Teck Metals Ltd.

Mississauga, Canada

Teck Metals Ltd.

Mississauga, Canada

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News Article | May 12, 2017
Site: www.marketwired.com

ST. JOHN'S, TERRE-NEUVE-ET-LABRADOR--(Marketwired - 12 mai 2017) - Fortis Inc. (« Fortis ») (TSX:FTS)(NYSE:FTS) et Ressources Teck Limitée (« Teck ») (TSX:TECK.A)(TECK.B)(NYSE:TECK) ont annoncé aujourd'hui la conclusion d'un accord par lequel Fortis se porte acquéreuse des intérêts de Teck dans le barrage Waneta, soit les deux tiers de la propriété, et des actifs de transport connexes situés en Colombie-Britannique (Canada), le tout pour la somme de 1,2 milliard de dollars comptant. L'accord prévoit un bail de 20 ans au titre duquel Teck Metals Ltd. (« Teck Metals ») pourra faire usage de la participation de Fortis dans le barrage Waneta afin de produire l'électricité devant alimenter ses installations industrielles de Trail (les « installations de Trail »). Les paiements annuels s'élèveront initialement à environ 75 millions de dollars et augmenteront à raison de 2 % par année, ce qui correspond à un prix initial de 40 $/MWh pour une consommation annuelle d'électricité de 1 880 GWh. Teck Metals aura aussi l'option de prolonger le bail pour une autre période de 10 ans, à des tarifs comparables. « Grâce à cet accord, Teck renforce davantage son bilan et obtient un capital substantiel à réinvestir dans la croissance globale de ses activités, indique Don Lindsay, président et chef de la direction de Teck. Ainsi, nos installations de Trail bénéficieront pendant longtemps d'une alimentation en électricité sûre à des tarifs concurrentiels, inférieurs à ceux du marché, ce qui nous permettra d'investir dans des projets innovants de modernisation de nos installations. » « Installation de grande qualité productrice d'énergie renouvelable et située au cœur de nos activités britanno-colombiennes, le barrage Waneta est le complément idéal à notre stratégie d'investissement dans les énergies durables, souligne M. Barry Perry, président et chef de la direction de Fortis. Il s'agit d'un bien durable qui générera d'excellents flux de trésorerie, garantis par le bail de 20 ans avec Teck. Nous prévoyons que cette acquisition contribuera dès maintenant au bénéfice par action. » À la clôture de l'opération, Teck s'attend à réaliser produit net comptable d'environ 800 millions de dollars, qui ne fera l'objet d'aucun prélèvement d'impôt. Depuis 2012, Teck a investi approximativement 525 millions de dollars dans divers projets d'amélioration de l'efficacité, de la productivité et de la performance environnementale de ses installations. De plus, elle a engagé 174 millions de dollars pour la construction d'une deuxième usine d'acide, qui est déjà en chantier et dont la mise en service est prévue pour l'été 2019. Teck a aussi ciblé de nouveaux projets, actuellement à l'étude, qui représentent un investissement total de 150 millions de dollars sur cinq ans dans l'amélioration de sa rentabilité, de sa productivité et sa performance environnementale. L'acquisition du barrage Waneta, situé au cœur du territoire de FortisBC, témoigne de la confiance et de l'engagement de Fortis envers la Colombie-Britannique. FortisBC est enracinée dans la région depuis plus d'un siècle et elle emploie environ 350 travailleurs dans la région de Kootenay. En plus des quatre installations de production qu'elle possède sur la rivière Kootenay, FortisBC exploite le barrage Waneta et l'Expansion Waneta, en plus d'en assurer l'entretien. Le barrage Waneta sera exploité en tant que filiale d'infrastructure énergétique non réglementée de Fortis Inc. Fortis financera l'opération au moyen de fonds en caisse, de capitaux empruntés et de capitaux propres. La clôture de l'opération est sujette aux réserves d'usage, soit l'obtention des approbations et consentements requis. De plus, BC Hydro, qui détient l'autre tiers des intérêts dans les actifs du barrage Waneta et reçoit actuellement le tiers de l'énergie produite, a, de ce fait, droit de préemption sur la participation de Teck, conformément à l'accord de copropriété et d'exploitation que Teck Metals et BC Hydro ont conclu en 2010 à l'égard du barrage. BC Hydro doit aussi fournir certains consentements et apporter des modifications pour que l'opération se concrétise. Teck versera une indemnité de rupture à Fortis si BC Hydro décide d'exercer son droit de préemption. La clôture de l'opération devrait avoir lieu au quatrième trimestre de 2017. Marchés mondiaux CIBC Inc. agit comme conseiller financier exclusif de Ressources Teck dans le cadre de l'opération. Le barrage Waneta, situé sur la rivière Pend d'Oreille, a une capacité totale de 496 mégawatts (MW) en énergie renouvelable et génère en moyenne 2 750 gigawattheures par année. Les installations de Teck à Trail consomment aux alentours de 1 880 gigawattheures de l'électricité qui provient du barrage Waneta. BC Hydro détient un tiers des intérêts dans le barrage Waneta et reçoit environ le tiers de l'énergie qu'il produit. Fortis détient 51 % de l'Expansion Waneta, projet qui s'est terminé en 2015 et qui a ajouté une capacité de 335 MW en énergie propre grâce à l'ajout d'une deuxième centrale en aval. Le barrage Waneta est régi par la convention de la centrale Canal (« CCC »), conclue entre BC Hydro, FortisBC et les propriétaires d'autres centrales le long des rivières Kootenay et Pend d'Oreille. La CCC permet aux parties, grâce à une utilisation coordonnée des débits d'eau ainsi qu'à l'exploitation coordonnée des réservoirs de stockage et des centrales, de produire plus d'électricité à partir de leurs ressources de production respectives qu'elles ne pourraient le faire si elles exerçaient leurs activités de façon indépendante. Les intérêts de Teck dans la production du barrage Waneta sont définis et déterminés conformément aux stipulations de la CCC. La CCC réduit le risque hydrologique lié au barrage Waneta. Parmi les actifs acquis, on compte aussi la ligne de transport 71, qui donne accès aux marchés d'importation et d'exportation aux États-Unis, et d'autres actifs de transport locaux. Les installations de Teck à Trail, ville du sud-est de la Colombie-Britannique, forment l'un des plus grand complexes intégrés de fusion et d'affinage du zinc et du plomb au monde. On y produit aussi toute une gamme de métaux précieux et spéciaux, de produits chimiques et d'engrais. Plus de la moitié des produits affinés aux installations de Trail proviennent des mines de Teck. En 2016, les installations de Trail ont produit 312 000 tonnes de zinc affiné, dont la vente a généré un chiffre d'affaire de 2,05 milliards de dollars et un bénéfice brut avant amortissement de 241 millions de dollars. Fortis se positionne parmi les géants nord-américains du secteur réglementé de l'électricité et du gaz, forte d'un actif d'environ 48 milliards de dollars. Ses 8 000 employés servent des clients dans cinq provinces canadiennes, neuf États américains et trois pays des Caraïbes. Les actions de Fortis sont inscrites à la cote de la TSX et de la NYSE sous le symbole « FTS ». Pour en savoir plus, consultez le www.fortis.com, le www.sedar.com ou le www.sec.gov. Teck est une société exploitante de ressources vouée à l'exploitation et à la mise en valeur responsables des ressources minérales. Ses principales divisions sont spécialisées dans le cuivre, le charbon destiné à la sidérurgie, le zinc et l'énergie. Son siège social est à Vancouver (Canada) et ses actions sont inscrites à la cote de la TSX, sous les symboles « TECK.A » et « TECK.B », et de la NYSE, sous le symbole « TECK ». Teck est présente sur le Web à l'adresse www.teck.com et sur Twitter à @TeckResources. Fortis et Teck incluent dans le présent communiqué des énoncés prospectifs au sens des lois sur les valeurs mobilières applicables, y compris la Private Securities Litigation Reform Act of 1995. Les mots « anticiper », « croire », « budgets », « pourrait », « estimer », « s'attendre à », « prévoir », « avoir l'intention de », « peut », « possible », « plans », « projets », « planifié », « cible », « devrait », le pendant négatif de ces termes et toute expression semblable servent aussi souvent que possible à introduire des énoncés prospectifs, qui incluent, notamment, en ce qui a trait à Fortis, les énoncés se rapportant à l'acquisition d'intérêts dans le barrage Waneta et les actifs de transport connexes, à son échéancier et aux avantages qu'elle représente; à la contrepartie totale attendue et aux ajustements; à la satisfaction des conditions de clôture, y compris l'obtention de certains consentements et approbations; et au financement prévu. En ce qui a trait à Teck, les énoncés prospectifs incluent, notamment : les énoncés se rapportant à la vente de ses intérêts dans le barrage Waneta et les actifs de transport connexes, et à la location de ces intérêts; aux avantages attendus de l'opération; à la valeur nette comptable du gain attendu; à la date d'achèvement de la construction de la deuxième usine d'acide aux installations de Trail; au potentiel de nouveaux projets aux installations de Trail et aux avantages qu'ils représentent; et à la satisfaction des conditions de clôture, y compris l'obtention de certains consentements et approbations. Les énoncés prospectifs comportent des risques, des incertitudes et des hypothèses considérables. Les conclusions contenues dans les énoncés prospectifs reposent sur un certain nombre de facteurs ou hypothèses d'importance. Ces facteurs ou hypothèses sont assujettis à des incertitudes et à des risques inhérents entourant les attentes futures en général, y compris ceux contenus dans les énoncés prospectifs. Ces facteurs et hypothèses comprennent notamment : l'obtention des approbations requises en vue de l'acquisition et à l'échéancier et aux modalités de ces approbations; les risques entourant la non-réalisation de l'acquisition ou son échéancier; le risque que BC Hydro exerce son droit de préemption; les risques d'intrusion; les risques liés à la satisfaction des conditions de l'acquisition; les risques que des conditions économiques défavorables se répercutent sur les résultats d'exploitation de Fortis et de Teck; les risques de change; et les conditions économiques, politiques et de marché en général. De plus, en ce qui a trait à Teck, on tient pour acquis, dans les hypothèses à l'égard des nouveaux projets aux installations de Trail et de leurs avantages, que ces projets seront approuvés et qu'ils produiront les résultats attendus. Fortis et Teck mettent en garde les lecteurs sur le fait que divers facteurs pourraient entraîner un écart important entre les rendements, les réalisations ou les résultats réels et ceux exprimés ou sous-entendus dans les énoncés prospectifs. Le lecteur est invité à étudier ces facteurs attentivement et à ne pas se fier indûment aux énoncés prospectifs. Pour obtenir plus de renseignements sur certains de ces facteurs de risque, prière de consulter les documents du dossier d'information continue que Fortis dépose de temps à autre auprès des autorités de réglementation en valeurs mobilières du Canada et de la Securities and Exchange Commission. Fortis décline toute intention ou obligation de mettre à jour ou de modifier les énoncés prospectifs par suite de faits nouveaux, d'événements futurs ou autrement. Pour obtenir plus de renseignements sur certains facteurs de risque se rapportant à Teck, prière de consulter les documents du dossier d'information continue que Teck déposent de temps à autre auprès des autorités de réglementation en valeurs mobilières du Canada et de la Securities and Exchange Commission. Teck décline toute obligation de réviser ou de mettre à jour les énoncés prospectifs après la publication du présent communiqué ou de les réviser si des événements futurs imprévus surviennent, à moins les lois sur les valeurs mobilières ne l'exigent.


News Article | May 12, 2017
Site: www.marketwired.com

VANCOUVER, BRITISH COLUMBIA and ST. JOHN'S, NEWFOUNDLAND AND LABRADOR--(Marketwired - May 12, 2017) - Fortis Inc. ("Fortis"), (TSX/NYSE:FTS) and Teck Resources Limited ("Teck"), (TSX: TECK.A and TECK.B, NYSE: TECK) today announced an agreement under which Fortis will purchase Teck's two-thirds interest in the Waneta Dam and related transmission assets in British Columbia, Canada, for $1.2 billion cash. Under the agreement, Teck Metals Ltd. ("Teck Metals") will be granted a 20-year lease to use Fortis' two-thirds interest in Waneta to produce power for its industrial operations in Trail ("Trail Operations"). Annual payments will begin at approximately $75 million per year and escalate at 2% per annum, equivalent to an initial power price of $40/MWh based on 1,880 GWh of energy per annum. Teck Metals will have an option to extend the lease for a further 10 years at comparable rates. "This agreement will further strengthen Teck's balance sheet and provide significant new capital that can be reinvested to grow our overall business," said Don Lindsay, President and CEO, Teck. "We have secured a long-term power supply for Trail Operations at competitive, below-market pricing and will invest in innovative projects to further enhance and modernize this facility." "Waneta is a high-quality, renewable energy facility located in an area central to our BC operations, making this acquisition a natural fit with our strategy to increase our investment in sustainable energy," said Mr. Barry Perry, President and CEO of Fortis. "Waneta will be a stable long-term asset that will generate strong cash flows secured by a 20-year lease with Teck. The transaction is expected to be immediately accretive to earnings per share." Teck expects to realize a net book gain of approximately $800 million on the closing of the transaction. No cash tax will be payable on the proceeds. Since 2012, Teck has invested approximately $525 million at Trail Operations in projects to improve efficiency, productivity and environmental performance. In addition, Teck has committed $174 million for a second new acid plant which is currently under construction and scheduled to be operational in summer 2019. Teck has also identified, and is currently evaluating, a further $150 million in new projects to improve profitability, productivity and environmental performance over the next five years. The acquisition of the Waneta Dam, located in the centre of FortisBC's territory, demonstrates Fortis' commitment to and confidence in British Columbia. FortisBC has longstanding roots in the area that span more than a century with FortisBC employing approximately 350 workers in the Kootenay region. In addition to operating four of its own generating facilities on the Kootenay River, FortisBC currently operates and maintains Waneta and the Waneta Expansion. The Waneta Dam will operate as a non-regulated energy infrastructure subsidiary of Fortis Inc. Fortis will finance the transaction through a combination of cash on hand, debt and equity. Closing of the transaction is subject to customary conditions, including receipt of certain approvals and consents. In addition, BC Hydro, which owns one-third of the Waneta Dam assets and currently receives one-third of the Waneta Dam generation, has a right of first offer with respect to the sale of Teck's two-third interest under the 2010 co-ownership and operating agreement between Teck Metals and BC Hydro in relation to Waneta. In addition, certain consents and amendments from BC Hydro are required in connection with the transaction. Teck will pay a break fee to Fortis in the event BC Hydro exercises its right of first offer. Closing is expected to occur in the fourth quarter of 2017. CIBC World Markets Inc. is acting as exclusive financial advisor to Teck Resources with respect to the transaction. The Waneta Dam, located on the Pend d'Oreille River, has a total capacity of 496 megawatts (MW) of renewable power and generates an average of 2,750 gigawatt hours of energy per year. Teck's Trail Operations utilizes approximately 1,880 gigawatt hours of energy per year from Waneta. BC Hydro has a one-third ownership interest in Waneta and receives approximately one-third of the Waneta Dam generation. Fortis holds a 51% interest in the Waneta Expansion, completed in 2015. This project added 335 MW of new clean power generation from a second powerhouse downstream of the dam. The Waneta Dam is governed by the Canal Plant Agreement ("CPA"), a contractual arrangement between BC Hydro, FortisBC and other plant owners along the Kootenay and Pend d'Oreille rivers. The CPA enables the parties, through the coordinated use of water flows and coordinated operation of storage reservoirs and generating plants, to generate more power collectively from their respective generating plants than if they were to operate independently. Teck's two-thirds interest in the Waneta Dam output is defined and determined in accordance with the terms of the CPA. The CPA mitigates hydrology risk for the Waneta Dam. Also included in this acquisition is the Line 71 transmission line and other local transmission assets. This line enables access to the U.S. power import/export market. Teck's Trail Operations, located in southeastern British Columbia, is one of the world's largest fully integrated zinc and lead smelting and refining complexes. It also produces a variety of precious and specialty metals, chemicals and fertilizer products. Over half of the product refined at Trail Operations comes from Teck mines. In 2016, Trail Operations produced and sold 312,000 tonnes of refined zinc and generated $2.05 billion in revenues and $241 million in gross profit before depreciation and amortization. Fortis is a leader in the North American regulated electric and gas utility industry with total assets of approximately $48 billion. The Corporation's 8,000 employees serve utility customers in five Canadian provinces, nine U.S. states and three Caribbean countries. Fortis shares are listed on the Toronto Stock Exchange and New York Stock Exchange and trade under the symbol FTS. Additional information can be accessed at www.fortisinc.com, www.sedar.com, or www.sec.gov. Teck is a diversified resource company committed to responsible mining and mineral development with major business units focused on copper, steelmaking coal, zinc and energy. Headquartered in Vancouver, Canada, its shares are listed on the Toronto Stock Exchange under the symbols TECK.A and TECK.B and the New York Stock Exchange under the symbol TECK. Learn more about Teck at www.teck.com or follow @TeckResources. Fortis and Teck include forward-looking information in this release within the meaning of applicable securities laws including the Private Securities Litigation Reform Act of 1995. Wherever possible, words such as "anticipates", "believes", "budgets", "could", "estimates", "expects", "forecasts", "intends", "may", "might", "plans", "projects", "schedule", "should", "target", "will", "would" and the negative of these terms and other similar terminology or expressions have been used to identify the forward-looking information, which includes with respect to Fortis, without limitation: statements related to the acquisition of an interest in the Waneta Dam and related transmission assets; the expected timing and benefits thereof; the total expected consideration and adjustments; the conditions precedent to the closing, including receipt of certain approvals and consents; and the expected financing of the acquisition. Forward-looking information with respect to Teck includes, without limitation: statements related to the sale of an interest in the Waneta Dam and related transmission assets and lease of an interest therein, expected benefits of the transaction, amount of the expected net book gain, timing of completion of the second acid plant at Trail Operations, potential for new projects at Trail Operations and potential benefits thereof, the conditions precedent to the closing, including receipt of certain approvals. Forward-looking information involves significant risk, uncertainties and assumptions. Certain material factors or assumptions have been applied in drawing the conclusions contained in the forward-looking information. These factors or assumptions are subject to inherent risks and uncertainties surrounding future expectations generally, including those identified from time to time in the forward-looking information. Such risk factors or assumptions include, but are not limited to: the ability to obtain the required approvals in connection with the acquisition and the timing and terms thereof; risks associated with the uncertainty of the completion of the acquisition and the timing thereof; the risk that BC Hydro exercises its pre-emptive right; interloper risk; the risk that conditions to the acquisition may not be satisfied; risk associated with the impact of less favorable economic conditions on Fortis' and Teck's results of operations; currency exchange rates and general economic, market and political conditions. In addition, with respect to Teck, assumptions regarding new projects at Trail Operations and their benefits assume such projects are approved and perform as anticipated. Fortis and Teck caution readers that a number of factors could cause actual results, performance or achievements to differ materially from the results discussed or implied in their forward-looking information. These factors should be considered carefully and undue reliance should not be placed on the forward-looking information. For additional information with respect to certain of these risks relating to Fortis, reference should be made to the continuous disclosure materials filed from time to time by Fortis with Canadian securities regulatory authorities and the Securities and Exchange Commission. Fortis disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. For additional information with respect to certain of these risks relating to Teck, reference should be made to the continuous disclosure materials filed from time to time by Teck with Canadian securities regulatory authorities and the Securities and Exchange Commission. Teck does not assume the obligation to revise or update forward-looking statements after the date of this release or to revise them to reflect the occurrence of future unanticipated events, except as may be required under applicable securities laws.


