Husky Energy Reports Third Quarter 2018 Results
Funds From Operations up 48%, Earnings up 300% Year over Year
CALGARY, Alberta, Oct. 25, 2018 (GLOBE NEWSWIRE) -- Husky Energy (TSX:HSE) generated funds from operations of $1.3 billion in the third quarter, up 48 percent from $891 million in the same period last year. Year-to-date, funds from operations are $3.4 billion.
Free cash flow in the quarter was $350 million and $1.1 billion year-to-date.
Net earnings were $545 million, a 300 percent increase compared to $136 million in Q3 2017. Net debt at the end of the quarter was lowered to $2.6 billion.
“Husky’s physical integration allows the Company to benefit fully from strong Brent and WTI prices despite wide location and quality differentials. With committed export pipeline capacity and the flexibility to swing between heavy and light crudes in our refining system, we are maximizing margins across our Integrated Corridor,” said CEO Rob Peabody. “Through Husky’s high level of integration, and offshore production, we continue to attain higher, global pricing and generate strong free cash flow.
“Our offer to acquire the outstanding shares of MEG Energy utilizes Husky’s strong balance sheet and ability to capture higher prices to create a stronger, more competitive Canadian energy company. Husky’s third quarter results demonstrate the value potential for MEG shareholders and our ability to achieve financial targets faster than MEG could as a stand-alone company.”
OFFER TO ACQUIRE MEG ENERGY
On October 2, Husky made an offer to acquire all outstanding shares of MEG Energy. Husky believes the proposal is in the best interests of both Husky and MEG shareholders. For MEG shareholders the benefits include:
- Physical integration with expanded market access, protection from heavy oil differentials and exposure to high netback offshore operations, providing stability in funds from operations.
- An enhanced shareholder return proposition with lower risk, including a strong investment-grade balance sheet that allows for more free cash flow to be directed towards cash returns to shareholders and growth investments, and the opportunity to participate in Husky’s dividend.
- $200 million a year in near-term realizable synergies.
For Husky shareholders, the transaction will be accretive to the Company’s free cash flow, funds from operations, earnings and production on a per share basis. Husky’s offer remains open for acceptance until January 16, 2019.
THIRD QUARTER HIGHLIGHTS
- Net earnings of $545 million
- Funds from operations of $1.3 billion
- Free cash flow of $350 million
- Quarterly cash dividend of $0.125 per common share declared
- Production of 297,000 barrels of oil equivalent per day (boe/day); see detailed guidance sheet at huskyenergy.com
- Net debt at the end of the quarter was $2.6 billion, representing 0.6 times trailing 12 months funds from operations, well below the Company’s target
- Commenced production at the Rush Lake 2 Lloyd thermal project, ahead of schedule
- Advanced construction at the Dee Valley Lloyd thermal project, with first oil now expected in Q4 2019, six months ahead of Investor Day target
- Completed a three-week planned turnaround at the Tucker Thermal Project, and has since ramped up to 30,000 barrels per day (bbls/day) peak daily rate
- Downstream EBITDA of $580 million, with Infrastructure and Marketing EBITDA of $206 million, demonstrating continued margin capture from upgrading, refining and long-term committed export pipeline capacity
- Average realized U.S. refining margins of $17.52 US per barrel reflected Husky’s flexibility to access discounted WTI Midland crude oil barrels, and included a pre-tax FIFO loss of $0.34 US per barrel
- Liwan Gas Project production averaged 371 million cubic feet per day (mmcf/day), with associated liquids averaging 16,500 bbls/day (182 mmcf/day and 8,400 bbls/day Husky working interest), demonstrating continued strong demand despite typhoon season impacts
- Liquids-rich BD Project in the Madura Strait consistently achieving the Company’s gross daily target, averaging 100 mmcf/day (40 mmcf/day Husky working interest) of natural gas with 40 percent higher than expected associated liquids production of 10,400 bbls/day (4,200 bbls/day Husky working interest)
- Completed construction on the base slab at the West White Rose Project and began slipforming the column, with topsides construction about 10 percent complete and living quarters 45 percent finished
|Three Months Ended||Nine Months Ended|
|Sept. 30 |
|Daily production, before royalties|
|Total equivalent production (mboe/day)||297||296||318||298||324|
|Crude oil and NGLs (mbbls/day)||210||213||224||215||234|
|Natural gas (mmcf/day)||520||494||563||497||541|
|Upstream operating netback1,2 ($/boe)||31.30||31.31||23.25||29.00||23.66|
|Refinery and Upgrader throughput (mbbls/day)||351||355||374||368||352|
|Funds from operations1 ($mm)|
Per common share – Basic ($/share)
|Adjusted net earnings1 ($mm)|
Per common share – Basic ($/share)
|Net earnings ($mm)|
Per common share – Basic ($/share)
|Net debt1 ($ billions)||2.6||3.0||3.0||2.6||3.0|
|Dividend per common share ($/share)||0.125||0.125||0.00||0.325||0.00|
|1Non-GAAP measure; refer to advisory.|
2Operating netback includes results from Upstream Exploration and Production and excludes results from Upstream Infrastructure and Marketing.
