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Press Release: Teck Reports Unaudited Second -7-

26 Jul 2018 9:43 am

Western Canada Select, or WCS, is a blend of conventionally produced heavy oils and bitumen, blended with diluent (condensate). WCS is a widely marketed crude grade with transparent market price references quoted at Hardisty and U.S. Gulf Coast market hubs. WCS at Hardisty, typically trades at a differential below the NYMEX WTI benchmark price, and traded at an average discount of US$19.27 per barrel for the second quarter, for a heavy value of US$48.61 per barrel for the second quarter. With new Canadian heavy production coming on stream throughout 2018 and 2019 and with limited pipeline export capacity to accommodate this new production, market conditions are indicative of a widening of this discount.

To facilitate the transportation of our bitumen by pipeline, we blend condensate acquired at the Edmonton/Fort Saskatchewan market hub for delivery to and blending at the East Tank Farm blending facility. Relative to NYMEX WTI, the benchmark market differential for condensate for the second quarter, determined at Edmonton, averaged US$0.95 per barrel for a condensate, for a value of US$68.83 per barrel for the second quarter. Readily accessed supplies of diluent in the near term are indicative of a condensate value at Edmonton, at or near the NYMEX WTI price.

Operating Netback(1)

The following table summarizes our Fort Hills operating netback for the month of June:
(Amounts reported in CAD$ per barrel of bitumen sold)     2018 
Bitumen price realized(3)                               $  64.59 
Crown royalties(4)                                         (3.59) 
Transportation costs(5)                                    (8.90) 
Operating costs(6)                                        (38.25) 
Operating netback(1)                                    $  13.85 


1) Non-GAAP measure. See "Use of Non-GAAP Financial Measures" section for further details.

2) Fort Hills financial results are included in operating results from June 1, 2018.

3) Bitumen price realized represents the realized petroleum revenue (blended bitumen sales revenue) net of diluent expense, expressed on a per barrel basis. Blended bitumen sales revenue represents revenue from our share of the heavy crude oil blend known as Fort Hills Reduced Carbon Life Cycle Dilbit Blend (FRB), sold at the Hardisty and U.S. Gulf Coast market hubs. FRB is comprised of bitumen produced from the Fort Hills oil sands mining and processing operations blended with purchased diluent. The cost of blending is affected by the amount of diluent required and the cost of purchasing, transporting and blending the diluent. A portion of diluent expense is effectively recovered in the sales price of the blended product. Diluent expense is also affected by the Canadian and U.S. benchmark pricing and changes in the value of the Canadian dollar relative to the U.S. dollar.

4) The royalty rate applicable to pre-payout oil sands operations starts at 1% of gross revenue and increases for every dollar by which the WTI crude oil price in Canadian dollars exceeds $55 per barrel, to a maximum of 9% when the WTI crude oil price is $120 per barrel or higher. Fort Hills is currently in the pre-payout phase. Detailed information regarding Alberta oil sands royalties can be found on the following website: https://www.energy.alberta.ca/OS/OSRoyalty/Pages/default.aspx.

5) Transportation costs represent pipeline and storage costs downstream of the East Tank Farm blending facility. We use various pipeline and storage facilities to transport and sell our blend to customers throughout North America. Sales to the U.S. markets require additional transportation costs, but realize higher selling prices.

6) Operating costs were lower than our guidance of CAD$40 to $50 per barrel. Operating costs per barrel are expected to decrease as the project continues to ramp-up to full capacity by the end of 2018.


Due to the strong start-up and commissioning, we now expect our share of bitumen production to be in the range of 8.5 million to 10.0 million barrels and operating costs to be $28.50 to $32.50 per barrel for the year, versus 7.5 million to 9.0 million barrels and $35.00 to $40.00 previously.

Based on our share of Fort Hills operating at full production rates (approximately 90% of nameplate capacity of 194,000 barrels per day), our estimated EBITDA sensitivity to a US$1/barrel change in the WCS price is approximately $18.5 million and $13.5 million to our after-tax profit.