News Article | May 12, 2017
Site: www.marketwired.com

ST. JOHN'S, NEWFOUNDLAND--(Marketwired - May 12, 2017) - Fortis Inc. ("Fortis"), (TSX:FTS)(NYSE:FTS) and Teck Resources Limited ("Teck"), (TSX:TECK.A)(TSX:TECK.B)(NYSE:TECK) today announced an agreement under which Fortis will purchase Teck's two-thirds interest in the Waneta Dam and related transmission assets in British Columbia, Canada, for $1.2 billion cash. Under the agreement, Teck Metals Ltd. ("Teck Metals") will be granted a 20-year lease to use Fortis' two-thirds interest in Waneta to produce power for its industrial operations in Trail ("Trail Operations"). Annual payments will begin at approximately $75 million per year and escalate at 2% per annum, equivalent to an initial power price of $40/MWh based on 1,880 GWh of energy per annum. Teck Metals will have an option to extend the lease for a further 10 years at comparable rates. "This agreement will further strengthen Teck's balance sheet and provide significant new capital that can be reinvested to grow our overall business," said Don Lindsay, President and CEO, Teck. "We have secured a long-term power supply for Trail Operations at competitive, below-market pricing and will invest in innovative projects to further enhance and modernize this facility." "Waneta is a high-quality, renewable energy facility located in an area central to our BC operations, making this acquisition a natural fit with our strategy to increase our investment in sustainable energy," said Mr. Barry Perry, President and CEO of Fortis. "Waneta will be a stable long-term asset that will generate strong cash flows secured by a 20-year lease with Teck. The transaction is expected to be immediately accretive to earnings per share." Teck expects to realize a net book gain of approximately $800 million on the closing of the transaction. No cash tax will be payable on the proceeds. Since 2012, Teck has invested approximately $525 million at Trail Operations in projects to improve efficiency, productivity and environmental performance. In addition, Teck has committed $174 million for a second new acid plant which is currently under construction and scheduled to be operational in summer 2019. Teck has also identified, and is currently evaluating, a further $150 million in new projects to improve profitability, productivity and environmental performance over the next five years. The acquisition of the Waneta Dam, located in the centre of FortisBC's territory, demonstrates Fortis' commitment to and confidence in British Columbia. FortisBC has longstanding roots in the area that span more than a century with FortisBC employing approximately 350 workers in the Kootenay region. In addition to operating four of its own generating facilities on the Kootenay River, FortisBC currently operates and maintains Waneta and the Waneta Expansion. The Waneta Dam will operate as a non-regulated energy infrastructure subsidiary of Fortis Inc. Fortis will finance the transaction through a combination of cash on hand, debt and equity. Closing of the transaction is subject to customary conditions, including receipt of certain approvals and consents. In addition, BC Hydro, which owns one-third of the Waneta Dam assets and currently receives one-third of the Waneta Dam generation, has a right of first offer with respect to the sale of Teck's two-third interest under the 2010 co-ownership and operating agreement between Teck Metals and BC Hydro in relation to Waneta. In addition, certain consents and amendments from BC Hydro are required in connection with the transaction. Teck will pay a break fee to Fortis in the event BC Hydro exercises its right of first offer. Closing is expected to occur in the fourth quarter of 2017. CIBC World Markets Inc. is acting as exclusive financial advisor to Teck Resources with respect to the transaction. The Waneta Dam, located on the Pend d'Oreille River, has a total capacity of 496 megawatts (MW) of renewable power and generates an average of 2,750 gigawatt hours of energy per year. Teck's Trail Operations utilizes approximately 1,880 gigawatt hours of energy per year from Waneta. BC Hydro has a one-third ownership interest in Waneta and receives approximately one-third of the Waneta Dam generation. Fortis holds a 51% interest in the Waneta Expansion, completed in 2015. This project added 335 MW of new clean power generation from a second powerhouse downstream of the dam. The Waneta Dam is governed by the Canal Plant Agreement ("CPA"), a contractual arrangement between BC Hydro, FortisBC and other plant owners along the Kootenay and Pend d'Oreille rivers. The CPA enables the parties, through the coordinated use of water flows and coordinated operation of storage reservoirs and generating plants, to generate more power collectively from their respective generating plants than if they were to operate independently. Teck's two-thirds interest in the Waneta Dam output is defined and determined in accordance with the terms of the CPA. The CPA mitigates hydrology risk for the Waneta Dam. Also included in this acquisition is the Line 71 transmission line and other local transmission assets. This line enables access to the U.S. power import/export market. Teck's Trail Operations, located in southeastern British Columbia, is one of the world's largest fully integrated zinc and lead smelting and refining complexes. It also produces a variety of precious and specialty metals, chemicals and fertilizer products. Over half of the product refined at Trail Operations comes from Teck mines. In 2016, Trail Operations produced and sold 312,000 tonnes of refined zinc and generated $2.05 billion in revenues and $241 million in gross profit before depreciation and amortization. Fortis is a leader in the North American regulated electric and gas utility industry with total assets of approximately $48 billion. The Corporation's 8,000 employees serve utility customers in five Canadian provinces, nine U.S. states and three Caribbean countries. Fortis shares are listed on the Toronto Stock Exchange and New York Stock Exchange and trade under the symbol FTS. Additional information can be accessed at www.fortisinc.com, www.sedar.com, or www.sec.gov. Teck is a diversified resource company committed to responsible mining and mineral development with major business units focused on copper, steelmaking coal, zinc and energy. Headquartered in Vancouver, Canada, its shares are listed on the Toronto Stock Exchange under the symbols TECK.A and TECK.B and the New York Stock Exchange under the symbol TECK. Learn more about Teck at www.teck.com or follow @TeckResources. Fortis and Teck include forward-looking information in this release within the meaning of applicable securities laws including the Private Securities Litigation Reform Act of 1995. Wherever possible, words such as "anticipates", "believes", "budgets", "could", "estimates", "expects", "forecasts", "intends", "may", "might", "plans", "projects", "schedule", "should", "target", "will", "would" and the negative of these terms and other similar terminology or expressions have been used to identify the forward-looking information, which includes with respect to Fortis, without limitation: statements related to the acquisition of an interest in the Waneta Dam and related transmission assets; the expected timing and benefits thereof; the total expected consideration and adjustments; the conditions precedent to the closing, including receipt of certain approvals and consents; and the expected financing of the acquisition. Forward-looking information with respect to Teck includes, without limitation: statements related to the sale of an interest in the Waneta Dam and related transmission assets and lease of an interest therein, expected benefits of the transaction, amount of the expected net book gain, timing of completion of the second acid plant at Trail Operations, potential for new projects at Trail Operations and potential benefits thereof, the conditions precedent to the closing, including receipt of certain approvals. Forward-looking information involves significant risk, uncertainties and assumptions. Certain material factors or assumptions have been applied in drawing the conclusions contained in the forward-looking information. These factors or assumptions are subject to inherent risks and uncertainties surrounding future expectations generally, including those identified from time to time in the forward-looking information. Such risk factors or assumptions include, but are not limited to: the ability to obtain the required approvals in connection with the acquisition and the timing and terms thereof; risks associated with the uncertainty of the completion of the acquisition and the timing thereof; the risk that BC Hydro exercises its pre-emptive right; interloper risk; the risk that conditions to the acquisition may not be satisfied; risk associated with the impact of less favorable economic conditions on Fortis' and Teck's results of operations; currency exchange rates and general economic, market and political conditions. In addition, with respect to Teck, assumptions regarding new projects at Trail Operations and their benefits assume such projects are approved and perform as anticipated. Fortis and Teck caution readers that a number of factors could cause actual results, performance or achievements to differ materially from the results discussed or implied in their forward-looking information. These factors should be considered carefully and undue reliance should not be placed on the forward-looking information. For additional information with respect to certain of these risks relating to Fortis, reference should be made to the continuous disclosure materials filed from time to time by Fortis with Canadian securities regulatory authorities and the Securities and Exchange Commission. Fortis disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. For additional information with respect to certain of these risks relating to Teck, reference should be made to the continuous disclosure materials filed from time to time by Teck with Canadian securities regulatory authorities and the Securities and Exchange Commission. Teck does not assume the obligation to revise or update forward-looking statements after the date of this release or to revise them to reflect the occurrence of future unanticipated events, except as may be required under applicable securities laws.


News Article | May 15, 2017
Site: www.mining-journal.com

Teck Resources (CN:TECK.A) has agreed to sell its two-thirds interest in the Waneta Dam hydroelectric power facility in British Columbia to utility group, Fortis (US:FTS), for C$1.2 billion (US$877 million) in cash, which the miner says will further strengthen the balance sheet and be reinvested into the overall business. Waneta Dam on the Pend d’Oreille River generates some 2,750GWh of energy per annum, of which Teck uses about 1,880GWh for its Trail operations – one of the world’s largest fully-integrated zinc and lead smelting and refining complexes. Trail last year produced 312,000 tonnes of refined zinc for C$2.05 billion in revenue and C$241 million in gross profit. The agreement would see Teck subsidiary Teck Metals granted a 20-year lease to use the power generation capacity sold to Fortis to continue supplying Trail. Annual payments are set to start at around C$75 million, rising 2% per annum, equivalent to an initial power price of C$40/MWh based on 1,880 GWhpa of energy. Teck will have an option to extend the lease for another 10 years at “comparable rates”. Teck chief executive Don Lindsay said the deal secured long-term power supply for Trail at “competitive, below-market pricing” while allowing the miner to spend on “innovative projects to further enhance and modernise this facility”.” Teck expects to realise a net book gain of some C$800 million on the deal, which is subject to “customary” conditions. However, one potential hiccup to the agreement may be an existing first right of refusal over Teck’s stake held by BC Hydro, which owns the other third of Waneta Dam. BMO Capital Markets analyst Alex Terentiew consented the deal would bolster Teck’s balance sheet and provide opportunities to spend the extra cash, but countered that additional costs at Trail and removal of infrastructure assets from the company’s portfolio meant the news was net neutral to its valuation. “While Teck received C$1.2 billion, Trail will pay C$75 million per annum, which reduces our NAV for Trail by C$672 million, which, in addition to removing the $500 million in value we previously placed on Waneta Dam, largely offsets the C$1.2 billion in sale proceeds,” he said in a note early this week. Further, he was not expecting any exciting new projects to be announced on the back of the cash injection. “With US$4.7 billion capex guided by Teck for [the Quebrada Blanca phase two project in Chile] and Teck’s ultimate ownership of the project (currently 76.5%, but responsible for 85% of spending) yet to be determined, we expect Teck hold on to its cash.”


News Article | May 15, 2017
Site: www.marketwired.com

BRIDGEWATER, NOVA SCOTIA--(Marketwired - May 15, 2017) - Silver Spruce Resources Inc. ("Silver Spruce" or the "Company") (TSX VENTURE:SSE)(FRANKFURT:S6Q) is pleased to announce the appointment of Greg Davison, MSc, PGeo to its Board of Directors. Mr. Davison is a professional consulting exploration geologist, project manager and ore mineralogist with thirty-nine years of practical field, commercial laboratory and management experience in diverse geological settings. Mr. Davison has expertise in ore geology, process mineralogy, property evaluation, bulk sampling and pilot process operations. He has contributed to the development of exploration properties, ore deposits and mines in Canada, United States, Mexico, Greenland, Russia, Central and South America, Africa, Middle East, Asia and Australia. Greg works with Teck Metals' research team on VMS Cu-Zn-Pb-Ag-Au (San Nicolás), porphyry Cu and Cu-Mo (Highland Valley, Quebrada Blanca), rift intrusion Ni-Cu-PGE (Mesaba) and stratabound Pb-Zn (Red Dog) deposits. As VP Exploration, he led Tribute Minerals' programs in Ontario, the first junior company to utilize Titan-24 geophysics to guide VMS targeting, successfully drilling the Garnet Lake Zn-Cu deposit. As a project geologist, he conducted exploration of Archean VMS targets in the English River metamorphic terrane. He has performed ore mineralogy studies on VMS deposits in Mexico, Bolivia, Alaska, Canada and Iran. Mr. Davison has completed independent 43-101 reports for VMS, intrusive-related gold, Dawson orogenic gold, Keno Hill Ag-Pb-Zn, epithermal gold and diamond kimberlite projects, and technical and assessment reports for junior to major public companies, SGS Lakefield Research and Watts Griffis McOuat, among others. Greg graduated with an MSc in Geological Sciences from Brock University and an Honours BSc in Geology from Dalhousie University, and is a professional geologist (P.Geo.) licensed with the Association of Professional Geoscientists of Ontario and the Association of Professional Engineers & Geoscientists of British Columbia. "Silver Spruce Resources is honored to have Greg join our Board. I have known him for many years and find his experience, judgement and ethics to be of the highest order. He will bring expertise in VMS deposits and project management to assist the Company's growth as we advance our Kay Mine VMS project in Arizona and our Pino de Plata epithermal silver project in Mexico," said President Karl Boltz - President & CEO. Silver Spruce Resources Inc. is a well-positioned Canadian junior exploration company pursuing development of the Kay Mine volcanogenic massive sulfide project in Arizona, USA, and the Pino De Plata and the Encino De Oro epithermal silver/ base metal/ gold projects, located in the prolific Sierra Madre Occidental region of western Chihuahua State in Mexico. Neither TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this release. The company seeks Safe Harbour.


