Husky Energy Reports Third Quarter 2019 Results

Source Press Release
Company Husky Energy Inc. 
Tags Capital Spending, Strategy - Corporate, Financial & Operating Data
Date October 24, 2019

Husky Energy continued to execute its 2019 business plan in the third quarter, with the delivery of all planned milestones in the Integrated Corridor and Offshore businesses.

Funds from operations were $1 billion, compared to $1.3 billion in the third quarter of 2018. Net earnings were $273 million. Cash flow from operating activities, including changes in non-cash working capital, was $800 million, compared to $1.3 billion in the third quarter of 2018. The reductions in funds from operations and net earnings include impacts from lower crude oil prices and lower U.S. refining margins.

“We achieved all of the milestones for the third quarter as set out at Investor Day in May, and remain on track for the rest of the year,” said CEO Rob Peabody. “We also saw our work to enhance process safety translate to improved reliability across the business.”

“In the Integrated Corridor, we started up our latest 10,000 barrel-per-day Saskatchewan thermal bitumen project at Dee Valley, which has already reached its nameplate capacity. We began the final tie-in of the Lima Refinery crude oil flexibility project, received permits to commence the Superior Refinery rebuild, and reached an agreement to sell the Prince George Refinery.”

In the Offshore business, the SeaRose floating production, storage and offloading (FPSO) vessel is back up to full rates, the Liuhua 29-1 project in China is 65% complete, and the West White Rose Project is now 52% complete.

In line with the reduced capital program set out at Investor Day in May 2019, earlier this week Husky took steps to further align its organization and workforce.

THIRD QUARTER HIGHLIGHTS

  • Funds from operations of $1 billion, compared to $1.3 billion in the year-ago period
  • Cash flow from operating activities of $800 million, compared to $1.3 billion in the third quarter of 2018
  • Net earnings of $273 million, compared to net earnings of $545 million in Q3 2018
  • Capital spending of $868 million was directed towards advancing the Saskatchewan thermal portfolio, the Lima crude oil flexibility project, and progressing construction of the Liuhua 29-1 field offshore China and the West White Rose Project in the Atlantic region. Capital expenditure guidance for 2019 remains unchanged at $3.3-$3.5 billion
  • Free cash flow, before dividends, of $153 million
  • Successful startup of the 10,000 barrel-per-day Dee Valley thermal bitumen project, which came in ahead of schedule and under budget
  • Overall Upstream production averaged 294,800 barrels of oil equivalent per day (boe/day), which takes into account the return to full production at the White Rose field in the Atlantic region, mandated production quotas in Alberta and maintenance at the Liwan Gas Project and the BD Project in the Asia Pacific region; production was approximately 310,000 boe/day at the end of the third quarter
  • Downstream throughput of 356,400 barrels per day (bbls/day), compared to 350,600 bbls/day in the third quarter of 2018
  • Construction commenced on the Superior Refinery rebuild project; full operations expected to resume in 2021
  • Reached an agreement to sell the Prince George Refinery for $215 million in cash plus a closing adjustment for working capital, and a contingent payment of up to $60 million over two years; sale is expected to close in the fourth quarter of 2019 subject to closing conditions
  Three Months Ended    Nine Months Ended   


 
Sept. 30
2019 
June 30
2019 
Sept. 30
2018 
  Sept. 30
2019 
Sept. 30
2018 
 
Upstream production, before royalties               
  Total equivalent production (mboe/day)  295  268   297    283  298   
  Crude oil and natural gas liquids (mbbls/day)    211  189   210    200  215   
  Natural gas (mmcf/day)  503  475   520    498  497   
Upgrader and refinery throughput (mbbls/day)  356  340   351    343  368   
Revenue, net of royalties ($mm)  5,313  5,303   6,194    15,190  17,260   
Operating margin1 ($mm)  976  942   1,414    3,090  3,910   
  Integrated Corridor  710  703   1,028    2,356  2,774   
  Offshore  266  239   386    734  1,136   
Funds from operations1 ($mm)
  Per common share – Basic ($/share)   
1,021
1.02 
802
0.80 
1,318
1.31 
  2,782
2.77 
3,421
3.40 
 
