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Crew Energy Inc
Symbol CR
Shares Issued 156,209,401
Close 2019-11-04 C$ 0.50
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Crew Energy loses $3.25-million in Q3

2019-11-04 07:35 ET - News Release

Mr. Dale Shwed reports

CREW ENERGY INC. ANNOUNCES THIRD QUARTER 2019 FINANCIAL AND OPERATING RESULTS HIGHLIGHTED BY 24% GROWTH IN QUARTERLY CONDENSATE VOLUMES

Crew Energy Inc. has released its operating and financial results for the three- and nine-month periods ended Sept. 30, 2019. Crew's financial statements and notes, as well as management's discussion and analysis (MD&A) for the three- and nine month-periods ended Sept. 30, 2019, are available on Crew's website and filed on SEDAR.

Third quarter 2019 highlights:

  • Average production of 22,824 barrels of oil equivalent per day with 29 per cent liquids: Liquids volumes increased to 29 per cent of production for both third quarter 2019 and year to date 2019, compared with 25 per cent in Q3 2018, representing a 16-per-cent increase. Liquids made up 58 per cent of Crew's total petroleum and natural gas sales in the quarter, while oil and condensate volumes were 67 per cent of the company's total liquids.
  • Ultracondensate-rich (UCR) Montney growth drives 24-per-cent growth in condensate volumes: Condensate production for the quarter grew 24 per cent to 2,575 barrels per day from 2,077 bbl per day in Q3 2018, and year to date increased 18 per cent to 2,773 bbl per day, reflecting the success of Crew's strategy to focus the company's production growth volumes on higher-value condensate.
  • Adjusted funds flow (AFF) reflects pricing environment: Third quarter 2019 AFF totalled $16.7-million or 11 cents per fully diluted share, while year to date, Crew generated AFF of $65.0-million or 43 cents per diluted share. Relative to the same periods in 2018, significantly weaker commodity pricing offset the benefit of higher condensate production.
  • New completions outperform: The four B zone wells at the 15-20 pad have produced 282,000 bbl of condensate in the first 210 days of production averaging 839 boe per day (40 per cent condensate), while five B zone wells at the 4-21 pad have produced 201,600 bbl of condensate over the first 180 days averaging 896 boe per day (25 per cent condensate). Better than expected performance from these wells has enabled Crew to achieve forecasted Q3 2019 production volumes while shutting in dry gas production in the quarter due to low pricing.
  • Support for long-term sustainability: With base production decline rates below 15 per cent at Septimus and area operating netbacks that exceed maintenance capital, Crew is well positioned to support the company's sustainability by replicating this trend at West Septimus, where decline rates are estimated at approximately 18 per cent.
  • Financial liquidity remains strong: Ending Q3 2019 net debt of $356.1-million remains in line with $353.4-million at June 30, 2019, and comprises $300-million of senior notes which have no financial maintenance covenants and are termed out until 2024. The company's syndicate of lenders has completed its fall 2019 review and reconfirmed the bank facility's borrowing base at $235-million, with Crew 26 per cent drawn at Sept. 30.
  • Capital plans outlined through first half 2020: Crew remains committed to balancing the company's capital expenditures with AFF to retain financial flexibility. To capitalize on strong gas prices anticipated this winter, the company plans to invest a total of $54-million in Q4 2019 (55 per cent), Q1 2020 (30 per cent) and Q2 2020 (15 per cent), which compares with $102-million invested in the comparable periods the prior year. Shifting the timing of this capital is expected to enable Crew to secure lower rates for services, significantly improve economics, enhance per-well rates of return, and produce an average of 22,000 to 23,000 boe per day in the first half of 2020 while maintaining liquidity levels.