News Article | July 28, 2017
Site: www.marketwired.com

ST. JOHN'S, NEWFOUNDLAND AND LABRADOR--(Marketwired - July 28, 2017) - Fortis Inc. ("Fortis" or the "Corporation") (TSX:FTS)(NYSE:FTS), a leader in the North American regulated electric and gas utility industry, released its second quarter results today. "Two clear goals for us in 2017 were realizing the economic benefit of the acquisition of ITC, which remains nicely accretive, and securing a reasonable outcome in our first large rate case in Arizona since the announcement of the UNS Energy acquisition in 2013. Achievement of these two goals was a factor in delivering strong second quarter results," said Barry Perry, President and Chief Executive Officer, Fortis. The Corporation reported second quarter net earnings attributable to common equity shareholders of $257 million, or $0.62 per common share, compared to $107 million, or $0.38 per common share, for the same period of 2016. On a year-to-date basis, reported net earnings attributable to common equity shareholders were $551 million, or $1.34 per common share, compared to $269 million, or $0.95 per common share, for the same period of 2016. On an adjusted basis, net earnings attributable to common equity shareholders for the second quarter were $253 million, or $0.61 per common share, an increase of $0.16 per common share over the same period of 2016. On a year-to-date basis, adjusted net earnings attributable to common equity shareholders were $540 million, or $1.31 per common share, an increase of $0.18 per common share over the same period of 2016. Adjusted net earnings no longer excludes mark-to-market adjustments related to derivative instruments, which occur in the normal course of business, as comparative information is now presented in reported net earnings. Capital expenditure plan on track and supported by strong cash flow Capital expenditures for the first half of 2017 were $1.4 billion and the Corporation's consolidated capital expenditure plan of $3.1 billion for 2017 is on track. Cash flow from operating activities totalled $1.2 billion for the first half of 2017, an increase of 28% over the same period of 2016. The increase reflects higher earnings, driven by UNS Energy and ITC, partially offset by timing differences in working capital. Fortis uses financial measures that do not have a standardized meaning under generally accepted accounting principles in the United States of America ("US GAAP") and may not be comparable to similar measures presented by other entities. Fortis calculated the non-US GAAP measures by adjusting certain US GAAP measures for specific items that impact comparability but which the Corporation does not consider part of normal, ongoing operations. Refer to the Financial Highlights section of the Corporation's Management Discussion and Analysis for further discussion of these items. The Corporation's capital program continues to address the energy infrastructure needs of customers. The Corporation's five-year consolidated capital expenditures through 2021 are expected to be approximately $13 billion, including more than $3.5 billion of capital expenditures at ITC. Construction of the Tilbury liquefied natural gas ("LNG") facility expansion in British Columbia, the Corporation's largest ongoing capital project, is nearing completion. The total cost of the project is estimated at approximately $400 million, before allowance for funds used during construction and development costs. The facility is expected to be in service in the third quarter of 2017. The Corporation continues to invest in four Multi-Value Projects ("MVPs") at ITC, which are regional electric transmission projects that have been identified by the Midcontinent Independent System Operator to address system capacity needs and reliability in various states. Approximately $228 million (US$176 million) was invested in the MVPs from the date of acquisition of ITC and an additional $135 million (US$102 million) is expected to be spent in the remainder of 2017. Three of the MVPs are expected to be completed by the end of 2018, with the fourth scheduled for completion in 2023. In addition to the Corporation's base consolidated capital expenditure forecast, management is pursuing additional investment opportunities within existing service territories. Specifically, two significant electric transmission opportunities are being pursued. The Wataynikaneyap Power project in Northwestern Ontario, which involves construction of new transmission lines to connect remote First Nation communities to the electricity grid, and the Lake Erie Connector project at ITC, which would connect the Province of Ontario to the PJM electricity market. During the quarter noteworthy milestones were achieved with respect to the Lake Erie Connector project. In May ITC completed the major permit process in Pennsylvania upon receipt of two required permits from the Pennsylvania Department of Environmental Protection, and in June approval was received from Canada's Governor in Council and the Certificate of Public Convenience and Necessity was issued by the National Energy Board. Furthermore, the Corporation continues to pursue additional LNG infrastructure investment opportunities in British Columbia, including the potential pipeline expansion to the proposed Woodfibre LNG export facility and further expansion of the Tilbury LNG facility. Fortis and its utilities are focused on achieving key milestones in 2017 to further advance these opportunities. In May 2017 Fortis entered into an agreement with Teck Resources Limited ("Teck") to acquire a two-thirds ownership interest in the Waneta Dam and related transmission assets in British Columbia, for $1.2 billion. Closing of the transaction is subject to customary conditions, including receipt of certain approvals and consents. In addition, BC Hydro, which owns the remaining one-third ownership interest, has a right of first offer with respect to the sale by Teck. Providing BC Hydro does not exercise its right to purchase Teck's two-thirds interest in the dam, the transaction is expected to close in the fourth quarter of 2017. "At Fortis our portfolio of utilities is well diversified and provides numerous growth opportunities. We continue to make progress on our $13 billion five-year base capital plan with more than $3 billion to be spent throughout 2017," continued Mr. Perry. "This plan coupled with incremental opportunities for investment in our service territories, including our intention to purchase a stake in the Waneta Dam hydroelectric facility, provides high quality low risk growth for the Corporation." The Corporation's results for 2017 will continue to benefit from the acquisition of ITC and the impact of the rate case settlement at UNS Energy. Over the long term, Fortis is well positioned to enhance value for shareholders through the execution of its capital plan, the balance and strength of its diversified portfolio of utility businesses, as well as growth opportunities within its service territories. Over the five-year period through 2021, the Corporation's capital program is expected to be approximately $13 billion, increasing rate base to almost $30 billion in 2021. Fortis expects this long-term sustainable growth in rate base to support continuing growth in earnings and dividends. Fortis has targeted average annual dividend growth of approximately 6% through 2021. This dividend guidance takes into account many factors, including the expectation of reasonable outcomes for regulatory proceedings at the Corporation's utilities, the successful execution of the five-year capital expenditure program, and management's continued confidence in the strength of the Corporation's diversified portfolio of utilities and record of operational excellence. "As we look past 2017, we are seeing upside to our five-year base capital plan at our utility businesses. The opportunities we are identifying will enhance our ability to serve customers safely and reliably, grow our rate base, and support our 6% average annual dividend growth target while maintaining a conservative payout ratio," concluded Mr. Perry. For the three and six months ended June 30, 2017 The following Fortis Inc. ("Fortis" or the "Corporation") Management Discussion and Analysis ("MD&A") has been prepared in accordance with National Instrument 51-102 - Continuous Disclosure Obligations. The MD&A should be read in conjunction with the unaudited condensed consolidated interim financial statements and notes thereto for the three and six months ended June 30, 2017 and the MD&A and audited consolidated financial statements for the year ended December 31, 2016 included in the Corporation's 2016 Annual Report. Financial information contained in the MD&A has been prepared in accordance with accounting principles generally accepted in the United States of America ("US GAAP") and is presented in Canadian dollars unless otherwise specified. Fortis includes "forward-looking information" in the MD&A within the meaning of applicable Canadian securities laws and "forward-looking statements" within the meaning of the U.S. Private Securities Litigation Reform Act of 1995, collectively referred to as "forward-looking information". Forward-looking information included in the MD&A reflect expectations of Fortis management regarding future growth, results of operations, performance and business prospects and opportunities. Wherever possible, words such as "anticipates", "believes", "budgets", "could", "estimates", "expects", "forecasts", "intends", "may", "might", "plans", "projects", "schedule", "should", "target", "will", "would" and the negative of these terms and other similar terminology or expressions have been used to identify the forward-looking information, which include, without limitation: the expected timing of filing of regulatory applications and receipt and outcome of regulatory decisions; the nature, timing and expected costs of certain capital projects including, without limitation, expansions of the Tilbury liquefied natural gas ("LNG") facility and Multi-Value Projects, and additional opportunities including the pipeline expansion to the Woodfibre LNG site, the Lake Erie Connector Project and the Wataynikaneyap Project; the Corporation's forecast gross consolidated and segmented capital expenditures for 2017 and from 2017 to 2021; statements related to the acquisition of an interest in the Waneta Dam and related transmission assets, including the expected timing and benefits thereof, total expected consideration and adjustments, the expected financing of the acquisition and conditions precedent to the closing, including receipt of certain approvals and consents; the expectation that the Corporation's 2017 results will continue to benefit from the acquisition of ITC and the impact of Tucson Electric Power Company's general rate case; the Corporation's forecast rate base over the five-year period through 2021; the expectation that the Corporation's significant capital expenditure program will support continuing growth in earnings and dividends; target average annual dividend growth through 2021; the expectation that subsidiary operating expenses and interest costs will be paid out of subsidiary operating cash flows; the expectation that cash required to complete subsidiary capital expenditure programs will be sourced from a combination of borrowings under credit facilities, long-term debt offerings and equity injections from Fortis; the expectation that maintaining the targeted capital structure of the Corporation's regulated operating subsidiaries will not have an impact on its ability to pay dividends in the foreseeable future; the expectation that cash required of Fortis to support subsidiary capital expenditure programs and finance acquisitions will be derived from a combination of borrowings under the Corporation's committed corporate credit facility and proceeds from the issuance of common shares, preference shares and long-term debt and advances from minority investors; expected consolidated fixed-term debt maturities and repayments over the next five years; the expectation that the Corporation and its subsidiaries will remain compliant with debt covenants throughout 2017; the intent of management to refinance certain borrowings under Corporation's and subsidiaries' long-term committed credit facilities with long-term permanent financing; the expectation that long-term debt will not be settled prior to maturity; the expectation that the adoption of future accounting pronouncements will not have a material impact on the Corporation's consolidated financial statements; and the expectation that any liability from current legal proceedings and claims will not have a material adverse effect on the Corporation's consolidated financial position, results of operations or cash flows. Certain material factors or assumptions have been applied in drawing the conclusions contained in the forward-looking information, including, without limitation: the receipt of applicable regulatory approvals and requested rate orders, no material adverse regulatory decisions being received, and the expectation of regulatory stability; no material capital project and financing cost overrun related to any of the Corporation's capital projects; the realization of additional opportunities; the Board of Directors exercising its discretion to declare dividends, taking into account the business performance and financial conditions of the Corporation; no significant variability in interest rates; no significant operational disruptions or environmental liability due to a catastrophic event or environmental upset caused by severe weather, other acts of nature or other major events; the continued ability to maintain the electricity and gas systems to ensure their continued performance; no severe and prolonged downturn in economic conditions; no significant decline in capital spending; sufficient liquidity and capital resources; the continuation of regulator-approved mechanisms to flow through the cost of natural gas and energy supply costs in customer rates; the ability to hedge exposures to fluctuations in foreign exchange rates, natural gas prices and electricity prices; no significant changes in tax laws; no significant counterparty defaults; the continued competitiveness of natural gas pricing when compared with electricity and other alternative sources of energy; the continued availability of natural gas, fuel, coal and electricity supply; continuation and regulatory approval of power supply and capacity purchase contracts; the ability to fund defined benefit pension plans, earn the assumed long-term rates of return on the related assets and recover net pension costs in customer rates; no significant changes in government energy plans, environmental laws and regulations that may materially negatively affect the Corporation and its subsidiaries; maintenance of adequate insurance coverage; the ability to obtain and maintain licences and permits; retention of existing service areas; the continued tax deferred treatment of earnings from the Corporation's Caribbean operations; continued maintenance of information technology infrastructure and no material breach of cybersecurity; continued favourable relations with First Nations; favourable labour relations; that the Corporation can reasonably assess the merit of and potential liability attributable to ongoing legal proceedings; and sufficient human resources to deliver service and execute the capital program. Forward-looking information involves significant risks, uncertainties and assumptions. Fortis cautions readers that a number of factors could cause actual results, performance or achievements to differ materially from the results discussed or implied in the forward-looking information. These factors should be considered carefully and undue reliance should not be placed on the forward-looking information. Risk factors which could cause results or events to differ from current expectations are detailed under the heading "Business Risk Management" in this MD&A and in continuous disclosure materials filed from time to time with Canadian securities regulatory authorities and the Securities and Exchange Commission. Key risk factors for 2017 include, but are not limited to: uncertainty regarding the outcome of regulatory proceedings at the Corporation's utilities; uncertainty of the impact a continuation of a low interest rate environment may have on the allowed rate of return on common shareholders' equity at the Corporation's regulated utilities; the impact of fluctuations in foreign exchange rates; uncertainty related to proposed tax reform in the United States; risk associated with the impacts of less favourable economic conditions on the Corporation's results of operations; risk that the expected benefits of the acquisition of ITC may fail to materialize, or may not occur within the time periods anticipated; risk associated with the Corporation's ability to comply with Section 404(a) of the Sarbanes-Oxley Act of 2002 and the related rules of the U.S. Securities and Exchange Commission and the Public Company Accounting Oversight Board; risk associated with the completion of the Corporation's 2017 capital expenditures plan, including completion of major capital projects in the timelines anticipated and at the expected amounts; and uncertainty in the timing and access to capital markets to arrange sufficient and cost-effective financing to finance, among other things, capital expenditures and the repayment of maturing debt. All forward-looking information in the MD&A is qualified in its entirety by the above cautionary statements and, except as required by law, Fortis disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Fortis is a leader in the North American regulated electric and gas utility business, with total assets of approximately $48 billion and fiscal 2016 revenue of $6.8 billion. More than 8,000 employees of the Corporation serve utility customers in five Canadian provinces, nine U.S. states and three Caribbean countries. Year-to-date June 30, 2017, the Corporation's electricity systems met a combined peak demand of 31,671 megawatts ("MW") and its gas distribution systems met a peak day demand of 1,567 terajoules. For additional information on the Corporation's regulated operations and business segments, refer to Note 1 to the Corporation's unaudited condensed consolidated interim financial statements for the three and six months ended June 30, 2017 and to the "Corporate Overview" section of the 2016 Annual MD&A. Pending Acquisition of an Interest in Waneta Dam: In May 2017 Fortis entered into an agreement with Teck Resources Limited ("Teck") to acquire a two-thirds ownership interest in the Waneta Dam and related transmission assets in British Columbia for a purchase price of $1.2 billion (the "Waneta Acquisition"), subject to certain adjustments. The Waneta Acquisition will be funded by a combination of cash on hand, debt and equity. The Waneta Dam is a renewable energy facility that is currently operated and maintained by FortisBC Inc. Under the purchase agreement, Teck Metals Ltd. will be granted a 20-year lease, with an option to extend for a further 10 years, to use the two-thirds interest in the Waneta Dam to produce power for its industrial operations in Trail, British Columbia. BC Hydro, the owner of the remaining one-third ownership interest in the Waneta Dam, has a right of first offer. Closing of the Waneta Acquisition will also be subject to certain customary conditions, including receipt of certain approvals and consents from Canadian and U.S. governmental authorities. Provided BC Hydro does not exercise its right to purchase Teck's two-thirds interest in the Waneta Dam, the transaction is expected to close in the fourth quarter of 2017. Fortis has adopted a strategy of long-term profitable growth with the primary measure of financial performance being earnings per common share. Key financial highlights for the second quarter and year-to-date periods ended June 30, 2017 and 2016 are provided in the following table. The increase in revenue for the quarter was driven by the acquisition of ITC in October 2016, the impact of the rate case settlement and higher electricity sales at UNS Energy, the flow through in customer rates of higher overall energy supply costs, and favourable foreign exchange associated with the translation of US dollar-denominated revenue. Also contributing to the increase in revenue was the reversal of transmission refund accruals of $7 million ($4 million after tax), in the second quarter of 2017, due to the United States Federal Energy Regulatory Commission ("FERC") ending its investigation into the late-filed transmission service agreements at UNS Energy. The increase in revenue year to date was driven by the