THIRD QUARTER RESULTS
Husky Energy generated funds from operations of $1.3 billion in the third quarter and free cash flow of $350 million.
Upstream production averaged 297,000 boe/day, which reflects a turnaround at the Tucker Thermal Project, planned maintenance at the Sunrise Energy Project, the decision to slow the pace of CHOPS well optimizations, third-party gas and power constraints and lower than anticipated Atlantic production due to well performance. This compared to 318,000 boe/day in the third quarter of 2017 and 296,000 bbls/day in the second quarter of 2018.
Average realized pricing for Upstream production was $50.44 per boe, compared to $40.05 per boe in the year-ago period. Realized pricing for oil and liquids averaged $56.02 per barrel, and natural gas averaged $6.15 per thousand cubic feet (mcf).
Upstream operating costs averaged $14.68 per boe, compared to $14.12 per boe in Q3 2017. Upstream operating netbacks averaged $31.30 per boe compared to $23.25 per boe in Q3 2017.
Downstream throughput was 350,600 bbls/day compared to 374,000 bbls/day in the third quarter of 2017, which includes the turnaround at Lima starting in mid-September this year.
The Chicago 3:2:1 crack spread averaged $19.04 US per barrel compared to $19.30 US per barrel in Q3 2017. Average realized U.S. refining margins were $17.52 US per barrel, which takes into account a pre-tax FIFO loss of $0.34 US per barrel. This compared to $14.98 US per barrel a year ago, which included a pre-tax FIFO adjustment gain of $1.74 US per barrel.
Upgrading net earnings were $88 million, compared to $9 million in the third quarter of 2017. Upgrading margins were $29.19 per barrel, compared to $12.32 per barrel in the year-ago period.
Net earnings in the Infrastructure and Marketing segment were $149 million, compared to $10 million in Q3 2017. This was primarily due to the wider WTI/WCS differential, which averaged $29.09 per barrel compared to $12.44 in the third quarter of 2017.
Infrastructure and Marketing realized margins were $202 million, compared to $14 million in Q3 2017, reflecting, in part, the value captured from the Company’s long-term 75,000 bbls/day committed export capacity on the Keystone pipeline and 160 mmcf/day in natural gas pipeline capacity to U.S. markets.
Net debt at the end of the quarter was $2.6 billion.
- Upstream average production of 223,000 boe/day
- Upstream operating netback of $19.75 per boe, including an operating netback of $30.63 per barrel from thermal operations
- Downstream throughput of 350,600 bbls/day
- Downstream upgrading/refining margin of $25.27 per barrel
Thermal bitumen production from Lloyd thermal projects, Tucker and Sunrise averaged 117,300 bbls/day (Husky working interest), compared to 117,700 bbls/day (Husky working interest) in the third quarter of 2017. This takes into account the turnaround at Tucker, planned maintenance at Sunrise and third-party gas and power constraints.
Overall thermal operating costs were $12.04 per barrel.
Rush Lake 2 achieved first oil in October and is expected to ramp up to its 10,000 bbls/day design capacity by the first quarter of 2019.
In addition, the Company is currently developing five 10,000 bbls/day Lloyd thermal bitumen projects, with a combined design capacity of 50,000 bbls/day coming online by the end of 2021.