Cash flow – operating activities ($mm)  800  760   1,283    2,105  2,821   
Capital expenditures ($mm)  868  858   968    2,538  2,313   
Free cash flow1 ($mm)  153  (56)  350    244  1,108   
Net earnings ($mm)
  Per common share – Basic ($/share) 
273
0.26 
370
0.36 
 545
0.53 
  971
0.94 
1,241
1.21 
 
Net debt1 ($ billions)  3.9  3.7   2.6    3.9  2.6   
Net debt to trailing funds from operations1(times)  1.1  1.0  0.6    1.1  0.6   
1Non-GAAP measure; refer to advisory.  

THIRD QUARTER RESULTS

Upstream production averaged 294,800 boe/day, compared to 296,700 boe/day in the third quarter of 2018, which takes into account the start up of the 10,000 bbls/day Dee Valley thermal bitumen project in Saskatchewan and return to full production at the White Rose field in the Atlantic region, partially offset by ongoing mandated production quotas in Alberta and maintenance at Liwan and the BD Project.

Average realized pricing for Upstream production was $47.54 per boe compared to $50.44 per boe in the same period in 2018. Realized pricing for oil and liquids averaged $53.46 per barrel compared to $56.02 per barrel in the year-ago period, and natural gas pricing averaged $5.44 per thousand cubic feet (mcf), compared to $6.15 per mcf in Q3 2018. Upstream operating costs were $14.83 per boe compared to $14.68 per boe in the third quarter of 2018, reflecting lower production in the Atlantic region and maintenance at Liwan and the BD Project.

Upstream operating netbacks averaged $29.31 per boe compared to $31.30 per boe in the year-ago period.

Upgrader and refinery throughput was 356,400 bbls/day, compared to 350,600 bbls/day in the same period in 2018. This reflects strong performance at the Lima Refinery, which averaged 174,300 bbls/day in the third quarter.

The average realized U.S. refining and marketing margin was $12.17 US per barrel of crude oil throughput, which reflects an unfavourable first-in, first-out (FIFO) pre-tax inventory valuation adjustment of $0.13 US per barrel. This compared to $17.52 US per barrel a year ago, which included an unfavourable FIFO pre-tax inventory valuation adjustment of $0.35 US per barrel.

The Upgrader realized margin was $15.01 per barrel compared to $29.19 per barrel in the same period in 2018, which takes into account lower upgrading differentials.

Net earnings in the Infrastructure and Marketing segment were $34 million compared to $149 million in Q3 2018, due to tighter location pricing differentials.

Husky has already achieved most of its planned 2019 operational milestones and is making strong progress on its 2020 targets.

NEAR & MID-TERM MILESTONES

2019  Capacity
(Husky W.I.) 
Timing/
Completion 
Status 
       
Turnarounds       
  Upstream    Q2 ’19  Completed 
  Downstream    Q2 ’19  Completed 
       
White Rose infill production wells online  +6-8,000 bbls/day  Q2 ’19  Completed 
White Rose drill centres on full production    Q3 ’19  Completed 
Dee Valley thermal project  10,000 bbls/day  Q3 ’19  Completed 
Liuhua 29-1 initial pipeline laying    Q3 ’19  Completed 
Lima Refinery crude oil flexibility project  40,000 bbls/day  YE ’19  95% complete 
Prince George Refinery sale    Q4 ’19  Announced 
Strategic review of fuels/retail business    ’19  In progress 
       