                                     FINANCIAL AND OPERATING HIGHLIGHTS 
                                  (in thousands, except per-share amounts)  

                                                   Three months ended                   Nine months ended   
Financial                            Sept. 30, 2019    Sept. 30, 2018     Sept.30, 2019    Sept. 30, 2018

Petroleum and natural gas sales             $41,597           $54,080          $148,591          $167,547
Adjusted funds flow                          16,664            20,107            64,948            68,284
Per share
Basic                                          0.11              0.13              0.43              0.45
Diluted                                        0.11              0.13              0.43              0.45
Net (loss) income                            (3,255)             (939)           18,306            (5,972)
Per share
Basic (loss)                                  (0.02)            (0.01)             0.12             (0.04)
Diluted (loss)                                (0.02)            (0.01)             0.12             (0.04)
Exploration and
Development expenditures                     18,466            23,656            87,704            70,045
Property acquisitions (loss)
(net of dispositions)                             7                 9           (19,166)           (9,981)
Net capital expenditures                     18,473            23,665            68,538            60,064

                                            Three months ended                    Nine months ended
Operations                     Sept. 30, 2019   Sept. 30, 2018    Sept. 30, 2019     Sept. 30, 2018
Daily production
Light crude oil (bbl/d)                   233              269               205                282
Heavy crude oil (bbl/d)                 1,627            1,819             1,653              1,832
Condensate (bbl/d)                      2,575            2,077             2,773              2,358
Ngl (bbl/d)                             2,148            1,711             2,071              1,738
Natural gas (mcf/d)                    97,443          106,821            97,608            109,099
Total (boe/d at 6:1)                   22,824           23,680            22,970             24,393
Average prices   
Light crude oil ($/bbl)                 63.81            78.25             63.39              73.75
Heavy crude oil ($/bbl)                 52.86            51.03             52.58              47.96
Ngl ($/bbl)                              0.57            28.15              6.16              26.19
Condensate ($/bbl)                      62.19            81.45             64.73              78.99
Natural gas ($/mcf)                      1.95             2.40              2.58               2.51
Oil equivalent ($/boe)                  19.81            24.82             23.70              25.16

                                                              Three months ended                   Nine months ended
                                                Sept. 30, 2019    Sept. 30, 2018     Sept. 30, 2019   Sept. 30, 2018
Netback ($/boe)
Petroleum and natural gas sales                         $19.81            $24.82             $23.70           $25.16
Royalties (loss)                                         (1.49)            (1.73)             (1.70)           (1.76)
Realized commodity hedging gain (loss)                    1.38             (2.09)              0.12            (1.40)
Marketing income                                          1.33              0.25               1.32             0.27
Net operating (costs)                                    (5.94)            (6.21)             (6.06)           (6.35)
Transportation (costs)                                   (2.80)            (1.62)             (2.69)           (1.85)
Operating netback                                        12.29             13.42              14.69            14.07
General and administrative (loss)                        (1.36)            (1.39)             (1.42)           (1.34)
Other income                                                 -                 -                  -             0.15
Financing (costs) on long-term debt                      (2.99)            (2.81)             (2.90)           (2.64)
Adjusted funds flow                                       7.94              9.22              10.37            10.24
Drilling activity
Gross wells                                                  0                 6                  8                6
Working interest wells                                     0.0               6.0                8.0              6.0
Success rate, net wells (%)                                N/A              100%               100%             100%

Financial overview

Shifting production gains to condensate:

  • Production of 22,824 boe per day for the quarter was in line with the previous quarter and 4 per cent lower than the same period in 2018 on exploration and development capital spending of $18.5-million. Third quarter forecasted production was not impacted by the shut in of dry gas caused by lower prices due to the production outperformance of the company's UCR pads that were completed earlier in the year.
  • Condensate production averaged 2,575 bbl per day, an increase of 24 per cent compared with Q3 2018, and represented 11 per cent of Crew's total volumes for the period. Condensate contributed 35 per cent to Crew's total sales in Q3 2019, compared with 29 per cent in Q3 2018 and 38 per cent in Q2 2019. Liquids production averaged 29 per cent of corporate volumes, although petroleum and natural gas sales were negatively impacted due to weakened liquids pricing.
  • Greater Septimus production averaged 19,648 boe per day in Q3 2019, an increase of 2 per cent over 19,240 boe per day in Q3 2018 and on par with Q2 2019 volumes. Year-to-date area production averaged 19,593 boe per day, on par with the same period in 2018, and reflective of the company's focus on prudent development of the higher-value UCR area.