same factors discussed above for the quarter, as well as $18 million ($11 million after tax) in FERC ordered transmission refunds, recognized in the first quarter of 2016, associated with late-filed transmission service agreements at UNS Energy. The increase in energy supply costs for the quarter and year to date was mainly due to higher overall commodity costs. Unfavourable foreign exchange associated with the translation of US dollar-denominated energy supply costs also contributed to the increase for the quarter. The increase in operating expenses for the quarter and year to date was primarily due to the acquisition of ITC and general inflationary and employee-related cost increases. The increase was partially offset by acquisition-related transaction costs of $19 million ($15 million after tax) and $35 million ($29 million after tax) for the second quarter and year-to-date 2016, respectively, associated with the acquisition of ITC. Unfavourable foreign exchange associated with the translation of US dollar-denominated operating expenses also contributed to the increase for the quarter. The increase in depreciation and amortization for the quarter and year to date was primarily due to the acquisition of ITC and continued investment in energy infrastructure at the Corporation's other regulated utilities. The increase in other income, net of expenses, for the quarter and year to date was primarily due to the acquisition of ITC. The favourable settlement of matters at UNS Energy pertaining to FERC ordered transmission refunds of $11 million ($7 million after tax), in the first quarter of 2017, also contributed to the year-to-date increase. The increase in finance charges for the quarter and year to date was primarily due to the acquisition of ITC, including interest expense on debt issued to complete the financing of the acquisition. The increase was partially offset by acquisition-related transaction costs of $10 million ($7 million after tax) and $14 million ($10 million after tax) for the second quarter and year-to-date 2016, respectively, associated with the acquisition of ITC. The increase in income tax expense for the quarter and year to date was driven by the acquisition of ITC and higher earnings before taxes. ITC's higher federal and state jurisdictional tax rates increased the total effective tax rate of Fortis. Net Earnings Attributable to Common Equity Shareholders and Basic Earnings per Common Share The increase in net earnings attributable to common equity shareholders for the quarter was driven by earnings of $93 million at ITC, which was acquired in October 2016. The increase for the quarter was also due to: (i) strong performance at UNS Energy, largely due to the impact of the rate case settlement and higher electricity sales; (ii) lower Corporate and Other expenses, primarily due to $22 million in acquisition-related transaction costs associated with ITC recognized in the second quarter of 2016; (iii) higher earnings from Aitken Creek related to the unrealized gain on the mark-to-market of derivatives quarter over quarter; and (iv) favourable foreign exchange associated with the translation of US dollar-denominated earnings. The increase was partially offset by higher finance charges associated with the acquisition of ITC. The increase in net earnings attributable to common equity shareholders year to date was driven by earnings of $184 million at ITC. The year-to-date increase was also due to: (i) strong performance at UNS Energy, as discussed above for the quarter; (ii) the overall favourable impact of $22 million associated with FERC ordered refunds on late-filed transmission service agreements at UNS Energy; (iii) lower Corporate and Other expenses, primarily due to $39 million in acquisition-related transaction costs associated with ITC recognized year-to-date 2016; and (iv) higher earnings from Aitken Creek related to the unrealized gain on the mark-to-market of derivatives period over period and contribution from the first quarter of 2017. The increase was partially offset by: (i) higher finance charges associated with the acquisitions of ITC and Aitken Creek; (ii) lower contribution from FortisAlberta, mainly due to lower customer rates and higher operating expenses; and (iii) lower contribution from the Caribbean, mainly due to higher finance charges and lower equity income from Belize Electricity Limited ("Belize Electricity"). Earnings per common share for the quarter and year to date were $0.24 and $0.39 higher, respectively, compared to the same periods in 2016. The impact of the above-noted items on net earnings attributable to common equity shareholders were partially offset by an increase in the weighted average number of common shares outstanding associated with the financing of the acquisition of ITC and the Corporation's dividend reinvestment and share plans. Adjusted Net Earnings Attributable to Common Equity Shareholders and Adjusted Basic Earnings per Common Share Fortis supplements the use of US GAAP financial measures with non-US GAAP financial measures, including adjusted net earnings attributable to common equity shareholders and adjusted basic earnings per common share. The Corporation refers to these measures as non-US GAAP financial measures since they are not required by, or presented in accordance with, US GAAP. The most directly comparable US GAAP measures to adjusted net earnings attributable to common equity shareholders and adjusted basic earnings per common share are net earnings attributable to common equity shareholders and basic earnings per common share, respectively. The Corporation calculates adjusted net earnings attributable to common equity shareholders as net earnings attributable to common equity shareholders plus or minus items that management believes are not reflective of the underlying operations of the business. For the quarter and year-to-date periods ended June 30, 2017 and 2016, the Corporation adjusted net earnings attributable to common equity shareholders for: (i) acquisition-related transactions costs; and (ii) cumulative adjustments for regulatory decisions pertaining to prior periods considered to be outside the normal course of business for the periods presented. The Corporation no longer excludes mark-to-market adjustments related to derivative instruments at Aitken Creek, which occur in the normal course of Aitken Creek's business, in its calculation of adjusted net earnings attributable to common equity shareholders as comparative information is now presented in reported net earnings. The adjusting items described above do not have a standardized meaning as prescribed under US GAAP and are not considered US GAAP measures. Therefore, these adjusting items may not be comparable with similar adjustments presented by other companies. The Corporation calculates adjusted basic earnings per common share by dividing adjusted net earnings attributable to common equity shareholders by the weighted average number of common shares outstanding. The following table provides a reconciliation of the non-US GAAP financial measures and each of the adjusting items are discussed in the segmented results of operations for the respective reporting segments. The following is a discussion of the financial results of the Corporation's reporting segments. A discussion of the material regulatory decisions and applications pertaining to the Corporation's regulated utilities is provided in the "Regulatory Highlights" section of this MD&A. ITC was acquired by Fortis in October 2016 and, therefore, there are no revenue and earnings reported for the comparative periods. There were no transactions or events, outside the normal course of operations, that materially impacted revenue or earnings for the quarter and year to date. The increase in electricity sales for the quarter was primarily due to higher residential and commercial retail electricity sales due to warmer temperatures that increased air conditioning load. The increase was partially offset by lower short-term wholesale sales due to unplanned generation outages and lower long-term wholesale sales due to the expiration of a large contract as compared to the same period in 2016. The majority of short-term wholesale sales is flowed through to customers and has no impact on earnings. The increase in electricity sales year to date was primarily due to the same factors discussed above for the quarter and higher short-term wholesale sales in the first quarter of 2017 as a result of more favourable commodity prices. Gas volumes were comparable with the same periods in 2016. The increase in revenue for the quarter was primarily due to the impact of the rate settlement effective February 27, 2017, higher retail electricity sales, as discussed above, and approximately $22 million of favourable foreign exchange associated with the translation of US dollar-denominated revenue. Also contributing to the increase was the reversal of $7 million (US$5 million), or $4 million (US$3 million) after-tax, in transmission refund accruals due to FERC ending its investigation into TEP's late-filed transmission agreements in the second quarter of 2017. The increase was partially offset by lower revenue related to a decrease in cost recovery rates, which has no impact on earnings. The increase in revenue year to date was due to the same factors discussed above for the quarter, as well as approximately $18 million (US$13 million), or $11 million (US$8 million) after tax, in FERC ordered transmission refunds in the first quarter of 2016 and higher short-term wholesale sales. Also contributing to the increase year to date was approximately $5 million of favourable foreign exchange associated with the translation of US dollar-denominated revenue. The increase in earnings for the quarter was primarily due to the impact of the rate case settlement, higher retail electricity sales, and the reversal of $4 million (US$3 million) in transmission refund accruals, all discussed above. Also contributing to the increase was more favourably priced long-term wholesale contracts and approximately $2 million of favourable foreign exchange associated with the translation of US dollar-denominated earnings, partially offset by higher deferred income taxes. The increase in earnings year to date was due to the same factors discussed above for the quarter, as well as approximately $11 million (US$8 million) in FERC ordered transmission refunds in the first quarter of 2016 and approximately $7 million (US$5 million) related to the favourable settlement of matters pertaining to FERC ordered transmission refunds in the first quarter of 2017. Also contributing to the increase was approximately $1 million of favourable foreign exchange associated with the translation of US dollar-denominated earnings. The decrease in electricity sales for the quarter and year to date was primarily due to lower average consumption in the second quarter of 2017 as a result of cooler temperatures. Also contributing to the year-to-date decrease was lower average consumption in the first quarter of 2017, as a result of warmer temperatures. Gas volumes were comparable with the same periods in 2016. Changes in electricity sales and gas volumes at Central Hudson are subject to regulatory revenue decoupling mechanisms and, as a result, do not have a material impact on annual revenue and earnings. The increase in revenue for the quarter and year to date was due to higher delivery revenue from increases in base electricity rates effective July 1, 2016 and the recovery from customers of higher commodity costs. Also contributing to the increase for the quarter was favourable foreign exchange of approximately $8 million associated with the translation of US dollar-denominated revenue. The decrease in earnings for the quarter and year to date was primarily due to the timing of unbilled revenue, which is not subject to the operation of the decoupling mechanism. Also contributing to the decrease was higher operating costs, partially offset by increases in delivery revenue. Higher-than-expected storm restoration costs incurred in the first quarter of 2017 also contributed to the decrease year to date. The increase in gas volumes for the quarter and year to date was primarily due to growth in the number of customers and higher average consumption by residential and commercial customers as a result of colder temperatures. Also contributing to the increase was higher volumes for transportation customers due to additional customers switching to natural gas compared to alternative fuel sources. The increase in revenue for the quarter and year to date was primarily due to higher gas volumes and a higher commodity cost of natural gas charged to customers, partially offset by an increase in flow-through adjustments owing to customers. The decrease in earnings for the quarter was primarily due to the timing of quarterly revenue and operating expenses compared to the same period in 2016 and higher operating expenses, partially offset by higher allowance for funds used during construction ("AFUDC"). The increase in earnings year to date was primarily due to higher AFUDC and the timing of quarterly revenue and operating expenses as compared to the same period in 2016, partially offset by higher operating expenses. FortisBC Energy earns approximately the same margin regardless of whether a customer contracts for the purchase and delivery of natural gas or only for the delivery of natural gas. As a result of the operation of regulatory deferral mechanisms, changes in consumption levels and the cost of natural gas do not materially affect earnings. The increase in energy deliveries for the quarter and year to date was primarily due to higher average consumption by oil and gas customers in the second quarter of 2017 and growth in the number of residential and commercial customers. The increase year to date was partially offset by lower oil and gas activity in the first quarter of 2017. The increase in revenue for the quarter and year to date was primarily due to an increase in capital tracker revenue. Higher revenue related to the flow through of costs to customers and higher energy deliveries, due to customer growth and higher average consumption, also contributed to the increase, partially offset by a decrease in customer rates effective January 1, 2017 based on a combined inflation and productivity factor of negative 1.9%. The increase in earnings for the quarter was primarily due to an increase in capital tracker revenue and customer growth, partially offset by higher operating costs, mainly due to timing, and lower customer rates, as discussed above. The decrease in earnings year to date was mainly due to higher operating expenses and timing differences related to certain operating expenses. Lower customer rates, partially offset by an increase in capital tracker revenue and customer growth, also contributed to the decrease year to date. The increase in electricity sales for the quarter and year to date was primarily due to higher average consumption as a result of favourable weather conditions. The increase in revenue for the quarter and year to date was primarily due to higher electricity sales and an increase in base electricity rates effective January 1, 2017, partially offset by higher flow-through adjustments owing to customers. The increase in earnings for the quarter and year to date was due to lower operating expenses. Variances from regulated forecasts used to set rates for electricity revenue and power purchase costs are flowed back to customers in future rates through approved regulatory deferral mechanisms and, therefore, these variances do not have an impact on earnings. The increase in electricity sales for the quarter and year to date was due to higher average consumption and growth in the number of customers. The increase in revenue for the quarter and year to date was primarily due to higher electricity sales and an increase in customer electricity rates. The increase in earnings for the quarter and year to date was due to lower-than-anticipated finance costs, an increase in customer electricity rates, and higher electricity sales. The recognition of the cumulative impact of a decrease in the allowed return on equity ("ROE") at Newfoundland Power, effective January 1, 2016, in the second quarter of 2016 also had a favourable impact on earnings quarter over quarter. Electricity sales for the quarter and year to date were comparable with the same periods in 2016. The increase in revenue for the quarter and year to date was mainly due to the flow through in customer electricity rates of higher fuel costs. Also contributing to the increase for the quarter is approximately $3 million of favourable foreign exchange associated with the translation of US dollar-denominated revenue. The decrease in earnings for the quarter and year to date was due to higher finance costs, primarily due to lower capitalized interest, partially offset by lower operating costs. Also contributing to the decrease year to date was lower equity income from Belize Electricity. Energy sales for the quarter and year to date were comparable with the same periods in 2016. The decrease in revenue for the quarter was primarily due to Aitken Creek. The increase in revenue year to date was driven by the acquisition of Aitken Creek in April 2016. The increase in earnings for the quarter and year to date was primarily due to higher earnings from Aitken Creek associated with the unrealized gains on the mark-to-market of derivatives period over period. Earnings from Aitken Creek in the first quarter of 2017 also contributed to the year-to-date increase. The decrease in Corporate and Other for the quarter and year to date was primarily due to lower operating expenses, a higher income tax recovery and lower preference share dividends, partially offset by an increase in finance charges. The decrease in operating expenses for the quarter and year to date was primarily due to acquisition-related transaction costs, including investment banking, legal, consulting and other fees, associated with the acquisition of ITC totalling approximately $19 million ($15 million after tax) and $35 million ($29 million after tax) for the second quarter and year-to-date 2016, respectively. The decrease was partially offset by higher compensation-related expenditures, general inflationary increases and ancillary expenses to support the acquisition of ITC and the Corporation's listing on the New York Stock Exchange. The increase in finance charges for the quarter and year to date was mainly due to the acquisition of ITC in October 2016, partially offset by fees associated with the Corporation's acquisition credit facilities totalling approximately $10 million ($7 million after tax) and $14 million ($10 million after tax) for the second quarter and year-to-date 2016, respectively. Finance charges associated with the acquisition of Aitken Creek in April 2016 also contributed to the year-to-date increase. The higher income tax recovery for the quarter and year to date was mainly due to the increase in finance charges, partially offset by lower acquisition-related transaction costs. The decrease in preference share dividends for the quarter and year to date was due to the redemption of First Preference Shares, Series E in September 2016. The nature of regulation associated with each of the Corporation's regulated electric and gas utilities is generally consistent with that disclosed in the 2016 Annual MD&A. The following summarizes the significant ongoing regulatory proceedings and significant decisions and applications for the Corporation's regulated utilities in the first half of 2017. Since 2013 two third-party complaints were filed with FERC requesting that FERC find the Midcontinent Independent System Operator ("MISO") regional base ROE for all MISO transmission owners, including some of ITC's operating subsidiaries, for the periods November 2013 through February 2015 (the "Initial Refund Period" or "Initial Complaint") and February 2015 through May 2016 (the "Second Refund Period" or "Second Complaint") to no longer be just and reasonable. In September 2016 FERC issued an order affirming the presiding Administrative Law Judge's ("ALJ") initial decision for the Initial Refund Period and setting the base ROE for the Initial Refund Period at 10.32%, with a maximum ROE of 11.35%. Additionally, the rates established by the September 2016 order will be used prospectively from the date of the order until a new approved rate is established for the Second Refund Period. FERC's September 2016 order regarding the Initial Complaint is currently under appeal by the MISO transmission owners. In June 2016 the presiding ALJ issued an initial decision for the Second Refund Period, which recommended a base ROE