2020+  Capacity
(Husky W.I.) 
Timing/
Completion 
Status 
       
Lloyd Upgrader diesel capacity increase   6,000 –> 9,800 bbls/day  ’20  45% complete 
Spruce Lake Central thermal project  10,000 bbls/day  2H ’20  85% complete 
Spruce Lake North thermal project  10,000 bbls/day  ~YE ’20  55% complete 
Liuhua 29-1 project  45 mmcf/day gas
1,800 bbls/day liquids 
YE ’20  65% complete 
Superior Refinery rebuild  50,000 bbls/day  ’21  In progress 
Spruce Lake East thermal project  10,000 bbls/day  ~YE ’21  In progress 
MDA-MBH & MDK fields  10,000 boe/day  ’21  In progress 
Edam Central thermal project  10,000 bbls/day  ’22  In progress 
West White Rose Project start up  52,500 bbls/day  ~YE ’22  52% complete 
Dee Valley 2 thermal project  10,000 bbls/day  ’23  In planning 

INTEGRATED CORRIDOR

  • Upstream production averaged 232,100 boe/day compared to 223,300 boe/day in Q3 2018
  • Operating margin of $710 million, compared to $703 million in Q2 2019 and $1.03 billion in Q3 2018
  • First oil achieved at the Dee Valley thermal bitumen project in Saskatchewan, which has reached its 10,000 bbls/day nameplate capacity
  • Downstream throughput of 356,400 bbls/day compared to 350,600 bbls/day in the third quarter of 2018

Thermal Production                                                                    

Thermal bitumen production from Saskatchewan thermal projects, the Tucker Thermal Project and the Sunrise Energy Project averaged 126,400 bbls/day (Husky W.I.), compared to 117,300 bbls/day (Husky W.I.) in Q3 2018.

Overall production from the Saskatchewan thermal portfolio was 76,900 bbls/day compared to 74,300 bbls/day in Q3 2018. This included the startup of the new 10,000 bbls/day Dee Valley thermal project, which began production ahead of schedule in August and achieved its nameplate capacity in September.

Five new Saskatchewan thermal bitumen projects with a combined nameplate capacity of 50,000 bbls/day are being advanced through 2023, including the Spruce Lake Central development, scheduled for startup in the second half of 2020, and the Spruce Lake North project, which is planned to start up around the end of 2020.

Resource Plays

The Company continues to pace investments in its liquids-rich resource play business with an ongoing focus on lowering costs, optimizing production rates and reducing cycle times while supporting the natural gas requirements of its thermal operations in Western Canada.

In the oil and liquids-rich Montney formation, one well was drilled in the Karr area, completing the planned 2019 Montney drilling program. Ten Montney wells at Wembley and Karr are expected to be brought on production in the fourth quarter.

Downstream

The Downstream operating margin was $244 million, compared to $286 million in Q2 2019 and $471 million in Q3 2018.

U.S. refinery throughput averaged 241,100 bbls/day, including average throughput of 174,300 bbls/day at the Lima Refinery. The Lima Refinery crude oil flexibility project to increase heavy oil processing capacity to 40,000 bbls/day is in its final stages and scheduled to conclude by the end of 2019.

The operating margin for the U.S. refining segment was $121 million.

The Superior Refinery rebuild has commenced, with a return to full operations expected in 2021. Rebuild costs are expected to be substantially covered by property damage insurance.

Pre-tax business interruption insurance proceeds of $132 million for the Superior Refinery was accounted for in $410 million of Downstream EBITDA.

Canadian throughput, including the Lloydminster Upgrader and asphalt refinery, averaged 115,300 bbls/day. A project is under way at the Upgrader to increase diesel production from 6,000 bbls/day to nearly 10,000 bbls/day in 2020.

The operating margin for the combined Upgrading and Canadian Refined Products segments was $123 million.

Husky continued to increase its focus on core assets in the Integrated Corridor business with the agreement to sell the Prince George Refinery for $215 million in cash plus a closing adjustment for working capital and a contingent payment of up to $60 million over two years. The sale is expected to close in the fourth quarter of 2019 subject to closing conditions and regulatory approvals. Proceeds will be used in accordance with Husky’s funding priorities, which include maintaining the strength of the balance sheet and returning value to shareholders.

A strategic review of the potential sale of the Canadian retail and commercial fuels business continues to progress.