Commodity prices having an impact

  • AFF in Q3 2019 was $16.7-million (11 cents per diluted share) and for the first nine months of the year totalled $65.0-million (43 cents per diluted share). Weaker petroleum and natural gas sales through both periods, partially offset by improved hedging gains, marketing income and lower net operating costs, has contributed to modest declines in both absolute and per-share AFF in 2019.
  • Quarter-over-quarter AFF was 26 per cent lower, primarily attributable to weaker petroleum and natural gas sales. This was partially offset by an increase in hedging gains, lower royalties, transportation and net operating costs.
  • Petroleum and natural gas sales for Q3 2019 and for the first nine months of the year decreased 23 per cent and 11 per cent, respectively, relative to the same periods in 2018, mainly due to lower realized commodity prices in 2019 relative to the same periods in 2018. Third quarter 2019 petroleum and natural gas sales decreased 19 per cent compared with Q2 2019, primarily the result of a 20-per-cent decline in realized commodity prices.
  • The price for West Texas Intermediate (WTI) denominated in Canadian dollars, Crew's benchmark price for light oil and condensate, decreased 7 per cent sequentially from Q2 2019 and 18 per cent over Q3 2018, mainly the result of a global oversupply of crude oil due to increased U.S. shale oil production.
  • Crew's realized combined light crude oil and condensate price decreased 8 per cent and 23 per cent in the quarter, compared with the prior quarter and Q3 2018, respectively, consistent with the decline in WTI benchmark pricing over the same periods.
  • Crew's heavy oil benchmark Western Canada Select (WCS) decreased 11 per cent in Q3 2019 compared with Q2 2019 and declined 5 per cent as compared with Q3 2018 mainly the result of declining global crude prices. The year-over-year heavy oil price decline was moderated, as compared with WTI declines, by the Alberta government's oil curtailment program, which has strengthened Canadian crude oil prices in 2019 compared with 2018.
  • Crew's Q3 2019 heavy crude oil realized price decreased 12 per cent compared with Q2 2019 and increased 4 per cent compared with Q3 2018. The quarter-over-quarter decrease is consistent with the WCS benchmark change. Crew's year-over-year change, as compared with WCS, was enhanced by lower diluent blending costs realized in 2019.
  • The realized price for Crew's NGL (natural gas liquids) production was 92 per cent lower than the previous quarter, and decreased 98 per cent compared with Q3 2018, primarily due to a decrease in realized propane and butane pricing in North America. Crew's NGL pricing includes embedded cost to process the NGL product out of the company's gas stream. During the third quarter, revenue earned from the sale of the extracted NGL product was only slightly above the cost of the extraction due to the low realized prices.
  • Crew's realized natural gas price for Q3 2019 was 17 per cent lower than the previous quarter and 19 per cent lower than Q3 2018, which is consistent with the decline in all of the company's benchmark natural gas prices over the last year. Natural gas prices across North America have continued to decline as a result of persistent production growth in the United States.
  • Marketing income for the quarter was $2.8-million or $1.33 per boe compared with $2.6-million or $1.23 per boe in Q2 2019, and $600,000 or 25 cents per boe in Q3 2018, reflecting the monetization of the company's Dawn transport contract and Malin sales contract.

Net operating costs continue trending lower:

  • Corporate operating netbacks in Q3 2019 averaged $12.29 per boe, a decline of 18 per cent sequentially from Q2 2019, reflective of a 20-per-cent decline in realized commodity prices per boe, partially offset by a larger hedging gain and lower operating costs per boe. Compared with Q3 2018, operating netbacks declined 8 per cent.
  • Cash costs per boe for Q3 decreased 3 per cent relative to Q2 2019, attributable mainly to lower royalties and transportation costs per boe. Cash costs per boe in Q3 2019 increased 6 per cent relative to Q3 2018 predominantly due to higher transportation costs associated with transportation access to new natural gas markets, partially offset by lower royalties and operating costs per boe.
  • With a focus on optimizing field operations to increase the efficiency of the company's operations, Crew's per boe net operating costs decreased 4 per cent in Q3 2019 compared with Q3 2018 and by 5 per cent for the nine months ended Sept. 30, 2019, relative to the same period in 2018.
  • As part of the continuing expansion to diversify market opportunities for the company's natural gas production, transportation costs in Q3 2019 and the first nine months of 2019 increased relative to the corresponding periods in 2018, but declined 6 per cent relative to Q2 2019. The year-over-year increase is due to the addition of fees associated with the new sales pipeline between West Septimus and TC Energy's Saturn meter station.