- Construction at Dee Valley has been advanced, with first oil now expected in the fourth quarter of 2019, six months sooner than expected at Investor Day in May.
- At Spruce Lake Central, construction has started on the central processing facility and drilling on the first well pad has been completed. First production is expected in 2020.
- Site clearing is underway at Spruce Lake North, with first oil expected around the end of 2020.
- Two additional 10,000 bbls/day thermal bitumen projects remain on track to be brought online in the second half of 2021.
Tucker averaged production of 18,300 bbls/day, reflecting the three-week turnaround completed in the quarter. Since the turnaround, it has achieved a peak daily rate of 30,000 bbls/day.
At Sunrise, average production in the quarter was 49,400 bbls/day (24,700 bbls/day Husky working interest), reflecting maintenance on the once-through steam generators. This compares to 40,500 bbls/day (20,250 bbls/day Husky working interest) in the year-ago period.
The Company remains focused on capital-efficient operations in Edson, Grand Prairie and Rainbow Lake, its three core Western Canada hubs.
An accelerated drilling program that was increased from an 18 to a 25-well program in the Ansell and Kakwa areas of the Wilrich formation is progressing, with 15 wells drilled and 13 completed. In the oil and liquids-rich Montney formation, four wells have been drilled as part of a 2018 program of up to eight wells, primarily in the Wembley and Karr areas. Three have been completed.
Husky Midstream Limited Partnership is progressing construction on the new Corser gas processing plant in the Ansell area of Central Alberta. It is expected to add 120 mmcf/day of processing capacity when it starts up in the fourth quarter of 2019.
Total Canadian refining throughput, including the Lloydminster Upgrader and the Lloydminster Asphalt Refinery, averaged 116,500 bbls/day, with EBITDA of $243 million.
In the U.S., total refining throughput was 234,100 bbls/day. At the Lima Refinery, throughput averaged 163,300 bbls/day compared to 178,300 bbls/day in the third quarter of 2017, including a scheduled turnaround starting in mid-September. A crude oil flexibility project to increase heavy oil processing capacity from the current 10,000 bbls/day to 40,000 bbls/day by the end of 2019 is on track.
Operations at the Superior Refinery remain suspended, and an investigation into the cause of the April 26th incident is ongoing. The Company is currently focused on winterizing the site. An engineering contractor has been appointed to oversee design work for the rebuild, with the rebuild beginning once the investigation and design work are complete. Normal operations are not expected to resume until 2020. In the quarter Husky accrued $110 million in insurance proceeds for asset damage and repair costs.
- Average production of 73,400 boe/day
- Operating netback of $66.34 per boe
° Asia Pacific operating netback of $65.45 per boe
° Atlantic operating netback of $68.20 per barrel
At the Liwan Gas Project, gross production from the two producing fields averaged 371 mmcf/day in sales gas volumes, with associated liquids averaging 16,500 bbls/day (182 mmcf/day and 8,400 bbls/day Husky working interest). This reflects continued strong demand in China and five days of downtime related to typhoon season.
The Company realized gas pricing of $13.14 Cdn per mcf, with liquids pricing of $76.13 Cdn per barrel.
Construction at Liuhua 29-1, the third deepwater field at Liwan, is underway with detailed design work in progress. Drilling of three additional wells is scheduled to commence in the fourth quarter of 2018, adding to the four wells previously drilled. All three wells will be tied into the existing Liwan infrastructure. First gas is anticipated around the end of 2020, with target net production of 45 mmcf/day gas and 1,800 bbls/day liquids when fully ramped up, reflecting Husky’s 75 percent working interest.
The Company is progressing commercial development plans following the successful drilling of an oil exploration well on Block 15/33 in the South China Sea, approximately 160 kilometres southeast of Hong Kong. Husky is the operator during the exploration phase, with a working interest of 100 percent in the wells. CNOOC may assume operatorship and up to a 51 percent working interest, with exploration cost recovery from production allocated to Husky.
During the quarter, an exploration well was drilled on the nearby Block 16/25. The results will be evaluated further.