OFFSHORE                                               

  • Overall average net production of 62,700 boe/day, compared to 73,400 boe/day in the third quarter of 2018
  • Operating netback of $55.53 per boe
    • Asia Pacific operating netback of $62.59 per boe
    • Atlantic operating netback of $41.64 per barrel
  • White Rose field returned to full operations           

Asia Pacific

China
Natural gas sales from the two producing fields at the Liwan Gas Project averaged 323 million cubic feet per day (mmcf/day), with associated liquids averaging 14,300 bbls/day (158 mmcf/day and 6,600 bbls/day Husky W.I.). Realized gas pricing at Liwan was $13.28 per mcf, with liquids pricing of $61.81 per barrel. Operating costs were $6.10 per boe, with an operating netback of $65.67 per boe.

At the Liuhua 29-1 field at Liwan, all seven wells have been drilled, with final completions under way. The wells will be tied in to the existing subsea infrastructure, with first gas expected by the end of 2020. Target production is 45 mmcf/day of gas and 1,800 bbls/day of liquids when fully ramped up, reflecting Husky’s 75% working interest.

Indonesia
Natural gas sales at the BD Project in the Madura Strait averaged 86 mmcf/day, with liquids production of 7,000 bbls/day (35 mmcf/day and 2,800 bbls/day, Husky W.I.). Volumes were impacted by maintenance to the leased FPSO vessel. Realized gas pricing at BD was $9.82 per mcf, with liquids pricing of $83.03 per barrel. Operating costs were $6.22 per boe, with an operating netback of $51.98 per boe.

Atlantic

Overall average production in the Atlantic region was approximately 21,000 bbls/day (Husky W.I.), reflecting the return to operations in August of the final two drill centres in the White Rose field.

West White Rose Project                                                  
Construction work on the concrete gravity structure and related topsides is progressing. The third quadrant of the concrete gravity structure (CGS) and two interior decks were completed, and the fourth and final CGS quadrant was completed in October. The project is now 52% complete as it advances towards first oil around the end of 2022.

CORPORATE DEVELOPMENTS

The Board of Directors has approved a quarterly dividend of $0.125 per common share for the three-month period ended September 30, 2019. The dividend will be payable on January 2, 2020 to shareholders of record at the close of business on December 2, 2019.

Regular dividend payments on each of the Cumulative Redeemable Preferred Shares – Series 1, Series 2, Series 3, Series 5 and Series 7 – will be paid for the three-month period ended December 31, 2019. The dividends will be payable on December 31, 2019 to holders of record at the close of business on December 2, 2019.

  Share Series    Dividend Type    Rate (%)    Dividend Paid ($/share) 
Series 1  Regular  2.404  $0.15025 
Series 2  Regular  3.368  $0.21223 
Series 3  Regular  4.50  $0.28125 
Series 5  Regular  4.50  $0.28125 
Series 7  Regular  4.60  $0.28750 


CONFERENCE CALL

A conference call will be held on Thursday, Oct. 24 at 9 a.m. Mountain Time (11 a.m. Eastern Time) to discuss Husky’s 2019 third quarter results. CEO Rob Peabody, COO Rob Symonds and CFO Jeff Hart will participate in the call.

To listen live: 

Canada and U.S. Toll Free: 1-800-319-4610
Outside Canada and U.S.: 1-604-638-5340


 
To listen to a recording (after 10 a.m. MT on Oct. 24): 

Canada and U.S. Toll Free: 1-800-319-6413
Outside Canada and U.S.: 1-604-638-9010
Passcode: 3602 
Duration: Available until November 23, 2019
Audio webcast: Available for 90 days at  

Investor and Media Inquiries:         