Third quarter capital expenditures in line with guidance:

  • Exploration and development capital expenditures remained in line with guidance at $18.5-million in Q3 2019 and $68.5-million (net of $19.2-million of net acquisition and disposition proceeds) year to date in 2019. The majority of Crew's net capital investments in Q3 and year to date 2019 were directed to development within the company's UCR area.
  • Approximately $12.4-million of Crew's Q3 capital was allocated to drilling and completion activities largely focused in the company's UCR area, including a partial completion at Crew's 3-32 pad, completion of the 14-34 well, incremental water handling infrastructure and pipeline installation. Of the company's total capital, $3.4-million was directed to Montney well site development, facilities and pipelines with $2.7-million for land, seismic and other miscellaneous expenditures.

Continuing commitment to balance sheet strength:

  • Net debt of $356.1-million was stable relative to the $353.4-million of net debt at the end of Q2 2019.
  • Crew's debt comprises $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 26 per cent drawn when combined with the working capital deficiency of approximately $3.6-million at quarter-end.
  • The company's syndicate of lenders has completed its fall 2019 review and reconfirmed the bank facility's borrowing base at $235-million.

Transportation, marketing and hedging

Active marketing program underpins strategy:

  • Crew elected to monetize the company's Dawn market access for the remainder of 2019 and all of 2020 and its Malin market exposure for the remainder of 2019, realizing marketing income in Q3 2019 of $2.8-million and a total of $8.3-million for the nine months ended Sept. 30, 2019.
  • For the fourth quarter of 2019, Crew's average natural gas sales exposure is currently forecast to be weighted approximately 53 per cent to Chicago, 17 per cent to NYMEX (New York Mercantile Exchange), 16 per cent to Alliance ATP, 7 per cent to Station 2 and 7 per cent to AECO 5A.

Natural gas and liquids hedging

  • Crew's natural gas hedges currently include:
    • 25,000 million British thermal units per day of Chicago gas at $3.53 per one million British thermal units for 2019;
    • 7,500 million British thermal units per day of Dawn gas at $3.55 per one million British thermal units for 2019;
    • 10,000 million British thermal units per day of NYMEX gas at $2.95 (U.S.) per one million British thermal units for 2019;
    • 12,500 million British thermal units per day of Chicago gas at $3.32 per one million British thermal units for 2020;
    • 2,500 million British thermal units per day of NYMEX gas at $2.48 (U.S.) per one million British thermal units for 2020;
  • For liquids, Crew has the following hedges in place:
    • 1,937 bbl per day of WTI at an average price of $76.17 per bbl for 2019;
    • 250 bbl per day of WCS for Q4 2019 at $56.20 per bbl;
    • 250 bbl per day of WCS for Q4 2019 at $55.75 per bbl;
    • 500 bbl per day of WCS differential at $25.23 per bbl for the second half of 2019;
    • 1,127 bbl per day of WTI at an average price of $77.41 per bbl for 2020;
    • 250 bbl per day of WCS differential at $17.25 (U.S.) per bbl for first half 2020;
    • 250 bbl per day of WCS for first half 2020 at $52.00 per bbl.

Operations and area overview

Northeastern B.C. Montney -- Greater Septimus

  • During Q3 2019, Crew completed the toe of one extended reach horizontal (ERH) well with a total lateral length of 3,050 metres drilled to the northwest on the 3-32 pad in the UCR area at West Septimus. This was a partial completion of approximately 25 per cent of the well to confirm flow and liquids characteristics, which proved to be similar to other UCR wells in the area.
  • Results to date from wells on the company's 15-20 pad in the UCR area at Greater Septimus have remained strong and are averaging above the 4.6 billion cubic feet of gas and 296,500 bbl of condensate assigned to proven plus probable UCR ERH-type wells by Crew's independent reserves evaluator at year-end 2018. The four B zone wells produced average sales of 839 boe per day, comprising 40 per cent condensate and 12 per cent NGL, over the first 210 days on production.
  • At Crew's 4-21 pad in the UCR transition zone, results have also exceeded management's initial expectations. The wells have produced average sales of 896 boe per day over the first 180 days on production, including 25 per cent condensate and 13 per cent NGL, despite being restricted for the first two months on production.
  • As a result of the outperformance of these condensate-rich wells at Greater Septimus, Crew has been able to optimize its commodity mix. During Q3 we were able to meet forecast production guidance while shutting in dry gas due to low prices.

