Costs Improves AFF

  • Significantly higher natural gas prices supported Crew’s AFF in Q4 2018 which totaled $23.7 million ($0.16 per diluted share), an increase of 18% over the previous quarter, while the severely depressed liquids and condensate prices combined with lower production caused Q4 2018 AFF to be 30% lower than the same period in 2017. For the full year 2018, our AFF totaled $92.0 million ($0.61 per diluted share), which was lower than the prior year largely due to a realized hedging gain recorded in 2017.
  • Corporate operating netbacks in Q4 2018 improved by 18% over Q3 to average $15.83 per boe benefitting from improved gas pricing, lower realized hedging losses and lower operating costs per boe. Crew’s Q4 and full year 2018 operating netbacks were 12% and 13% lower than the same periods in 2017.
  • Crew’s continued focus on controlling costs contributed to lower net operating costs in Q4 2018 compared to Q3 and to Q4 2017, while Q4 and full year 2018 transportation expenses per boe improved 7% and 19%, respectively, over the same periods in 2017.

Capital Expenditures Targeting Higher Margin Liquids

  • Q4 2018 net capital expenditures totaled $33.3 million and 2018 expenditures totaled $93.4 million. Of the Q4 capital, approximately $32.8 million was directed to drilling and completion activities, with $3.9 million spent on land, seismic, recompletions and other miscellaneous items.
  • During Q4 2018, the Company drilled six (6.0 net) and completed three (3.0 net) natural gas wells in the UCR area at West Septimus and drilled two (2.0 net) heavy oil wells, completed three (3.0 net) and recompleted two (2.0 net) heavy oil wells in Lloydminster.

Stable Net Debt Supports Ongoing Financial Flexibility

  • Ending 2018 net debt of $342.8 million was 1% lower than year end 2017 and includes $300 million of term debt with no financial maintenance covenants or repayment required until 2024, as well as a $235 million credit facility that was only 20% drawn after adjusting for a working capital surplus of approximately $12 million at year end.

TRANSPORTATION, MARKETING & HEDGING

Diversified Market Access Underpins Strategy

  • Crew strategically chose to monetize the inherent value in our Dawn, Sumas and Malin market exposure during 2018, which resulted in marketing revenue being realized in Q4 and for the year ended December 31, 2018, of $3.0 million and $6.9 million, respectively.
  • For 2019, our natural gas sales exposure is currently expected to be approximately 43% to Chicago, 16% to NYMEX, 15% to Dawn, 10% to Alliance ATP, 8% to Malin, 4% to Station 2 and 4% to AECO 5A.
  • The strategic pipeline from our West Septimus facility through Groundbirch connecting to the existing TCPL Saturn #2 meter station was completed late in 2018, affording our Greater Septimus gas processing complex access to the Alliance Pipeline System, Enbridge T-North System, and the TCPL/Nova System. This strategic access allows for increased exposure to further capitalize on relative pricing opportunities available on all three pipelines.

Natural Gas & Liquids Hedging

  • Approximately 36% of Crew’s budgeted 2019 natural gas volumes are hedged at $2.57 per GJ or approximately $2.71 per mcf, which increases to approximately $3.19 per mcf after adjusting for Crew’s higher heat content natural gas.
  • Natural gas hedges currently include 25,000 mmbtu per day of Chicago gas at C$3.53 per mmbtu, 7,500 mmbtu per day of Dawn gas at C$3.55 per mmbtu and 10,000 mmbtu per day of NYMEX gas at US$2.95 per mmbtu.
  • For liquids, 1,874 bbls per day of WTI are hedged at an average price of C$75.99 per bbl for 2019 and 500 bbls per day of WCS hedged for the first half of 2019 at an average price of C$52.93 per bbl. In addition, Crew has 250 bbls per day of WCS differential hedged at C$25.75 per bbl for the first half of 2019 and 500 bbls per day of WCS differential hedged at C$25.23 per bbl for the second half of 2019.

OPERATIONS & AREA OVERVIEW

NE BC Montney – Greater Septimus

  • In Q4, the final well on a five-well pad was drilled in the UCR area using a revised well design. The Company has continued to refine a number of variables in our drilling operations to improve efficiencies and as a result, have seen a 34% reduction in costs per metre of lateral length drilled. Crew continues to trial different lateral lengths, fluid systems, drill bits, downhole assemblies and fracture intensities in order to optimize cost and production efficiencies.
  • Three wells on Crew’s 15-20 five well pad were completed in the fourth quarter of 2018 and produced for 25 days in December before being shut-in to accommodate offsetting fracture operations of adjacent wells occurring in January and February. The three wells were producing at a combined sales rate of 4,584 boe per day (61% liquids), for an average per well rate of 1,528 boe per day comprised of 3.6 mmcf per day (599 boe per day) of sales gas, 776 bbls per day of condensate and 153 bbls per day of natural gas liquids (“NGL”). The condensate-gas ratio averaged 216 bbls per mmcf. In 2019, Crew plans on drilling six (6.0 net) UCR wells and completing ten (10.0 net) in the Greater Septimus area.