Leo Villegas, Senior Manager, Investor Relations
403-513-7817

Kim Guttormson, Media & Issues Specialist
403-298-7088

  Three months ended  Nine months ended 
  Sept. 30  June 30  Sept. 30  Sept. 30  Sept. 30 
($ millions)  2019  2019  2018  2019  2018 
Net earnings   273  370  545   971   1,241 
Items not affecting cash:           
Accretion   26  26   23   79   72 
Depletion, depreciation, amortization and impairment   703  643   672   1,976   1,929 
Exploration and evaluation expenses   -    23   -     23   7 
Deferred income taxes   22  (250)   156   (185)   371 
Foreign exchange gain   (1)  (2)   (6)   (15)   (7) 
Stock-based compensation   (9)  13   40   11   94 
Gain on sale of assets   (3)   -     (5)   (4) 
Unrealized mark to market loss (gain)   4  (4)   (22)   57   (134) 
Share of equity investment gain   (19)  (23)   (18)   (64)   (53) 
Gain on insurance recoveries for damage to property   (13)  -    -     (13)   -   
           
Other   5   (2)   1   19 
Settlement of asset retirement obligations   (73)  (41)   (45)   (186)   (116) 
Deferred revenue   (7)  (5)   (25)   (28)   (70) 
Distribution from equity investment   113  47   -     160   72 
Change in non-cash working capital   (221)  (42)   (35)   (677)   (600) 
Cash flow - operating activities   800  760   1,283   2,105   2,821 
Change in non-cash working capital   221  42   35   677   600 
Funds from operations   1,021  802   1,318   2,782   3,421 
Capital expenditures   (868)  (858)   (968)  (2,538)  (2,313) 
Free cash flow   153  (56)   350   244   1,108 
           
Weighted average number of common shares outstanding  1,005.1  1,005.1  1,005.1  1,005.1  1,005.1 
Funds from operations           
Per common share - Basic ($/share)

 
1.02  0.80  1.31  2.77  3.40 

Operating margin is a non-GAAP measure which should not be considered an alternative to, or more meaningful than, “revenue, net of royalties” as determined in accordance with IFRS, as an indicator of financial performance. Operating margin is presented to assist management and investors in analyzing operating performance of the Company in the stated period.

Operating margin equals revenues net of royalties less purchases of crude oil and products, production, operating and transportation expenses, and selling general and administrative expenses.

The following table shows the reconciliation of operating margin for the periods indicated:

  Three months ended 
  Sept. 30, 2019  June 30, 2019  Sept. 30, 2018 
($ millions)  Integrated
Corridor 
Offshore  Total  Integrated
Corridor 
Offshore  Total  Integrated
Corridor 
Offshore  Total 
Revenue, net of royalties   5,488   362   5,850  5,527  328  5,855   6,241   474   6,715 
Less:                   
Purchases of crude oil and products   4,043   -     4,043  4,074  4,074   4,470   -     4,470 
Production and operating expenses   638   88   726  662  81  743   662   78   740 
Selling, general and administrative expenses   97   8   105  88  96   81   10   91 
Operating margin   710   266   976  703  239  942   1,028   386   1,414 
  Nine months ended 
  Sept. 30, 2019  Sept. 30, 2018 
($ millions)  Integrated
Corridor 
Offshore  Total  Integrated
Corridor 
Offshore  Total 
Revenue, net of royalties  15,711  1,012  16,723  17,252  1,389  18,641 
Less:             
Purchases of crude oil and products  11,106  11,106  12,343  12,343 
Production and operating expenses  1,969  254  2,223  1,878  224  2,102 
Selling, general and administrative expenses  279  25  304  257  29  286 
Operating margin  2,356  734  3,090  2,774  1,136  3,910 

Net debt is a non-GAAP measure that equals the sum of long-term debt, long-term debt due within one year and short-term debt, less cash and cash equivalents. Net debt is considered to be a useful measure in assisting management and investors to evaluate the Company’s financial strength.

The following table shows the reconciliation of net debt as at the dates indicated:

  Sept. 30  June 30  Sept. 30 
($ millions)  2019  2019  2018 
Short-term debt  200  200   200 
Long-term debt due within one year   1,393  1,382   388 
Long-term debt   4,635  4,598   4,964 
Cash and cash equivalents  (2,362)  (2,512)   (2,916) 
Net debt  3,866  3,668   2,636 
Source: EvaluateEnergy® ©2020 EvaluateEnergy Ltd