At the liquids-rich BD Project, gross gas sales averaged 100 mmcf/day with associated liquids production of 10,400 bbls/day (40 mmcf/day and 4,200 bbls/day Husky working interest). Liquids production was 40 percent higher than expected. BD gas was sold into the East Java market at contracted rates for a realized price of $9.79 Cdn per mcf, with liquids pricing of $95.61 Cdn per barrel.
At the combined MDA-MBH fields in the Madura Strait, seven production wells are scheduled to be drilled in 2019 and come online in 2020.
Construction was completed on the base slab of the West White Rose Project’s concrete gravity structure, and slipforming of the column is underway. Work continues on the topsides and living quarters. First oil is anticipated in 2022, with West White Rose expected to reach peak production of 75,000 bbls/day (52,500 bbls/day Husky working interest) in 2025 as development wells are drilled and brought online.
At the North Amethyst infill well, remediation work to address a high water cut was unsuccessful and future intervention options on this well are being evaluated. Two well workovers were completed at the White Rose field during the quarter and two additional infill wells are scheduled to come online in the fourth quarter of 2018. These are part of a program to offset reservoir declines at the White Rose field and its satellite extensions until the startup of West White Rose in 2022.
Evaluation of the successful White Rose A-24 well is ongoing.
The Board of Directors has approved a quarterly dividend of $0.125 per common share for the three-month period ended September 30, 2018. The dividend will be payable on January 2, 2019 to shareholders of record at the close of business on November 26, 2018.
Regular dividend payments on each of the Cumulative Redeemable Preferred Shares – Series 1, Series 2, Series 3, Series 5 and Series 7 – will be paid for the three-month period ended December 31, 2018. The dividends will be payable on December 31, 2018 to holders of record at the close of business on November 26, 2018.
|Share Series||Dividend Type||Rate (%)||Dividend Paid ($/share)|
A conference call will take place on Thursday, October 25 at 9 a.m. Mountain Time (11 a.m. Eastern Time) to discuss Husky’s third quarter 2018 results. CEO Rob Peabody, COO Rob Symonds and Acting CFO Jeff Hart will participate in the call.
|To listen live:|
Canada and U.S. Toll Free: 1-855-327-6838
Outside Canada and U.S.: 1-604-235-2082
|To listen to a recording (after 10 a.m. MT on October 25):|
Canada and U.S. Toll Free: 1-800-319-6413
Outside Canada and U.S.: 1-604-638-9010
Duration: Available until November 25, 2018
Audio webcast: Available for 90 days at huskyenergy.com
Investor and Media Inquiries:
Dan Cuthbertson, Senior Manager, Investor Relations and External Communications
Mel Duvall, Senior Manager, Media & Issues
NO OFFER OR SOLICITATION
This news release is for informational purposes only and does not constitute an offer to buy or sell, or a solicitation of an offer to sell or buy, any securities. The offer to acquire MEG securities and to issue securities of the Company is made solely by, and subject to the terms and conditions set out in, the formal offer to purchase and takeover bid circular and accompanying letter of transmittal and notice of guaranteed delivery.
NOTICE TO U.S. HOLDERS OF MEG SHARES
The Company has filed a registration statement covering the offer and sale of the Company’s shares in the acquisition with the United States Securities and Exchange Commission (the “SEC”) under the U.S. Securities Act of 1933, as amended. Such registration statement covering such offer and sale includes various documents related to such offer and sale. THE COMPANY URGES INVESTORS AND SHAREHOLDERS OF MEG TO READ SUCH REGISTRATION STATEMENT AND ANY AND ALL OTHER RELEVANT DOCUMENTS FILED OR TO BE FILED WITH THE SEC IN CONNECTION WITH SUCH OFFER AND SALE OF THE COMPANY’S SHARES AS THOSE DOCUMENTS BECOME AVAILABLE, AS WELL AS ANY AMENDMENTS OR SUPPLEMENTS TO THOSE DOCUMENTS, BECAUSE THEY CONTAIN OR WILL CONTAIN IMPORTANT INFORMATION. You are able to obtain a free copy of such registration statement, as well as other relevant filings regarding the Company or such transaction involving the issuance of the Company’s shares, at the SEC’s website (www.sec.gov) under the issuer profile for the Company, or on request without charge from the Senior Vice President, General Counsel & Secretary of the Company, at 707, 8th Avenue S.W. Calgary Alberta or by telephone at 403-298-6111.