                                     GREATER SEPTIMUS    
                                                     
Production and drilling                 Q3 2019    Q2 2019    Q1 2019     Q4 2018    Q3 2018

Average daily production (boe/d)         19,648     19,594     19,535      18,447     19,240
Wells drilled (gross/net)                     -      1/1.0      6/6.0       6/6.0      4/4.0
Wells completed (gross/net)               1/1.0          -      8/8.0       3/3.0          -

Operating netback  ($ per boe)          Q3 2019    Q2 2019    Q1 2019     Q4 2018    Q3 2018

Revenue                                  $17.38     $22.20     $25.61      $26.53     $22.83
Royalties (loss)                          (1.04)     (1.27)     (1.56)      (1.58)     (1.15)
Realized commodity hedge gain (loss)       1.78       0.28      (0.74)      (1.79)     (2.01)
Marketing income                           1.55       1.43       1.66        1.23       0.34
Net operating (costs)                     (4.41)     (4.46)     (4.65)      (4.51)     (4.61)
Transportation (costs)                    (2.62)     (2.81)     (1.73)      (1.35)     (1.22)
Operating netback                         12.64      15.37      18.59       18.53      14.18

Other northeast B.C. Montney:

  • Tower: After being shut in for offsetting completion operations for most of Q2 2019, volumes at Tower in Q3 2019 returned to similar productivity levels realized prior to the shut-in. Crew continues to evaluate the relative economics of Tower development as well as reviewing encouraging nearby Lower Montney well results.
  • Monias: Activity at Monias during Q3 was directed to the completion of one horizontal Montney delineation well that is currently being tested and evaluated.
  • Attachie: Of Crew's 90 net sections of land in this area, approximately 44 net 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 of 2019 and another is planned in 2020, which is expected to conclude the lease preservation program in this area.
  • Oak/Flatrock: In this liquids-rich gas area, Crew has more than 60 (52 net) sections of land, and the company plans to continue monitoring industry activity and offsetting well results which have been encouraging.

Alberta/Saskatchewan heavy oil -- Lloydminster:

  • During Q3, activity at Lloydminster included the recompletion of eight (8.0 net) heavy crude oil wells which contributed to average production of 1,627 bbl per day of heavy crude oil, 5 per cent lower than the prior quarter and 10 per cent lower relative to Q3 2018, reflecting limited capital investment in the area.
  • Relative to Q3 2018, Crew's realized heavy crude oil price increased 4 per cent due to the lower cost of diluent needed to blend with the heavy crude oil, while the WCS benchmark price decreased 5 per cent in the period. This price improvement contributed to Q3 operating netbacks at Lloydminster, which averaged $17.56 per boe. To maximize profitability, Crew will continue to evaluate forward pricing for WCS for the purposes of optimizing execution timing of a one-to-three-well multilateral horizontal drilling program.

Outlook

Value creation and value preservation intact:

  • Crew's strategy of maximizing value over volume growth has led to the successful realization of increased margins through replacement of natural gas volumes with condensate production growth.
  • The company's emphasis on UCR drilling along with the company's goal of improving margins is proving successful. Condensate volumes in Q3 increased 24 per cent year over year while Crew's average condensate price of $62.19 per bbl was materially higher than the average corporate realized price per boe of $19.81. NGL prices continued to be very weak, averaging only 57 cents per bbl in Q3 2019 versus $28.15 per bbl in Q3 2018.