of 9.70%, with a maximum ROE of 10.68%, which is a recommendation to FERC. The total estimated refund for the Initial Complaint was $158 million (US$118 million), including interest, as at December 31, 2016. The true-up of the net refund was substantially finalized in the second quarter of 2017 and paid during the first half of 2017. The total amount of the refund, including interest and the associated true-up, for the Initial Complaint was not materially different from the amount recorded as at December 31, 2016. An order has not yet been issued by FERC in connection with the Second Complaint; however, it is expected that FERC will establish a new base ROE and range of reasonableness to calculate the refund liability for the Second Refund Period and future ROEs for ITC's operating subsidiaries. As at June 30, 2017, the estimated range of refunds for the Second Refund Period was between US$104 million to US$142 million and ITC has recognized an aggregated estimated regulatory liability of $184 million (US$142 million). The estimated regulatory liabilities were accrued by ITC before its acquisition by Fortis. There is uncertainty regarding the final outcome of the Initial and Second Complaints and the timing of the completion of these matters. This is due, in part, to a recent court decision requiring FERC to further justify the methodology used to establish new ROEs. It is possible that the outcome of these matters could differ materially from the estimated range of refunds. In February 2017 the Arizona Corporation Commission issued a rate order for new rates that took effect February 27, 2017 ("2017 Rate Order"). Provisions of the 2017 Rate Order include: (i) an increase in non-fuel base revenue of $108 million (US$81.5 million), including $20 million (US$15 million) of operating costs related to the 50.5% undivided interest in Unit 1 of Springerville Generating Station purchased by TEP in September 2016; (ii) a 7.04% return on original cost rate base, including a cost of equity of 9.75% and an embedded cost of long-term debt of 4.32%; (iii) a common equity component of capital structure of approximately 50%; and (iv) the adoption of proposed depreciation rates which reflect a reduction in the depreciable life for Unit 1 of San Juan Generating Station. Certain aspects of the general rate application, including net metering and rate design for new distributed generation customers, have been deferred to a second phase of TEP's rate case proceeding, which is currently expected to be completed in the first quarter of 2018. TEP cannot predict the outcome of this proceeding. In May 2017 FERC informed TEP that no further enforcement actions were necessary regarding TEP's transmission refunds and closed the related investigation. As a result, TEP reversed the remaining $7 million (US$5 million) provision related to potential time-value refunds. In July 2017 Central Hudson will file a rate case with the New York Public Service Commission ("PSC") requesting an increase in electric and nature gas rates. Included in the rate case will be a request to increase the allowed ROE to 9.5% from 9.0% and the equity component of the capital structure to 50% from 48%. An order from the PSC is expected in June 2018 with the new rates to become effective no later than July 1, 2018. In January 2017 the Alberta Utilities Commission ("AUC") issued its decision on FortisAlberta's 2015 True-Up Application approving the 2015 capital tracker revenue as filed, pending the approval of the Company's Compliance Filing, filed in February 2017. The AUC approved the Compliance Filing in May 2017. In June 2017 the Company filed its 2016 True-Up Application for 2016 capital tracker revenue and a decision is expected in the first quarter of 2018. There was no material adjustment to capital tracker revenue resulting from this application. In July 2017 the AUC established a process to determine an ROE and capital structure for 2018, 2019 and 2020. The process will commence in October 2017, with an oral hearing in March 2018. A decision is expected in the third quarter of 2018. In December 2016 the AUC issued its decision outlining the manner in which distribution rates will be determined during the second performance-based rate-setting ("PBR") term, being the five-year period from 2018 through 2022. FortisAlberta filed a rebasing application in April 2017 to establish the going-in revenue requirement for the second PBR term, which will be used to determine the going-in rates upon which the PBR formula will be applied to establish distribution rates for 2018. A decision on this application is expected in the first quarter of 2018. The following table summarizes significant ongoing regulatory proceedings, including filing dates and expected timing of decisions for the Corporation's utilities. The following table outlines the significant changes in the consolidated balance sheets between June 30, 2017 and December 31, 2016. The table below outlines the Corporation's sources and uses of cash for the second quarter and year-to-date periods ended June 30, 2017 compared to the same periods in 2016, followed by a discussion of the nature of the variances in cash flows. Operating Activities: Cash flow provided by operating activities was $201 million higher quarter over quarter and $259 million higher year to date compared to the same period in 2016. The increase was primarily due to higher cash earnings, driven by ITC and UNS Energy. The year-to-date increase was partially offset by timing differences in working capital, mainly due to the payment of the Initial Refund Period ROE complaint at ITC in the first quarter of 2017. Investing Activities: Cash used in investing activities was $21 million lower quarter over quarter. The decrease was primarily due to the acquisition of Aitken Creek in the second quarter of 2016 for a net cash purchase price of $318 million, largely offset by an increase in capital expenditures. The increase in capital expenditures was driven by capital spending at ITC along with higher capital spending at most of the Corporation's regulated utilities. Cash used in investing activities was $285 million higher year to date compared to the same period in 2016. The increase was primarily due to an increase in capital expenditures, partially offset by the acquisition of Aitken Creek, as discussed above for the quarter. Financing Activities: Cash provided by financing activities was $353 million lower quarter over quarter. The decrease was primarily due to higher net repayments under committed credit facilities, partially offset by lower net repayments of short-term borrowings at FortisBC Energy. Cash provided by financing activities was $79 million lower year to date compared to the same period in 2016. The decrease was primarily due to higher net repayments under both committed credit facilities and short-term borrowings. The decrease was partially offset by higher proceeds from the issuance of long-term debt, largely at ITC. In the first quarter of 2017 approximately 12.2 million common shares of Fortis were issued to an institutional investor for proceeds of $500 million. The proceeds were used to repay short-term borrowings. Proceeds from long-term debt, net of issue costs, repayments of long-term debt and capital lease and finance obligations, and net (repayments) borrowings under committed credit facilities for the quarter and year to date compared to the same periods last year are summarized in the following tables. Borrowings under credit facilities by the utilities are primarily in support of their respective capital expenditure programs and/or for working capital requirements. Repayments are primarily financed through the issuance of long-term debt, cash from operations and/or equity injections from Fortis. From time to time, proceeds from preference share, common share and long-term debt offerings are used to repay borrowings under the Corporation's committed credit facility. Common share dividends paid in the second quarter of 2017 were $104 million, net of $63 million of dividends reinvested, compared to $70 million, net of $36 million of dividends reinvested, paid in the second quarter of 2016. Common share dividends paid year-to-date 2017 were $202 million, net of $125 million of dividends reinvested, compared to $147 million, net of $65 million of dividends reinvested, paid year-to-date 2016. The dividend paid per common share for each of the first and second quarters of 2017 was $0.40 compared to $0.375 for each of the first and second quarters of 2016. The weighted average number of common shares outstanding for the second quarter and year-to-date 2017 was 416.8 million and 411.5 million, respectively, compared to 283.7 million and 283.0 million for the same periods in 2016. There were no material changes in the nature and amount of the Corporation's contractual obligations during the three and six months ended June 30, 2017 from those disclosed in the 2016 Annual MD&A. The Corporation's principal businesses of regulated electric and gas utilities require ongoing access to capital to enable the utilities to fund maintenance and expansion of infrastructure. Fortis raises debt at the subsidiary level to ensure regulatory transparency, tax efficiency and financing flexibility. Fortis generally finances a significant portion of acquisitions at the corporate level with proceeds from common share, preference share and long-term debt offerings, and advances from minority investors. To help ensure access to capital, the Corporation targets a consolidated long-term capital structure that will enable it to maintain investment-grade credit ratings. Each of the Corporation's regulated utilities maintains its own capital structure in line with the deemed capital structure reflected in their customer rates. The consolidated capital structure of Fortis is presented in the following table. Including amounts related to non-controlling interests, the Corporation's capital structure as at June 30, 2017 was 56.1% total debt and capital lease and finance obligations (net of cash), 4.2% preference shares, 35.0% common shareholders' equity and 4.7% non-controlling interests (December 31, 2016 - 57.8% total debt and capital lease and finance obligations (net of cash), 4.2% preference shares, 33.3% common shareholders' equity and 4.7% non-controlling interests). The change in the Corporation's capital structure was mainly due to an increase in common equity at the Corporation due to the issuance of $500 million of common shares in March 2017, used to repay short-term borrowings. The Corporation's credit ratings are as follows. The above-noted credit ratings reflect the Corporation's low business-risk profile and diversity of its operations, the stand-alone nature and financial separation of each of the regulated subsidiaries of Fortis, and the level of debt at the holding company. In May 2017 S&P and DBRS affirmed the Corporation's long-term corporate and unsecured debt credit ratings as presented above. A breakdown of the $1,428 million in gross consolidated capital expenditures by segment year-to-date 2017 is provided in the following table. Planned capital expenditures are based on detailed forecasts of energy demand, weather, cost of labour and materials, as well as other factors, including economic conditions, which could change and cause actual expenditures to differ from those forecast. Gross consolidated capital expenditures for 2017 are forecast to be approximately $3.1 billion. There have been no material changes in the overall expected level, nature and timing of the Corporation's significant capital projects from those that were disclosed in the 2016 Annual MD&A, with the exception of those noted below for UNS Energy and FortisBC Energy. Capital expenditures at UNS Energy are expected to be higher than the original forecast, primarily due to capital spending related to investment in natural gas-fired facilities and distribution modernization projects. At FortisBC Energy capital expenditures are expected to be higher than the original forecast, primarily due to advancing the capital spend for the Lower Mainland System Upgrade to 2017 from 2018. At ITC approximately $228 million (US$176 million) was invested in the Multi-Value Projects ("MVPs") from the date of acquisition and an additional $135 million (US$102 million) is expected to be spent in the second half of 2017. The MVPs consist of four regional electric transmission projects that have been identified by MISO to address system capacity needs and reliability in various states. The Tilbury liquefied natural gas ("LNG") facility expansion ("Tilbury LNG Facility Expansion") by FortisBC Energy in British Columbia is nearing completion. Approximately $439 million, including AFUDC and development costs, has been invested to the end of the second quarter of 2017. The total cost of the project scope that is currently under construction is estimated at approximately $470 million, including approximately $70 million of AFUDC and development costs, which could be impacted depending on the date the project is considered in service for rate-making purposes. The facility includes a second LNG tank and a new liquefier, both expected to be in service in the third quarter of 2017. Key activities during the first half of 2017 included commissioning of the LNG storage tank and the continued installation of the liquefaction process area piping insulation, electrical and instrumentation cable and terminations. Beginning with the first Order in Council ("OIC") in 2013, the Government of British Columbia has continued to support the Tilbury LNG Facility Expansion. The most recent OIC issued in March 2017 further facilitates the expansion of the facility by increasing the capital cost limit to $425 million from $400 million, before AFUDC and development costs. This latest OIC also provides greater discretion around when certain projects approved pursuant to previous OICs, including the Tilbury LNG Facility Expansion, could be added to rate base. Over the five-year period 2017 through 2021, gross consolidated capital expenditures are expected to be approximately $13 billion. The breakdown of the capital spending has not changed materially from that disclosed in the 2016 Annual MD&A. In addition to the Corporation's base consolidated capital expenditure forecast, management is pursuing additional investment opportunities within existing service territories. These additional investment opportunities, as discussed below, are not included in the Corporation's base capital expenditure forecast. The Corporation continues to pursue additional LNG infrastructure investment opportunities in British Columbia, including a pipeline expansion to the proposed Woodfibre LNG site and a further expansion of Tilbury. FortisBC Energy's potential pipeline expansion is conditional on Woodfibre LNG proceeding with its LNG export facility. FortisBC Energy received an OIC from the Government of British Columbia effectively exempting this project from further regulatory approval by the British Columbia Utilities Commission. Woodfibre LNG has obtained an export license from the National Energy Board ("NEB"), which was recently extended from 25 to 40 years, and received environmental assessment approvals from the Squamish First Nation, the British Columbia Environmental Assessment Office, and the Canadian Environmental Assessment Agency. FortisBC Energy also received environmental assessment approval from the Squamish First Nation and provincial environmental assessment approval in 2016. The potential pipeline expansion was initially estimated at a total project cost, before any customer contribution, of up to $600 million; however, this estimate will be updated for final scoping, detailed construction estimates and scheduling. In November 2016 Woodfibre LNG announced the approval from its parent company, Pacific Oil & Gas Limited, which is part of the Singapore-based RGE group of companies, of the funds necessary to complete the project. This project may move forward pending additional approvals and a final investment decision by Woodfibre LNG but is not expected to be in service any earlier than 2020. The Corporation's Tilbury LNG facility is uniquely positioned to meet customer demand for clean-burning natural gas. The site is scalable and can accommodate additional storage and liquefaction equipment, and is relatively close to international shipping lanes. Fortis continues to have discussions with a number of potential export customers. In January 2017 ITC received approval of a Presidential Permit from the U.S. Department of Energy for the Lake Erie Connector transmission line, which is a required approval for international border-crossing projects. Also in January, ITC received a report from Canada's NEB recommending the issuance of a Certificate of Public Convenience and Necessity ("CPCN") with prescribed conditions for the transmission line. In May 2017 ITC completed the major permit process in Pennsylvania upon receipt of two required permits from the Pennsylvania Department of Environmental Protection. In June 2017 ITC received approval from Canada's Governor in Council and the CPCN was issued by the NEB. The Lake Erie Connector project is a proposed 1,000 MW, bi-directional, high-voltage direct current underwater transmission line that would provide the first direct link between the markets of the Ontario Independent Electricity System Operator and PJM Interconnection, LLC. The project would enable transmission customers to more efficiently access energy, capacity and renewable energy credit opportunities in both markets. The project continues to advance through regulatory, operational, and economic milestones. Remaining key milestones include: receiving approval from the U.S. Army Corps of Engineers of a joint application, of which approval by the Pennsylvania Department of Environmental Protection was received in May 2017; completing project cost refinements; and securing favourable transmission service agreements with prospective counterparties. Pending achievement of key milestones, the expected in-service date for the project is late 2020. The Wataynikaneyap Power Project continues to advance in Ontario. Wataynikaneyap Power consists of a partnership between 22 First Nations and FortisOntario, with a mandate to develop new transmission lines to connect remote First Nations communities to the electricity grid in Ontario. In 2016 the Government of Ontario designated Wataynikaneyap Power as the licensed transmission company to complete this project. FortisOntario reached an agreement with Renewable Energy Systems Canada in December 2016 to acquire its ownership interest in the Wataynikaneyap Partnership. The transaction was approved by the Ontario Energy Board ("OEB") and closed in March 2017. As a result, FortisOntario's ownership interest in the Wataynikaneyap Partnership has increased to 49%, with the remaining 51% ownership interest held by the 22 First Nations communities. The total estimated capital cost for the project, subject to final cost estimation, is approximately $1.35 billion and is expected to contribute to significant savings for the First Nations communities and result in a significant reduction in greenhouse gas emissions. In March 2017 the project reached a significant milestone with the approval by the OEB of a deferral account to recognize development costs incurred between November 2010 and the commencement of construction. In addition to environmental assessments underway, other regulatory approvals are currently being sought and the next regulatory milestone will be the preparation and filing of the leave to construct with the OEB, which is expected in the fourth quarter of 2017. Construction will commence pending the receipt of permits, approvals and a cost-sharing agreement between the federal and provincial government. The Corporation also has other significant opportunities that have not yet been included in the Corporation's capital expenditure forecast including, but not limited to: transmission investment opportunities at ITC; investment opportunities for CH Energy in New York Transco, LLC to address electric transmission constraints in New York State; renewable energy investments, energy storage projects and transmission investments at UNS Energy; and further gas infrastructure opportunities at FortisBC Energy. At the subsidiary level, it is expected that operating expenses and interest costs will generally be paid out of subsidiary operating cash flows, with varying levels of residual cash flows available for subsidiary capital expenditures and/or dividend payments to Fortis. Borrowings under credit facilities may be required from time to time to support seasonal working capital requirements. Cash required to complete subsidiary