Greater Septimus

Production & Drilling

Q4
2018

Q3
2018

Q2
2018

Q1
2018

Q4
2017

Average daily production (boe/d)

18,447

19,240

18,953

20,467

20,193

Wells drilled (gross / net)

6 (6.0)

4 / 4.0

5 / 3.9

Wells completed (gross / net)

3 (3.0)

0 / 0

2 / 1.6

9 / 7.7

3 / 3.0

Operating Netback
($ per boe)

Q4 

2018

Q3
2018

Q2
2018

Q1
2018

Q4
2017

Revenue

26.53

22.83

22.70

25.40

24.43

Royalties

(1.58)

(1.15)

(1.35)

(1.50)

(1.19)

Realized commodity hedge (loss) / gain

(1.79)

(2.01)

(1.32)

(1.01)

1.74

Marketing income (1)

1.23

0.34

0.34

0.37

Net operating costs(2)

(4.51)

(4.61)

(4.71)

(4.45)

(3.67)

Transportation costs

(1.35)

(1.22)

(1.40)

(1.51)

(1.51)

Operating netback(3)

18.53

14.18

14.26

17.30

19.80

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, marking income, less royalties, net operating costs and transportation costs calculated on a boe basis. Operating netback does not have a standardized measure prescribed by IFRS 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 858 boe per day in Q4 2018 and 910 boe per day during 2018. Crew continues to evaluate the relative economics of Tower development as well as encouraging nearby Lower Montney well results.
  • Attachie: Of Crew’s 97 sections of land in this area, approximately 45 sections are situated within the liquids-rich hydrocarbon window. Given the positive results generated by offsetting operators, a lease retention well was drilled in January and finished on schedule and under budget.
  • Oak / Flatrock: Drilling activity is gaining momentum for liquids-rich gas in this area where Crew has over 60 sections of land. We will continue to monitor industry activity and offsetting well results from this area.

AB / SK Heavy Oil – Lloydminster

  • Q4 heavy oil activity at Lloydminster included drilling two (2.0 net) wells, completing three (3.0 net) wells and recompleting two (2.0 net) heavy oil wells, which resulted in average production volumes of 1,638 boe per day for the quarter. Production volumes were 9% lower than Q4 2017 due to shutting in lower margin production caused by extremely wide differentials along with minimal capital investment in 2018, given Crew’s investment focused in the higher-return UCR area at West Septimus.
  • WCS pricing differentials widened significantly in the fourth quarter with operating netbacks at Lloydminster averaging $2.27 per boe in the period. With differentials reaching unprecedented levels, Crew elected to reduce activity levels and preserve value by shutting-in up to 700 bbls per day, for an average of 450 bbls per day of shut-in heavy oil production in Q4.
  • Crew plans on drilling three (3.0 net) multi-lateral horizontal wells in this area in 2019 should prices be supportive.

OUTLOOK

Increasing Liquids Production and Margin Expansion

  • With an active drilling and completion program planned in the UCR area at West Septimus in 2019, Crew’s production will continue to reflect our ongoing goal of increasing the weighting of condensate in our production mix, contributing to continued improvements in realized pricing and operating netbacks. Under current strip pricing, the UCR wells being drilled by Crew are expected to generate robust internal rates of return (“IRR”) of over 70% with over $6.0 million per well of before tax net present value discounted at 10% (NPV10) 3.
  • The Company’s focus remains on optimizing netbacks and returns by drilling UCR wells that target condensate – gas ratios of 150 to 250 bbls per mmcf and are expected to pay out in approximately 12 to18 months at current prices.

Balancing Capital Expenditures with AFF

  • Crew’s 2019 capital expenditure budget, forecast to range between $95 and $105 million, is expected to approximate annual AFF and will be heavily weighted to the first quarter. This budget is designed to enable the Company to effectively manage our balance sheet and retain flexibility while averaging production of 22,000 to 23,000 boe per day. Proceeds from the sale of non-core assets in Q1 2019 of $17.5 million will be used to pay down bank debt to strengthen our financial position.
  • Q1 2019 capital expenditures are expected to be between $60 and $70 million, invested in continued Montney development including the planned drilling of five to six net UCR wells, the completion, equip and tie-in of eight net UCR wells, and the drilling of two net exploratory wells. Crew planned to complete four wells on the 4-21 pad in Q1, and the remaining two wells in Q3. The Company now plans to complete all six wells concurrently which will reduce mobilization costs and avoid production downtime in Q3 that would have resulted from shutting-in wells in order to complete the remaining two wells. Eight UCR wells are expected to be tied-in and on production by the end of May. This will position Crew with approximately $35 to $45 million to complete our 2019 capital program consisting of two net Montney completions, three multi-lateral heavy oil wells and other minor expenditures with excess funds planned to be directed to strengthening the balance sheet.

We thank our employees and directors for their commitment and dedication to the success of Crew, and we thank all of our shareholders and bondholders for their patience and continued support in this challenging environment.

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