The Company is a foreign private issuer and is permitted to prepare the offer to purchase and takeover bid circular and related documents in accordance with Canadian disclosure requirements, which are different from those of the United States. The Company prepares its financial statements in accordance with Canadian generally accepted accounting principles, and they may be subject to Canadian auditing and auditor independence standards. They may not be comparable to financial statements of United States companies.
Shareholders of MEG should be aware that owning the Company’s shares may subject them to tax consequences both in the United States and in Canada. The offer to purchase and takeover bid circular may not describe these tax consequences fully. MEG shareholders should read any tax discussion in the offer to purchase and takeover bid circular, and holders of MEG shares are urged to consult their tax advisors.
A MEG shareholder’s ability to enforce civil liabilities under the United States federal securities laws may be affected adversely because the Company is incorporated in Alberta, Canada, some or all of the Company’s officers and directors and some or all of the experts named in the offering documents reside outside of the United States, and all or a substantial portion of the Company’s assets and of the assets of such persons are located outside the United States. MEG shareholders in the United States may not be able to sue the Company or the Company’s officers or directors in a non-U.S. court for violation of United States federal securities laws. It may be difficult to compel such parties to subject themselves to the jurisdiction of a court in the United States or to enforce a judgment obtained from a court of the United States.
NEITHER THE SECURITIES EXCHANGE COMMISSION NOR ANY STATE SECURITIES REGULATOR HAS OR WILL HAVE APPROVED OR DISAPPROVED THE COMPANY’S SHARES OFFERED IN THE OFFERING DOCUMENTS, OR HAS OR WILL HAVE DETERMINED IF ANY OFFERING DOCUMENTS ARE TRUTHFUL OR COMPLETE. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.
MEG shareholders should be aware that, during the period of the offer, the Company or its affiliates, directly or indirectly, may bid for or make purchases of the securities to be distributed or to be exchanged, or certain related securities, as permitted by applicable laws or regulations of Canada or its provinces or territories.
Certain statements in this news release are forward-looking statements and information (collectively, “forward-looking statements”) within the meaning of the applicable Canadian securities legislation, Section 21E of the United States Securities Exchange Act of 1934, as amended, and Section 27A of the United States Securities Act of 1933, as amended. The forward-looking statements contained in this news release are forward-looking and not historical facts.
Some of the forward-looking statements may be identified by statements that express, or involve discussions as to, expectations, beliefs, plans, objectives, assumptions or future events or performance (often, but not always, through the use of words or phrases such as “will likely result”, “are expected to”, “will continue”, “is anticipated”, “is targeting”, “is estimated”, “intend”, “plan”, “projection”, “could”, “should”, “aim”, “vision”, “goals”, “objective”, “target”, “scheduled” and “outlook”). In particular, forward-looking statements in this news release include, but are not limited to, references to:
- with respect to the business, operations and results of the Company generally, general strategic plans and growth strategies; and the anticipated strategic, financial and operational benefits that may result from a combination of the Company and MEG;
- with respect to the Company’s thermal developments in the Integrated Corridor: expected timing of ramp-up to design capacity at Rush Lake 2; expected timing of first production at Dee Valley, Spruce Lake North and Spruce Lake Central; and expected timing for two additional 10,000 bbls/day projects to be brought online;
- with respect to the Company's resource plays in the Integrated Corridor: drilling plans; and the additional processing capacity expected to result from the start-up of the Corser gas processing plant, and the timing thereof;
- with respect to the Company’s Downstream operations in the Integrated Corridor: the expected timing of completion of the crude oil flexibility project at the Lima Refinery, and the increase in heavy oil capacity expected to result therefrom; and the expected timing of resumption of normal operations at the Superior Refinery;
- with respect to the Company’s Offshore business in Asia Pacific: the expected timing of drilling three additional wells and of first gas production, and target net production once fully ramped up, at Liuhua 29-1; and drilling plans at the combined MDA-MBH fields;
- with respect to the Company’s Offshore business in Atlantic: the expected timing of first oil, and the expected volume and timing of peak production, at the West White Rose Project; the timing at which two additional infill wells are scheduled to come online at the White Rose field; and the expected timing of startup of West White Rose.