capital expenditure programs is also expected to be financed from a combination of borrowings under credit facilities, long-term debt offerings and equity injections from Fortis. The Corporation's ability to service its debt obligations and pay dividends on its common and preference shares is dependent on the financial results of the operating subsidiaries and the related cash payments from these subsidiaries. Certain regulated subsidiaries may be subject to restrictions that may limit their ability to distribute cash to Fortis. These include restrictions by certain regulators limiting the amount of annual dividends and restrictions by certain lenders limiting the amount of debt to total capitalization at the subsidiaries. In addition, there are practical limitations on using the net assets of each of the Corporation's regulated operating subsidiaries to pay dividends based on management's intent to maintain the regulator-approved capital structures for each of its regulated operating subsidiaries. The Corporation does not expect that maintaining the targeted capital structures of its regulated operating subsidiaries will have an impact on its ability to pay dividends in the foreseeable future. Cash required of Fortis to support subsidiary capital expenditure programs and finance acquisitions is expected to be derived from a combination of borrowings under the Corporation's committed corporate credit facility and proceeds from the issuance of common shares, preference shares and long-term debt, and advances from minority investors. Depending on the timing of cash payments from the subsidiaries, borrowings under the Corporation's committed corporate credit facility may be required from time to time to support the servicing of debt and payment of dividends. In November 2016 Fortis filed a short-form base shelf prospectus, under which the Corporation may issue common or preference shares, subscription receipts or debt securities in an aggregate principal amount of up to $5 billion during the 25-month life of the base shelf prospectus. In July 2017 Fortis exchanged its US$2.0 billion ($2.6 billion) unregistered senior unsecured notes for US$2.0 billion ($2.6 billion) registered senior unsecured notes under the base shelf prospectus. In March 2017 Fortis issued $500 million common equity and in December 2016 issued $500 million unsecured notes at 2.85%, both under the base shelf prospectus. A principal amount of approximately $1.5 billion remains under the base shelf prospectus. As at June 30, 2017, management expects consolidated fixed-term debt maturities and repayments to average approximately $730 million annually over the next five years. The combination of available credit facilities and manageable annual debt maturities and repayments provides the Corporation and its subsidiaries with flexibility in the timing of access to capital markets. Fortis and its subsidiaries were in compliance with debt covenants as at June 30, 2017 and are expected to remain compliant throughout 2017. As at June 30, 2017, the Corporation and its subsidiaries had consolidated credit facilities of approximately $5.4 billion, of which approximately $4.0 billion was unused, including $940 million unused under the Corporation's committed revolving corporate credit facility. The credit facilities are syndicated mostly with large banks in Canada and the United States, with no one bank holding more than 20% of these facilities. Approximately $5.0 billion of the total credit facilities are committed facilities with maturities ranging from 2017 through 2022. The following summary outlines the credit facilities of the Corporation and its subsidiaries. As at June 30, 2017 and December 31, 2016, certain borrowings under the Corporation's and subsidiaries' long-term committed credit facilities were classified as long-term debt. It is management's intention to refinance these borrowings with long-term permanent financing during future periods. There were no material changes in credit facilities from that disclosed in the Corporation's 2016 Annual MD&A, except that, in March 2017, the Corporation repaid short-term borrowings using net proceeds from the issuance of common shares. With the exception of letters of credit outstanding of $124 million as at June 30, 2017 (December 31, 2016 - $119 million), the Corporation had no off-balance sheet arrangements that are reasonably likely to materially affect liquidity or the availability of, or requirements for, capital resources. Year-to-date 2017, the business risks of the Corporation were generally consistent with those disclosed in the Corporation's 2016 Annual MD&A, including certain risks, as disclosed below, and an update to those risks, where applicable. Regulatory Risk: For further information, refer to the "Regulatory Highlights" section of this MD&A. Capital Resources and Liquidity Risk - Credit Ratings: In April 2017 S&P upgraded TEP's unsecured debt rating to 'A-' from 'BBB+' with a stable outlook. For a discussion on the Corporation's credit ratings refer to the "Liquidity and Capital Resources" section of this MD&A. Defined Benefit Pension and Other Post-Employment Benefit Plan Assets: As at June 30, 2017, the fair value of the Corporation's consolidated defined benefit pension and other post-employment benefit plan assets was $3,032 million compared to $2,898 million as at December 31, 2016. The condensed consolidated interim financial statements have been prepared following the same accounting policies and methods as those used to prepare the Corporation's 2016 annual audited consolidated financial statements, except as described below. Effective January 1, 2017, the Corporation adopted Accounting Standards Update ("ASU") No. 2017-04, Simplifying the Test for Goodwill Impairment. The amendments in this update simplify the subsequent measurement of goodwill by eliminating step two in the current two-step goodwill impairment test. An entity will apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit's carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit. The new guidance does not amend the optional qualitative assessment of goodwill impairment. The above-noted ASU was applied prospectively and did not impact the Corporation's unaudited condensed consolidated interim financial statements for the three and six months ended June 30, 2017. The Corporation considers the applicability and impact of all ASUs issued by the Financial Accounting Standards Board ("FASB"). The following updates have been issued by FASB, but have not yet been adopted by Fortis. Any ASUs not included below were assessed and determined to be either not applicable to the Corporation or are not expected to have a material impact on the consolidated financial statements. ASU No. 2014-09 was issued in May 2014 and the amendments in this update create Accounting Standards Codification ("ASC") Topic 606, Revenue from Contracts with Customers, and supersede the revenue recognition requirements in ASC Topic 605, Revenue Recognition, including most industry-specific revenue recognition guidance throughout the codification. This standard clarifies the principles for recognizing revenue and can be applied consistently across various transactions, industries and capital markets. In 2016 a number of additional ASUs were issued that clarify implementation guidance in ASC Topic 606. This standard, and all related ASUs, is effective for annual and interim periods beginning after December 15, 2017. Early adoption is permitted for annual and interim periods beginning after December 15, 2016. The Corporation has elected not to early adopt. The new guidance permits two methods of adoption: (i) the full retrospective method, under which comparative periods would be restated, and the cumulative impact of applying the standard would be recognized as at January 1, 2017, the earliest period presented; and (ii) the modified retrospective method, under which comparative periods would not be restated and the cumulative impact of applying the standard would be recognized at the date of initial adoption, January 1, 2018. The Corporation expects to use the modified retrospective approach; however, it continues to monitor interpretative issues that remain outstanding. Any significant developments in interpretative issues could change the Corporation's expected method of adoption. More than 80% of the Corporation's revenue is generated from energy sales to retail and wholesale customers based on published tariff rates, as approved by the respective regulators, and is considered to be in the scope of ASU No. 2014-09. Fortis has assessed retail and wholesale tariff revenue and expects that the adoption of this standard will not change the Corporation's accounting policy for recognizing retail and wholesale tariff revenue and, therefore, will not have an impact on earnings. Fortis continues to assess whether this standard will have an impact on its remaining revenue streams. The Corporation has not disclosed the expected impact of the adoption of this standard on its consolidated financial statements as it is not expected to be material. However, certain specific interpretative issues remain outstanding and the conclusions reached, if different than currently anticipated, could have a material impact on the Corporation's consolidated financial statements and related disclosures. Fortis continues to closely monitor developments related to the new standard. The adoption of this standard will impact the Corporation's revenue disclosures as revenue from contracts with customers is required to be reported separately from alternative revenue, which is outside the scope of ASC Topic 606. Fortis is in the process of drafting these required disclosures. As part of its effort to adopt the new revenue recognition standard, Fortis is monitoring its adoption process under its existing internal controls over financial reporting ("ICFR"), including accounting processes and the gathering and evaluation of information used in assessing the required disclosures. As the implementation process continues, Fortis will assess any necessary changes to ICFR. Recognition and Measurement of Financial Assets and Financial Liabilities ASU No. 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities, was issued in January 2016 and the amendments in this update address certain aspects of recognition, measurement, presentation and disclosure of financial instruments. Most notably, the amendments require the following: (i) equity investments in unconsolidated entities (other than those accounted for using the equity method of accounting) to be measured at fair value through earnings; however, entities will be able to elect to record equity investments without readily determinable fair values at cost, less impairment, and plus or minus subsequent adjustments for observable price changes; and (ii) financial assets and financial liabilities to be presented separately in the notes to the consolidated financial statements, grouped by measurement category and form of financial asset. This update is effective for annual and interim periods beginning after December 15, 2017. Fortis is assessing the impact that the adoption of this update will have on its consolidated financial statements and related disclosures. ASU No. 2016-02 was issued in February 2016 and the amendments in this update create ASC Topic 842, Leases, and supersede lease requirements in ASC Topic 840, Leases. The main provision of ASC Topic 842 is the recognition of lease assets and lease liabilities on the balance sheet by lessees for those leases that were previously classified as operating leases. For operating leases, a lessee is required to do the following: (i) recognize a right-of-use asset and a lease liability, initially measured at the present value of the lease payments, on the balance sheet; (ii) recognize a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a generally straight-line basis; and (iii) classify all cash payments within operating activities in the statement of cash flows. These amendments also require qualitative disclosures along with specific quantitative disclosures. This update is effective for annual and interim periods beginning after December 15, 2018 and is to be applied using a modified retrospective approach with practical expedient options. Early adoption is permitted. Fortis is assessing the impact that the adoption of this update will have on its consolidated financial statements and related disclosures. Measurement of Credit Losses on Financial Instruments ASU No. 2016-13, Measurement of Credit Losses on Financial Instruments, was issued in June 2016 and the amendments in this update require entities to use an expected credit loss methodology and to consider a broader range of reasonable and supportable information to inform credit loss estimates. This update is effective for annual and interim periods beginning after December 15, 2019 and is to be applied on a modified retrospective basis. Early adoption is permitted for annual and interim periods beginning after December 15, 2018. Fortis is assessing the impact that the adoption of this update will have on its consolidated financial statements and related disclosures. Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost ASU No. 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, was issued in March 2017 and the amendments in this update require that an employer disaggregate the current service costs component of net benefit cost and present it in the same statement of earnings line item(s) as other employee compensation costs arising from services rendered. The other components of net benefit cost are required to be presented separately from the service cost component and outside of operating income. Additionally, the amendments allow only the service cost component to be eligible for capitalization when applicable. This update is effective for annual and interim periods beginning after December 15, 2017. Early adoption is permitted. The amendments in this update should be applied retrospectively for the presentation of the net periodic benefit costs and prospectively, on and after the effective date, for the capitalization in assets of only the service cost component of net periodic benefit costs. Fortis is assessing the impact that the adoption of this update will have on its consolidated financial statements and related disclosures. The carrying values of the Corporation's consolidated financial instruments approximate their fair values, reflecting the short-term maturity, normal trade credit terms and/or nature of these instruments, except as follows. The fair value of long-term debt is calculated using quoted market prices when available. When quoted market prices are not available, as is the case with the Waneta Partnership promissory note and certain long-term debt, the fair value is determined by either: (i) discounting the future cash flows of the specific debt instrument at an estimated yield to maturity equivalent to benchmark government bonds or treasury bills with similar terms to maturity, plus a credit risk premium equal to that of issuers of similar credit quality; or (ii) obtaining from third parties indicative prices for the same or similarly rated issues of debt of the same remaining maturities. Since the Corporation does not intend to settle the long-term debt or promissory note prior to maturity, the excess of the estimated fair value above the carrying value does not represent an actual liability. The Corporation generally limits the use of derivative instruments to those that qualify as accounting, economic or cash flow hedges, or those that are approved for regulatory recovery. The Corporation records all derivative instruments at fair value, with certain exceptions including those derivatives that qualify for the normal purchase and normal sale exception. The fair value of derivative instruments is the estimate of the amounts that the Corporation would receive or have to pay to terminate the outstanding contracts as at the balance sheet dates. The Corporation's derivatives primarily include energy contracts that are subject to regulatory deferral, as permitted by the regulators, as well as certain limited energy contracts that are not subject to regulatory deferral and cash flow hedges. For further details of the Corporation's derivative instruments as at June 30, 2017 refer to Note 14 to the Corporation's unaudited condensed consolidated interim financial statements. There were no material changes in the nature and amount of the Corporations' derivative instruments from those disclosed in the 2016 Annual MD&A, except as follows. In 2017 ITC entered into additional forward-starting interest rate swaps, all effective December 2017, with a combined notional amount of $247 million and 10-year original terms. The agreements include a mandatory early termination provision and will be terminated no later than the effective date. The interest rate swaps manage the interest rate risk associated with the forecasted future issuance of fixed-rate debt. The preparation of the Corporation's condensed consolidated interim financial statements in accordance with US GAAP requires management to make estimates and judgments that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenue and expenses during the reporting periods. Estimates and judgments are based on historical experience, current conditions and various other assumptions believed to be reasonable under the circumstances. Additionally, certain estimates and judgments are necessary since the regulatory environments in which the Corporation's regulated utilities operate often require amounts to be recognized at estimated values until these amounts are finalized pursuant to regulatory decisions or other regulatory proceedings. Due to changes in facts and circumstances, and the inherent uncertainty involved in making estimates, actual results may differ significantly from current estimates. Estimates and judgments are reviewed periodically and, as adjustments become necessary, are recognized in earnings in the period in which they become known. In the event that a regulatory decision is received after the balance sheet date but before the consolidated financial statements are issued, the facts and circumstances are reviewed to determine whether or not it is a recognized subsequent event. Interim financial statements may also employ a greater use of estimates than the annual financial statements. There were no material changes in the nature of the Corporation's critical accounting estimates from those disclosed in the 2016 Annual MD&A. Contingencies: The Corporation and its subsidiaries are subject to various legal proceedings and claims associated with the ordinary course of business operations. Management believes that the amount of liability, if any, from these actions would not have a material adverse effect on the Corporation's consolidated financial position, results of operations or cash flows. For complete details of legal proceedings affecting the Corporation, refer to Note 17 to the Corporation's unaudited condensed consolidated interim financial statements. There were no material changes in the Corporation's contingencies from those disclosed in the 2016 Annual MD&A, except as described below. Following announcement of the acquisition of ITC in February 2016, complaints which named Fortis and other defendants were filed in the Oakland County Circuit Court in the State of Michigan ("Superior Court") and the United States District Court in and for the Eastern District of Michigan. The complaints generally allege, among other things, that the directors of ITC breached their fiduciary duties in connection with the merger agreement and that ITC, Fortis, FortisUS Inc. and Element Acquisition Sub Inc. aided and abetted those purported breaches. The complaints seek class action certification and a variety of relief including, among other things, unspecified damages, and costs, including attorneys' fees and expenses. In July 2016 the federal actions were voluntarily dismissed by the federal plaintiffs. The federal plaintiffs reserved the right to make certain other claims, and ITC and the individual members of the ITC board of directors reserved the right to oppose any such claim. In June 2016 the Superior Court granted a motion for summary disposition dismissing the aiding and abetting claims asserted against Fortis, FortisUS Inc. and Element Acquisition Sub Inc. In January 2017 the defendants filed an additional motion for summary disposition, which was to be heard by the court in March 2017. A hearing on class certification occurred in February 2017. In March 2017 an agreement in principle was reached to settle the case, subject to formal documentation and court approval. The court has stayed