Frontier Energy Project

The regulatory application review of Frontier is continuing with a public hearing before a federal/provincial panel scheduled to commence on September 25, 2018. The earliest a federal decision statement could be expected for Frontier is mid-2019. Our expenditures on Frontier are limited to supporting this process. We continue to evaluate the future project schedule and development options as part of our ongoing capital review and prioritization process.


Other operating expense, net of other income, was $117 million in the second quarter compared with other operating expense of $45 million a year ago. Significant items include negative pricing adjustments of $20 million, $29 million of take or pay contracts, $15 million of commodity derivative losses and $27 million in share-based compensation. The commodity derivative losses result from our short-term zinc and lead positions and from derivatives embedded in our gold and silver streaming agreements.

The table below outlines our outstanding receivable positions, provisionally valued at June 30, 2018 and March 31, 2018.
                                Outstanding at   Outstanding at 
                                June 30, 2018    March 31, 2018 
(payable pounds in millions)   Pounds   US$/lb   Pounds   US$/lb 
Copper                             112     3.01      130     3.04 
Zinc                               136     1.33      158     1.51 

Our finance expense of $55 million in the second quarter decreased by $4 million from a year ago. Our finance expense includes the interest expense on our debt, finance fees and amortization, interest components of our pension obligations and accretion on our decommissioning and restoration provisions, less any interest that we capitalize against our development projects. The primary reasons for the decrease in our finance expense were the lower outstanding debt balances and the favorable effect of a stronger Canadian dollar on our U.S. dollar denominated debt. In addition, a slightly higher amount of interest was capitalized against our development projects, including $41 million for Fort Hills and $41 million for Quebrada Blanca Phase 2, reflecting our increased carrying values of both of these projects compared with a year ago, but only two months of interest capitalization for Fort Hills compared to three months in 2017. We expect our interest expense to increase by approximately $40 million in the third quarter as we have ceased capitalizing interest to Fort Hills.

Non-operating expense in the second quarter was $12 million comprised of a $20 million loss on the revaluation of the embedded call option on our 8.5% long-term notes (due in 2024), offset by net foreign exchange gains of $8 million. However, as the foreign exchange gains and losses were subject to varying rates of tax, depending on the jurisdiction and nature, they resulted collectively in a $1 million after-tax loss.

Income and resource taxes for the quarter were $368 million, or 36% of pre-tax profits. This effective tax rate is higher than the Canadian statutory income tax rate of 27% as a result of resource taxes and higher rates in some foreign jurisdictions. Due to available tax pools, we are currently shielded from cash income taxes, but not resource taxes, in Canada. We remain subject to cash taxes in foreign jurisdictions.


Our financial position and liquidity remains strong. Our debt position, net debt, and credit ratios are summarized in the table below:
                                         June 30,       December 31, 
                                           2018             2017 
Term notes                              $   4,809      $       4,831 
Unamortized fees and discounts                (38)               (40) 
Other                                         255                286 
Total debt (US$ in millions)            $   5,026      $       5,077 
Canadian $ equivalent(1)                    6,619              6,369 
Less cash balances                         (1,631)              (952) 
Net debt                                $   4,988      $       5,417 
Debt to debt-plus-equity ratio(2 3)            24%                24% 
Net-debt to net-debt-plus-equity 
 ratio(2)                                      19%                21% 
Debt to EBITDA ratio(2)                       1.1x               1.1x 
Net debt to EBITDA ratio(2)                   0.8x               1.0x 
Average interest rate                         5.7%               5.7% 


1) Translated at period end exchange rates.

2) Non-GAAP financial measure. See "Use of Non-GAAP Financial Measures" section for further information.

3) Our revolving credit facility requires us to maintain a debt to debt-plus-equity ratio not greater than 50%.

Our liquidity remains strong at $5.6 billion. This will be enhanced by the $1.2 billion we expect to receive on July 26, 2018 upon the closing of the sale of our two-thirds interest in the Waneta Dam to BC Hydro, which was recently approved by the BCUC. With the receipt of the $1.2 billion, we will have $2.9 billion in cash, liquidity of $6.8 billion and our debt to EBITDA and net debt to EBITDA ratios will decline to 1.0 and 0.6, respectively.

In the second quarter of 2018, there was no change to the principal balance of our public notes, which remained at US$4.8 billion.

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