There are numerous uncertainties inherent in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary from production estimates.
Although the Company believes that the expectations reflected by the forward-looking statements presented in this news release are reasonable, the Company’s forward-looking statements have been based on assumptions and factors concerning future events that may prove to be inaccurate. Those assumptions and factors are based on information currently available to the Company about itself and MEG and the businesses in which they operate. Information used in developing forward-looking statements has been acquired from various sources, including third party consultants, suppliers and regulators, among others.
Because actual results or outcomes could differ materially from those expressed in any forward-looking statements, investors should not place undue reliance on any such forward-looking statements. By their nature, forward-looking statements involve numerous assumptions, inherent risks and uncertainties, both general and specific, which contribute to the possibility that the predicted outcomes will not occur. Some of these risks, uncertainties and other factors are similar to those faced by other oil and gas companies and some are unique to the Company.
The Company’s Annual Information Form for the year ended December 31, 2017, offer documents (in respect of the offer to acquire MEG) and other documents filed with securities regulatory authorities (accessible through the SEDAR website www.sedar.com and the EDGAR website www.sec.gov) describe risks, material assumptions and other factors that could influence actual results and are incorporated herein by reference.
New factors emerge from time to time and it is not possible for management to predict all of such factors and to assess in advance the impact of each such factor on the Company’s business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are dependent upon other factors, and the Company’s course of action would depend upon management’s assessment of the future considering all information available to it at the relevant time. Any forward-looking statement speaks only as of the date on which such statement is made and, except as required by applicable securities laws, the Company undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events.
This news release contains references to the terms “funds from operations”, “free cash flow”, “adjusted net earnings”, “net debt”, “net debt to trailing funds from operations”, “EBITDA” and “operating netback”, which do not have standardized meanings prescribed by International Financial Reporting Standards (“IFRS”) and are therefore unlikely to be comparable to similar measures presented by other issuers. None of these measures is used to enhance the Company’s reported financial performance or position. These measures are useful complementary measures in assessing the Company’s financial performance, efficiency and liquidity. There is no comparable measure in accordance with IFRS for operating netback.
Funds from operations is a non-GAAP measure which should not be considered an alternative to, or more meaningful than, cash flow – operating activities as determined in accordance with IFRS, as an indicator of financial performance. Funds from operations is presented to assist management and investors in analyzing operating performance of the Company in the stated period. Funds from operations equals cash flow – operating activities plus change in non-cash working capital.
Funds from operations was restated in the second quarter of 2017 in order to be more comparable to similar non-GAAP measures presented by other companies. Changes from prior period presentation include the removal of adjustments for settlement of asset retirement obligations and deferred revenue. Prior periods have been restated to conform to current presentation.
Free cash flow is a non-GAAP measure, which should not be considered an alternative to, or more meaningful than, cash flow – operating activities as determined in accordance with IFRS, as an indicator of financial performance. Free cash flow is presented to assist management and investors in analyzing operating performance by the business in the stated period. Free cash flow equals funds from operations less capital expenditures and investment in joint ventures.
Free cash flow was restated in the first quarter of 2018 in order to be more comparable to similar non-GAAP measures presented by other companies. Changes from prior period presentation include the addition of investment in joint ventures. Prior periods have been restated to conform to current presentation.