Sustainability continues to improve:

  • At Septimus, Crew is successfully generating an operating netback that exceeds maintenance capital requirements for the area. As a result of Crew's investment in the area, production declines for Septimus are under 15 per cent, representing similar performance attributes to a tight conventional reservoir. The company has estimated the base decline rate in the West Septimus area to now be approximately 18 per cent, further improving the sustainability of the company's entire Montney production base.
  • Crew plans to replicate the development success and free cash flow generation realized first at Septimus and now at West Septimus within the company's UCR area, which has over 135 potential drilling opportunities, representing over 10 years of highly economic future growth at Crew's current pace of development.

Capital expenditures to approximate AFF through first half 2020:

  • Responding to advantageous Q4 2019 operational and cost-efficiencies, as well as favourable winter commodity prices, Crew's board of directors has approved a reallocated capital expenditure budget of $54-million for the next three quarters, including Q4 2019, Q1 2020 and Q2 2020. Crew anticipates investing approximately $28-million to $32-million in Q4 2019, $14-million to $18-million in Q1 2020 and $6-million to $10-million in Q2 2020 to generate average production of 22,000 and 23,000 boe per day through this period. For comparative purposes, over the same nine-month period in Q4 2018 and the first half of 2019, Crew invested $102-million. The company continues to prioritize financial flexibility and as a result, if this level of capital spending does not approximate AFF, Crew would further refine its capital spending plans to align with its goal of maintaining current debt levels. The company plans on releasing its full-year 2020 capital investment budget and production guidance in Q1 2020.
  • Four drilled but uncompleted wells on the company's 3-32 pad were originally planned for completion in Q1 2020 and are now planned to be completed in Q4 2019, consistent with the company's revised capital allocation timing. Crew has been able to secure the required services to complete this operation at compelling rates, allowing the company to achieve more with lower capital while producing at higher rates into a period with forward curve commodity prices that are expected to be over 40 per cent higher on average than the forward curve for Q2 and Q3 2020. The company's analysis indicates that completing these wells in Q4 2019 rather than Q1 2020 can enhance individual well rates of return and meaningfully impact 2020 AFF.
  • Crew's net 2019 capital expenditure budget is expected to range between $95-million and $100-million (exploration and development spending of between $114-million and $119-million). Average volumes are forecast to be between 22,500 to 23,000 boe per day, with a steady focus on increasing the weighting of higher valued condensate and oil within Crew's production portfolio.
  • For Q4 2019, production is expected to average between 22,000 and 22,500 boe per day on capital expenditures of between $28-million and $32-million. Quarterly volume forecasts incorporate the company's planned deferral of dry gas production that is exposed to weak Station 2 gas prices and the shut-in of production for offsetting completion operations. Activity during Q4 2019 will focus on the completion and equipping of four UCR ERH Montney wells and water-handling initiatives.

Diversified market access and positioned for low-cost growth:

  • With access to differentiated sales points in North America, three major export pipelines and close proximity to the Coastal Gas Link pipeline, Crew's land base is ideally located to move gas to advantageously priced markets in addition to having the potential to significantly reduce transportation costs as a supply source for LNG.
  • Crew's continuous investment in infrastructure has positioned the company with capacity to produce over 40,000 boe per day, providing future growth opportunities at reduced costs.

Innovation leads to improved safety and reduced emissions:

  • Crew's relentless pursuit to continuously improve has led to a 52-per-cent reduction in gas plant flaring intensity from 2015 to 2018. The company has also transitioned to testing new wells directly into pipelines which has led to a reduction in flaring of over 85 per cent from 2017, equivalent to removing 120 passenger vehicles from the road annually.
  • Over 95 per cent recycled water was used during the company's completion operations in 2018, significantly reducing the amount of fresh water used.
  • By building pipelines to pad sites prior to drilling, Crew is able to fuel the company's drilling operations with natural gas rather than diesel, thereby reducing carbon dioxide emissions by 20 per cent and saving approximately $80,000 per well. By using the same pipeline, the company can deliver water for fracturing operations to the pad site. In its last 11 well completions, this practice resulted in 1,286 truckloads being removed from the road and saving the company $275,000, while also significantly reducing the risk of vehicular accidents.

The company thanks its employees and directors for their commitment and dedication to the success of Crew, particularly in light of insiders now constituting 10 of the top 20 shareholders of the company. The company would also like to thank all of its shareholders and bondholders for their patience and support in this challenging environment.

We seek Safe Harbor.

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