The following table shows the reconciliation of net earnings to funds from operations and free cash flow, and related per share amounts, for the periods indicated:
|Three months ended||Nine months ended|
|Sep. 30||Jun. 30||Sep. 30||Sep. 30||Sep. 30|
|Items not affecting cash:|
|Depletion, depreciation, amortization and impairment||672||639||673||1,929||2,235|
|Exploration and evaluation expenses||-||7||1||7||6|
|Deferred income taxes||156||138||52||371||1|
|Foreign exchange gain||(6)||(2)||(3)||(7)||(5)|
|Gain on sale of assets||-||-||(2)||(4)||(33)|
|Unrealized mark to market loss (gain)||(22)||(26)||31||(134)||(1)|
|Share of equity investment income||(18)||(26)||(12)||(53)||(60)|
|Settlement of asset retirement obligations||(45)||(22)||(23)||(116)||(91)|
|Distribution from joint ventures||-||-||-||72||25|
|Change in non-cash working capital||(35)||(199)||3||(600)||61|
|Cash flow - operating activities||1,283||1,009||894||2,821||2,353|
|Change in non-cash working capital||35||199||(3)||600||(61)|
|Funds from operations||1,318||1,208||891||3,421||2,292|
|Investment in joint ventures||-||-||(12)||(40)||(72)|
|Free cash flow||350||500||368||1,068||745|
|Weighted average number of common shares outstanding - Basic||1005.1||1005.1||1,005.2||1005.1||1,005.4|
|Per common share - Basic ($/share)||1.31||1.20||0.89||3.40||2.28|
Adjusted net earnings is a non-GAAP measure which should not be considered an alternative to, or more meaningful than, net earnings as determined in accordance with IFRS, as an indicator of financial performance. Adjusted net earnings consists of net earnings and excludes items such as after-tax property, plant and equipment impairment charges (reversals), goodwill impairment charges, exploration and evaluation asset write-downs, inventory write-downs and loss (gain) on sale of assets which are not considered to be indicative of the Company’s ongoing financial performance. Adjusted net earnings is a complementary measure used in assessing the Company's financial performance through providing comparability between periods. Adjusted net earnings was redefined in the second quarter of 2016. Previously, adjusted net earnings was defined as net earnings plus after-tax property, plant and equipment impairment charges (reversals), goodwill impairment charges, exploration and evaluation asset write-downs and inventory write-downs.
The following table shows the reconciliation of net earnings to adjusted net earnings for the periods indicated:
|Three months ended||Nine months ended|
|Sep. 30||Jun. 30||Sep. 30||Sep. 30||Sep. 30|
|Impairment of property, plant and equipment, net of tax||23||21||-||44||123|
|Exploration and evaluation asset write-downs, net of tax||-||5||1||5||4|
|Gain on sale of assets, net of tax||-||-||(1)||(3)||(22)|
|Adjusted net earnings||568||474||136||1,287||219|
|Weighted average number of common shares outstanding - Basic||1005.1||1005.1||1,005.2||1005.1||1,005.4|
|Per common share - Basic ($/share)||0.57||0.47||0.14||1.28||0.22|
Net debt is a non-GAAP measure that equals total debt less cash and cash equivalents. Total debt is calculated as long-term debt, long-term debt due within one year and short-term debt. 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 total debt to net debt as at the dates indicated:
|Sep. 30||Jun. 30||Sep. 30|
|Long-term debt due within one year||388||394||-|
|Cash and cash equivalents||(2,916)||(2,583)||(2,486)|
Net debt to trailing funds from operations is a non-GAAP measure that equals net debt divided by the 12-month trailing funds from operations as at September 30, 2018. Net debt to trailing funds from operations is considered to be a useful measure in assisting management and investors to evaluate the Company's financial strength.
EBITDA is a non-GAAP measure which should not be considered an alternative to, or more meaningful than, net earnings as determined in accordance with IFRS, as an indicator of financial performance. EBITDA is presented in this news release to assist management and investors in analyzing operating performance by business in the stated period. EBITDA equals net earnings plus finance expenses (income), provisions for (recovery of) income taxes, and depletion, depreciation and amortization.
Operating netback is a common non-GAAP measure used in the oil and gas industry. This measure assists management and investors to evaluate the specific operating performance by product at the oil and gas lease level. Operating netback is calculated as gross revenue less royalties, production and operating and transportation costs on a per unit basis.
DISCLOSURE OF OIL AND GAS INFORMATION
Unless otherwise noted, projected and historical production volumes provided represent the Company’s working interest share before royalties.
The Company uses the term “barrels of oil equivalent” (or “boe”), which is consistent with other oil and gas companies’ disclosures, and is calculated on an energy equivalence basis applicable at the burner tip whereby one barrel of crude oil is equivalent to six thousand cubic feet of natural gas. The term boe is used to express the sum of the total company products in one unit that can be used for comparisons. Readers are cautioned that the term boe may be misleading, particularly if used in isolation. This measure is used for consistency with other oil and gas companies and does not represent value equivalency at the wellhead.
All currency is expressed in this news release in Canadian dollars unless otherwise indicated.More Details