the matter, except for all settlement-related proceedings. In May 2017 the court preliminarily approved the settlement and set a final settlement approval hearing for September 2017. Related-party transactions are in the normal course of operations and are measured at the exchange amount, which is the amount of consideration established and agreed to by the related parties. There were no material related-party transactions for the three and six months ended June 30, 2017 and 2016. Inter-company balances and inter-company transactions, including any related inter-company profit, are eliminated on consolidation, except for certain inter-company transactions between non-regulated and regulated entities in accordance with accounting standards for rate-regulated entities. The significant inter-company transactions are summarized in the following table. As at June 30, 2017, accounts receivable on the Corporation's condensed consolidated interim balance sheet included approximately $11 million due from Belize Electricity (December 31, 2016 - $16 million), in which Fortis holds a 33% equity investment. The following table sets forth certain quarterly information for the Corporation. The quarterly information has been obtained from the Corporation's unaudited condensed consolidated interim financial statements. These financial results are not necessarily indicative of results for any future period and should not be relied upon to predict future performance. The summary of the past eight quarters reflects the Corporation's continued organic growth, growth from acquisitions net of the associated acquisition-related transaction costs, and the impact of the sale of non-regulated assets, as well as the seasonality associated with its businesses. Interim results will fluctuate due to the seasonal nature of electricity and gas demand, as well as the timing and recognition of regulatory decisions. Revenue is also affected by the cost of fuel, purchased power and natural gas, which are flowed through to customers without markup. Given the diversified nature of the Corporation's subsidiaries, seasonality may vary. Most of the annual earnings of the gas utilities are realized in the first and fourth quarters due to space-heating requirements. Earnings for the electric utilities in the United States are generally highest in the second and third quarters due to the use of air conditioning and other cooling equipment. June 2017/June 2016: Net earnings attributable to common equity shareholders were $257 million, or $0.62 per common share, for the second quarter of 2017 compared to earnings of $107 million, or $0.38 per common share, for the second quarter of 2016. A discussion of the quarter over quarter variance in financial results is provided in the "Financial Highlights" section of this MD&A. March 2017/March 2016: Net earnings attributable to common equity shareholders were $294 million, or $0.72 per common share, for the first quarter of 2017 compared to earnings of $162 million, or $0.57 per common share, for the first quarter of 2016. The increase was driven by earnings of $91 million at ITC, acquired in October 2016. The increase was also due to: (i) strong performance at UNS Energy, due to the favourable settlement of matters pertaining to FERC ordered transmission refunds of $7 million, after-tax, in January 2017 compared to $11 million, after-tax, in FERC ordered transmission refunds in the first quarter of 2016, and higher retail rates as approved pursuant to its 2017 general rate case; (ii) acquisition-related transactions costs associated with ITC recognized in Corporate and Other expenses in the first quarter of 2017; (iii) contribution from Aitken Creek, including an after-tax $6 million unrealized gain on the mark-to-market of derivatives; and (iv) the timing of quarterly revenue and operating expenses as compared to the same period in 2016 and higher AFUDC at FortisBC Energy. The increase was partially offset by: (i) lower contribution from FortisAlberta, mainly due to lower customer rates and higher operating expenses; (ii) higher finance charges at Corporate and Other associated with the acquisitions of ITC and Aitken Creek; and (iii) unfavourable foreign exchange associated with US dollar-denominated earnings. December 2016/December 2015: Net earnings attributable to common equity shareholders were $189 million, or $0.49 per common share, for the fourth quarter of 2016 compared to earnings of $135 million, or $0.48 per common share, for the fourth quarter of 2015. The increase in earnings was driven by contribution of $59 million from ITC, which was reduced by $22 million in expenses associated with the accelerated vesting of the Company's stock-based compensation awards as a result of the acquisition. Strong performance at most of the Corporation's regulated utilities and contribution of $6 million from Aitken Creek, net of an after-tax $3 million unrealized loss on the mark-to-market of derivatives, also contributed to higher earnings. The increase was partially offset by higher Corporate and Other expenses. Corporate and Other expenses reflected after-tax acquisition-related transaction costs of $32 million in the fourth quarter of 2016, compared to $7 million in the fourth quarter of 2015, with the remaining increase primarily due to finance charges associated with the acquisition of ITC. September 2016/September 2015: Net earnings attributable to common equity shareholders were $127 million, or $0.45 per common share, for the third quarter of 2016 compared to earnings of $151 million, or $0.54 per common share, for the third quarter of 2015. The decrease in earnings was primarily due to: $7 million (US$5 million) in FERC ordered transmission refunds at UNS Energy, $19 million in acquisition-related transaction costs, and a $1 million unrealized loss on the mark-to-market of derivatives in the third quarter of 2016; a $5 million positive tax adjustment on the sale of hotel assets, a $5 million gain on the sale of non-regulated generation assets, and a foreign exchange gain of $5 million in the third quarter of 2015; partially offset by the $9 million loss on the settlement of expropriation matters in Belize in the third quarter of 2015. Also contributing to the decrease in earnings were: (i) lower earnings at FortisAlberta due to higher operating expenses, a negative capital tracker revenue adjustment as a result of the outcome of the 2016 Generic Cost of Capital Proceeding in Alberta, and lower average energy consumption; (ii) the sale of hotel assets in 2015; and (iii) an increase in Corporate and Other expenses. Partially offsetting the above decreases in earnings were: (i) strong performance at most of the Corporation's regulated utilities driven by UNS Energy, largely due to the settlement of Springerville Unit 1 matters, and Central Hudson, due to an increase in delivery revenue; (ii) the timing of quarterly earnings at FortisBC Electric compared to the third quarter of 2015; and (iii) contribution of $2 million from Aitken Creek, which was acquired in early April 2016. The Corporation's results for 2017 will continue to benefit from the acquisition of ITC and the impact of the rate case settlement at UNS Energy. Over the long term, Fortis is well positioned to enhance value for shareholders through the execution of its capital plan, the balance and strength of its diversified portfolio of utility businesses, as well as growth opportunities within its service territories. Over the five-year period through 2021, the Corporation's capital program is expected to be approximately $13 billion, increasing rate base to almost $30 billion in 2021. Fortis expects this long-term sustainable growth in rate base to support continuing growth in earnings and dividends. Fortis has targeted average annual dividend growth of approximately 6% through 2021. This dividend guidance takes into account many factors, including the expectation of reasonable outcomes for regulatory proceedings at the Corporation's utilities, the successful execution of the five-year capital expenditure program, and management's continued confidence in the strength of the Corporation's diversified portfolio of utilities and record of operational excellence. As at July 27, 2017, the Corporation had issued and outstanding 417.9 million common shares; 5.0 million First Preference Shares, Series F; 9.2 million First Preference Shares, Series G; 7.0 million First Preference Shares, Series H; 3.0 million First Preference Shares, Series I; 8.0 million First Preference Shares, Series J; 10.0 million First Preference Shares, Series K; and 24.0 million First Preference Shares, Series M. Only the common shares of the Corporation have voting rights. The Corporation's First Preference Shares do not have voting rights unless and until Fortis fails to pay eight quarterly dividends, whether or not consecutive and whether such dividends have been declared. The number of common shares of Fortis that would be issued if all outstanding stock options were converted as at July 27, 2017 is approximately 4.0 million. Additional information can be accessed at www.fortisinc.com, www.sedar.com, or www.sec.gov. The information contained on, or accessible through, any of these websites is not incorporated by reference into this document. See accompanying Notes to Condensed Consolidated Interim Financial Statements See accompanying Notes to Condensed Consolidated Interim Financial Statements See accompanying Notes to Condensed Consolidated Interim Financial Statements See accompanying Notes to Condensed Consolidated Interim Financial Statements See accompanying Notes to Condensed Consolidated Interim Financial Statements Fortis Inc. ("Fortis" or the "Corporation") is principally an international electric and gas utility holding company. Fortis segments its utility operations by franchise area and, depending on regulatory requirements, by the nature of the assets. Fortis also holds investments in non-regulated energy infrastructure, which is treated as a separate segment. The Corporation's reporting segments allow senior management to evaluate the operational performance and assess the overall contribution of each segment to the long-term objectives of Fortis. Each entity within the reporting segments operates with substantial autonomy, assumes profit and loss responsibility and is accountable for its own resource allocation. The Corporation's reportable segments and basis of segmentation is consistent with the Corporation's 2016 annual audited consolidated financial statements. The Corporation's interests in regulated electric and gas utilities are as follows: Non-Regulated - Energy Infrastructure is primarily comprised of long-term contracted generation assets in British Columbia and Belize, and the Aitken Creek natural gas storage facility ("Aitken Creek") in British Columbia. Aitken Creek was acquired by Fortis in April 2016 (Note 16). The Corporate and Other segment captures expense and revenue items not specifically related to any reportable segment and those business operations that are below the required threshold for reporting as separate segments. The Corporate and Other segment includes net corporate expenses of Fortis and non-regulated holding company expenses. These condensed consolidated interim financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("US GAAP") for interim financial statements. As a result, these condensed consolidated interim financial statements do not include all of the information and disclosures required in the annual consolidated financial statements and should be read in conjunction with the Corporation's 2016 annual audited consolidated financial statements. In management's opinion, the condensed consolidated interim financial statements include all adjustments that are of a normal recurring nature and necessary to present fairly the consolidated financial position of the Corporation. Interim results will fluctuate due to the seasonal nature of electricity and gas demand, as well as the timing and recognition of regulatory decisions. Revenue is also affected by the cost of fuel, purchased power and natural gas, which are flowed through to customers without markup. Given the diversified nature of the Corporation's subsidiaries, seasonality may vary. Most of the annual earnings of the gas utilities are realized in the first and fourth quarters due to space-heating requirements. Earnings for the electric utilities in the United States are generally highest in the second and third quarters due to the use of air conditioning and other cooling equipment. The preparation of the condensed consolidated interim financial statements in accordance with US GAAP requires management to make estimates and judgments that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements, and the reported amounts of revenue and expenses during the reporting periods. Estimates and judgments are based on historical experience, current conditions and various other assumptions believed to be reasonable under the circumstances. Additionally, certain estimates and judgments are necessary since the regulatory environments in which the Corporation's regulated utilities operate often require amounts to be recognized at estimated values until these amounts are finalized pursuant to regulatory decisions or other regulatory proceedings. Due to changes in facts and circumstances, and the inherent uncertainty involved in making estimates, actual results may differ significantly from current estimates. Estimates and judgments are reviewed periodically and, as adjustments become necessary they are recognized in earnings in the period in which they become known. In the event that a regulatory decision is received after the balance sheet date but before the consolidated financial statements are issued, the facts and circumstances are reviewed to determine whether or not it is a recognized subsequent event. All amounts are presented in Canadian dollars unless otherwise stated. These condensed consolidated interim financial statements are comprised of the accounts of Fortis and its wholly owned subsidiaries and controlling ownership interests. All inter-company balances and transactions have been eliminated on consolidation, except as disclosed in Note 4. These condensed consolidated interim financial statements have been prepared following the same accounting policies and methods as those used to prepare the Corporation's 2016 annual audited consolidated financial statements, except as described below. Effective January 1, 2017, the Corporation adopted Accounting Standards Update ("ASU") No. 2017-04, Simplifying the Test for Goodwill Impairment. The amendments in this update simplify the subsequent measurement of goodwill by eliminating step two in the current two-step goodwill impairment test. An entity will apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit's carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit. The new guidance does not amend the optional qualitative assessment of goodwill impairment. The above-noted ASU was applied prospectively and did not impact the Corporation's unaudited condensed consolidated interim financial statements for the three and six months ended June 30, 2017. The Corporation considers the applicability and impact of all ASUs issued by the Financial Accounting Standards Board ("FASB"). The following updates have been issued by FASB, but have not yet been adopted by Fortis. Any ASUs not included below were assessed and determined to be either not applicable to the Corporation or are not expected to have a material impact on the consolidated financial statements. ASU No. 2014-09 was issued in May 2014 and the amendments in this update create Accounting Standards Codification ("ASC") Topic 606, Revenue from Contracts with Customers, and supersede the revenue recognition requirements in ASC Topic 605, Revenue Recognition, including most industry-specific revenue recognition guidance throughout the codification. This standard clarifies the principles for recognizing revenue and can be applied consistently across various transactions, industries and capital markets. In 2016 a number of additional ASUs were issued that clarify implementation guidance in ASC Topic 606. This standard, and all related ASUs, is effective for annual and interim periods beginning after December 15, 2017. Early adoption is permitted for annual and interim periods beginning after December 15, 2016. The Corporation has elected not to early adopt. The new guidance permits two methods of adoption: (i) the full retrospective method, under which comparative periods would be restated, and the cumulative impact of applying the standard would be recognized as at January 1, 2017, the earliest period presented; and (ii) the modified retrospective method, under which comparative periods would not be restated and the cumulative impact of applying the standard would be recognized at the date of initial adoption, January 1, 2018. The Corporation expects to use the modified retrospective approach; however, it continues to monitor interpretative issues that remain outstanding. Any significant developments in interpretative issues could change the Corporation's expected method of adoption. More than 80% of the Corporation's revenue is generated from energy sales to retail and wholesale customers based on published tariff rates, as approved by the respective regulators, and is considered to be in the scope of ASU No. 2014-09. Fortis has assessed retail and wholesale tariff revenue and expects that the adoption of this standard will not change the Corporation's accounting policy for recognizing retail and wholesale tariff revenue and, therefore, will not have an impact on earnings. Fortis continues to assess whether this standard will have an impact on its remaining revenue streams. The Corporation has not disclosed the expected impact of the adoption of this standard on its consolidated financial statements as it is not expected to be material. However, certain specific interpretative issues remain outstanding and the conclusions reached, if different than currently anticipated, could have a material impact on the Corporation's consolidated financial statements and related disclosures. Fortis continues to closely monitor developments related to the new standard. The adoption of this standard will impact the Corporation's revenue disclosures as revenue from contracts with customers is required to be reported separately from alternative revenue, which is outside the scope of ASC Topic 606. Fortis is in the process of drafting these required disclosures. As part of its effort to adopt the new revenue recognition standard, Fortis is monitoring its adoption process under its existing internal controls over financial reporting ("ICFR"), including accounting processes and the gathering and evaluation of information used in assessing the required disclosures. As the implementation process continues, Fortis will assess any necessary changes to ICFR. Recognition and Measurement of Financial Assets and Financial Liabilities ASU No. 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities, was issued in January 2016 and the amendments in this update address certain aspects of recognition, measurement, presentation and disclosure of financial instruments. Most notably, the amendments require the following: (i) equity investments in unconsolidated entities (other than those accounted for using the equity method of accounting) to be measured at fair value through earnings; however, entities will be able to elect to record equity investments without readily determinable fair values at cost, less impairment, and plus or minus subsequent adjustments for observable price changes; and (ii) financial assets and financial liabilities to be presented separately in the notes to the consolidated financial statements, grouped by measurement category and form of financial asset. This update is effective for annual and interim periods beginning after December 15, 2017. Fortis is assessing the impact that the adoption of this update will have on its consolidated financial statements and related disclosures. ASU No. 2016-02 was issued in February 2016 and the amendments in this update create ASC Topic 842, Leases, and supersede lease requirements in ASC Topic 840, Leases. The main provision of ASC Topic 842 is the recognition of lease assets and lease liabilities on the balance sheet by lessees for those leases that were previously classified as operating leases. For operating leases, a lessee is required to do the following: (i) recognize a right-of-use asset and a lease liability, initially measured at the present value of the lease payments, on the balance sheet; (ii) recognize a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a generally straight-line basis; and (iii) classify all cash payments within operating activities in the statement of cash flows. These amendments also require qualitative disclosures along with specific quantitative disclosures. This update is effective for annual and interim periods beginning after December 15, 2018 and is to be applied using a modified retrospective approach with practical expedient options. Early adoption is permitted. Fortis is assessing the impact that the adoption of this update will have on its consolidated financial statements and related disclosures. Measurement of Credit Losses on Financial Instruments ASU No. 2016-13, Measurement of Credit Losses on Financial Instruments, was issued in June 2016 and the amendments in this update require entities to use an expected credit loss methodology and to consider a broader range of reasonable and supportable information to inform credit loss estimates. This update is effective for annual and interim periods beginning after December 15, 2019 and is to be applied on a modified retrospective basis. Early adoption is permitted for annual and interim periods beginning after December 15, 2018. Fortis is assessing the impact that the adoption of this update will have on its consolidated financial statements and related disclosures. Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost ASU No. 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, was issued in March 2017 and the amendments in this update require that an employer disaggregate the current service costs component of net benefit cost and present it in the same statement of earnings line item(s) as other employee compensation costs arising from services rendered. The other components of net benefit cost are required to be presented separately from the service cost component and outside of operating income. Additionally, the amendments allow only the service cost component to be eligible for capitalization when applicable. This update is effective for annual and interim periods beginning after December 15, 2017. Early adoption is permitted. The amendments in this update should be applied retrospectively for the presentation of the net periodic benefit costs and prospectively, on and after the effective date, for the capitalization in assets of only the service cost component of net periodic benefit costs. Fortis is assessing the impact that the adoption of this update will have on its consolidated financial statements and related disclosures. Information by reportable segment is as follows: Related-party transactions are in the normal course of operations and are measured at the exchange amount, which is the amount of consideration established and agreed to by the related parties. There were no material related-party transactions for the three and six months ended June 30, 2017 and 2016. Inter-company balances and inter-company transactions, including any related inter-company profit, are eliminated on consolidation, except for certain inter-company transactions between non-regulated and regulated entities in accordance with accounting standards for rate-regulated entities. The significant inter-company transactions are summarized in the following table. As at June 30, 2017, accounts receivable on the Corporation's condensed consolidated interim balance sheet included approximately $11 million due from Belize Electricity (December 31, 2016 - $16 million), in which Fortis holds a 33% equity investment. A summary of the Corporation's regulatory assets and liabilities is provided below. For a detailed description of the nature of the Corporation's regulatory assets and liabilities, refer to Note 8 to the Corporation's 2016 annual audited consolidated financial statements. In March 2017 ITC entered into 1-year and 2-year unsecured term loan credit agreements at floating interest rates of a one-month LIBOR plus a spread of 0.90% and 0.65%, respectively. As at June 30, 2017, borrowings under the term loan credit agreements were US$200 million ($268 million) and US$50 million ($67 million), respectively, representing the maximum amounts available under the agreements. The net proceeds from these borrowings were used to repay credit facility borrowings and for general corporate purposes. In April 2017 ITC issued 30-year US$200 million ($268 million) 4.16% secured first mortgage bonds. The net proceeds from the issuance were used to repay credit facility borrowings and for general corporate purposes. In March and May 2017, Caribbean Utilities issued US$60 million ($80 million) of unsecured notes in a dual tranche of 15-year US$40 million ($54 million) at 3.90% and 30-year US$20 million ($26 million) at 4.64%, respectively. The net proceeds from the issuances were used to finance capital expenditures and repay short-term borrowings. In June 2017 Newfoundland Power issued 40-year $75 million 3.82% first mortgage sinking fund bonds. The net proceeds from the issuance were used to repay credit facility borrowings and for general corporate purposes. Common shares issued during the period were as follows. In March 2017 Fortis issued approximately 12.2 million common shares to an institutional investor, representing share consideration of $500 million at a price of $41.00 per share. The net proceeds were used to repay short-term borrowings (Note 15). For the three and six months ended June 30, 2017, stock-based compensation expense of approximately $12 million and $24 million, respectively was recognized ($6 million and $15 million for the three and six months ended June 30, 2016, respectively). In February 2017 the Corporation granted 774,924 options to purchase common shares under its 2012 Stock Option Plan ("2012 Plan") at the five-day volume weighted average trading price immediately preceding the date of grant of $42.36. The options granted under the 2012 Plan are exercisable for a period not to exceed 10 years from the date of grant, expire no later than three years after the termination, death or retirement of the optionee and vest evenly over a four-year period on each anniversary of the date of grant. Directors are not eligible to receive grants of options under the 2012 Plan. The accounting fair value of each option granted was $3.22 per option. The accounting fair value was estimated at the date of grant using the Black-Scholes fair value option-pricing model and the following assumptions: In January 2017, 8,351 Deferred Share Units ("DSUs") were granted to the Corporation's Board of Directors, representing the first quarter equity component of the Directors' annual compensation and, where opted, their first quarter component of annual retainers in lieu of cash. Each DSU represents a unit with an underlying value equivalent to the value of one common share of the Corporation and is entitled to accrue notional common share dividends equivalent to those declared by the Corporation's Board of Directors. The DSUs are fully vested at the date of grant. In April 2017, 7,846 DSUs were granted to the Corporation's Board of Directors, representing the second quarter equity component of the Directors' annual compensation and, where opted, their second quarter component of annual retainers in lieu of cash. In the first half of 2017, the Corporation granted 728,552 Performance Share Units ("PSUs"), under the 2015 PSU Plan, to senior management of the Corporation and its subsidiaries, with the exception of ITC where PSUs were granted to all employees consistent with past practice. The Corporation's PSU Plans represent a component of long-term compensation. Each PSU represents a unit with an underlying value equivalent to the value of one common share of the Corporation and is subject to a three-year vesting and performance period, at which time a cash payment may be made. Each PSU is entitled to accrue notional common share dividends equivalent to those declared by the Corporation's Board of Directors. As at June 30, 2017, the estimated payout percentages for the grants under the 2015 PSU Plan ranged from 97% to 109%. In the second quarter of 2017, the Corporation paid out 281,794 PSUs at $41.46 per PSU, for a total of approximately $13 million. The payout was made in respect of the PSUs granted in 2014, under the 2013 PSU Plan. The payout percentage ranged from 106% to 113% and was based on the Corporation's and subsidiaries' performance over the three-year period, as determined by the respective Human Resources Committees. In the first half of 2017, the Corporation granted 330,686 Restricted Share Units ("RSUs") to senior management of the Corporation and its subsidiaries, with the exception of ITC where RSUs were granted to all employees consistent with past practice. The Corporation's RSU Plan represents a component of long-term compensation. Each RSU represents a unit with an underlying value equivalent to the value of one common share of the Corporation and is subject to a three-year vesting period, at which time a cash payment may be made. Each RSU is entitled to accrue notional common share dividends equivalent to those declared by the Corporation's Board of Directors. The Corporation and its subsidiaries each maintain one or a combination of defined benefit pension plans and defined contribution pension plans, including group Registered Retirement Savings Plans and group 401(k) plans, for employees. The Corporation and certain subsidiaries also offer other post-employment benefit ("OPEB") plans for qualifying employees. The net benefit cost of providing the defined benefit pension and OPEB plans is detailed in the following tables. For the three and six months ended June 30, 2017, the Corporation expensed $9 million and $20 million, respectively ($7 million and $15 million for the three and six months ended June 30, 2016, respectively) related to defined contribution pension plans. The Corporation calculates earnings per common share ("EPS") on the weighted average number of common shares outstanding. Diluted EPS is calculated using the treasury stock method for options and the "if-converted" method for convertible securities. EPS was as follows. 14. FAIR VALUE MEASUREMENTS AND FINANCIAL INSTRUMENTS Fair value is the price at which a market participant could sell an asset or transfer a liability to an unrelated party. A fair value measurement is required to reflect the assumptions that market participants would use in pricing an asset or liability based on the best available information. These assumptions include the risks inherent in a particular valuation technique, such as a pricing model, and the risks inherent in the inputs to the model. A fair value hierarchy exists that prioritizes the inputs used to measure fair value. The three levels of the fair value hierarchy are defined as follows: The fair values of the Corporation's financial instruments, including derivatives, reflect point-in-time estimates based on current and relevant market information about the instruments as at the balance sheet dates. The estimates cannot be determined with precision as they involve uncertainties and matters of judgment and, therefore, may not be relevant in predicting the Corporation's future consolidated earnings or cash flows. The following table presents, by level within the fair value hierarchy, the Corporation's assets and liabilities accounted for at fair value on a recurring basis. These assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement and there were no transfers between the levels in the periods presented. For derivative instruments, the Corporation has elected gross presentation for its derivative contracts under master netting agreements and collateral positions. The Corporation generally limits the use of derivative instruments to those that qualify as accounting, economic or cash flow hedges, or those that are approved for regulatory recovery. The Corporation records all derivative instruments at fair value, with certain exceptions including those derivatives that qualify for the normal purchase and normal sale exception. The fair value of derivative instruments is the estimate of the amounts that the Corporation would receive or have to pay to terminate the outstanding contracts as at the balance sheet dates. UNS Energy holds electricity power purchase contracts and gas swap contracts to reduce its exposure to energy price risk associated with purchased power and gas requirements. UNS Energy primarily applies the market approach for fair value measurements using independent third-party information, where possible. When published prices are not available, adjustments are applied based on historical price curve relationships, transmission costs and line losses. UNS Energy also considers the impact of counterparty credit risk using current and historical default and recovery rates, as well as its own credit risk using credit default swap data. Central Hudson holds swap contracts for electricity and natural gas to minimize price volatility by fixing the effective purchase price for the defined commodities. The fair value of the swap contracts was calculated using forward pricing provided by independent third parties. FortisBC Energy holds gas supply contracts and fixed price financial swaps to fix the effective purchase price of natural gas, as the majority of the natural gas supply contracts have floating, rather than fixed, prices. The fair value of the natural gas derivatives was calculated using the present value of cash flows based on published market prices and forward curves for natural gas. As at June 30, 2017, these energy contract derivatives were not designated as hedges; however, any unrealized gains or losses associated with changes in the fair value of the derivatives are deferred as a regulatory asset or liability for recovery from, or refund to, customers in future rates, as permitted by the regulators. These unrealized losses and gains would otherwise be recognized in earnings. As at June 30, 2017, unrealized losses of $28 million (December 31, 2016 - $19 million) were recognized in regulatory assets and unrealized gains of $1 million (December 31, 2016 - $12 million) were recognized in regulatory liabilities (Note 5). UNS Energy holds wholesale trading contracts that qualify as derivative instruments. The unrealized gains and losses on these derivative instruments are recognized in earnings, as they do not qualify for regulatory deferral. Ten percent of any realized gains on these contracts are shared with customers through UNS Energy's rate stabilization accounts. Aitken Creek holds gas swap contracts to manage its exposure to changes in natural gas prices, to capture natural gas price spreads, and to manage the financial risk posed by physical transactions. The fair value of the gas swap contracts was calculated using forward pricing from published market sources. The unrealized gains and losses on these derivative instruments are recognized in earnings. As at June 30, 2017, ITC held forward-starting interest rate swaps, effective December 2017 and January 2018, with notional amounts totalling $325 million and 10-year original terms. The agreements include a mandatory early termination provision and will be terminated no later than the effective dates. The interest rate swaps manage the interest rate risk associated with the forecasted future issuance of fixed-rate debt related to the refinancing of maturing $500 million long-term debt due in January 2018. UNS Energy holds an interest rate swap, expiring in 2020, to mitigate its exposure to volatility in variable interest rates on capital lease obligations. The unrealized gains and losses on cash flow hedges are recognized in other comprehensive income and reclassified to earnings as a component of interest expense over the life of the hedged debt. The loss expected to be reclassified to earnings within the next twelve months is estimated to be approximately $4 million. Cash flows associated with the settlement of all derivative instruments are included in operating activities on the Corporation's consolidated statement of cash flows. As at June 30, 2017, the following notional volumes related to electricity and natural gas derivatives that are expected to be settled are outlined below. Financial Instruments Not Carried At Fair Value The following table discloses the estimated fair value measurements of the Corporation's financial instruments not carried at fair value. The fair values were measured using Level 2 pricing inputs, except as noted. The carrying values of the Corporation's consolidated financial instruments approximate their fair values, reflecting the short-term maturity, normal trade credit terms and/or nature of these instruments, except as follows. The fair value of long-term debt is calculated using quoted market prices when available. When quoted market prices are not available, as is the case with the Waneta Partnership promissory note and certain long-term debt, the fair value is determined by either: (i) discounting the future cash flows of the specific debt instrument at an estimated yield to maturity equivalent to benchmark government bonds or treasury bills with similar terms to maturity, plus a credit risk premium equal to that of issuers of similar credit quality; or (ii) obtaining from third parties indicative prices for the same or similarly rated issues of debt of the same remaining maturities. Since the Corporation does not intend to settle the long-term debt or promissory note prior to maturity, the excess of the estimated fair value above the carrying value does not represent an actual liability. The Corporation is primarily exposed to credit risk, liquidity risk and market risk as a result of holding financial instruments in the normal course of business. For cash equivalents, trade and other accounts receivable, and long-term other receivables, the Corporation's credit risk is generally limited to the carrying value on the consolidated balance sheet. The Corporation generally has a large and diversified customer base, which minimizes the concentration of credit risk. The Corporation and its subsidiaries have various policies to minimize credit risk, which include requiring customer deposits, prepayments and/or credit checks for certain customers and performing disconnections and/or using third-party collection agencies for overdue accounts. ITC has a concentration of credit risk as a result of approximately 70% of its revenue being derived from three primary customers. Credit risk is limited as such customers have investment-grade credit ratings. ITC also reduces its exposure to credit risk by requiring a letter of credit or cash deposit equal to the credit exposure, which is determined by a credit-scoring model and other factors. FortisAlberta has a concentration of credit risk as a result of its distribution service billings being to a relatively small group of retailers. As at June 30, 2017, FortisAlberta's gross credit risk exposure was approximately $129 million, representing the projected value of retailer billings over a 37-day period. The Company has reduced its exposure to $1 million by obtaining from the retailers either a cash deposit, bond, letter of credit, an investment-grade credit rating from a major rating agency, or a financial guarantee from an entity with an investment-grade credit rating. UNS Energy, Central Hudson, FortisBC Energy and Aitken Creek may be exposed to credit risk in the event of non-performance by counterparties to derivative instruments. The Companies use netting arrangements to reduce credit risk and net settle payments with counterparties where net settlement provisions exist. They also limit credit risk by mostly dealing with counterparties that have investment-grade credit ratings. At UNS Energy, contractual arrangements also contain certain provisions requiring counterparties to derivative instruments to post collateral under certain circumstances. The Corporation's consolidated financial position could be adversely affected if it, or one of its subsidiaries, fails to arrange sufficient and cost-effective financing to fund, among other things, capital expenditures, acquisitions and the repayment of maturing debt. The ability to arrange sufficient and cost-effective financing is subject to numerous factors, including the consolidated results of operations and financial position of the Corporation and its subsidiaries, conditions in capital and bank credit markets, ratings assigned by rating agencies and general economic conditions. To help mitigate liquidity risk, the Corporation and its regulated utilities have secured committed credit facilities to support short-term financing of capital expenditures, seasonal working capital requirements, and for general corporate purposes. In addition to its credit facilities, ITC uses commercial paper to finance its short-term cash requirements, and may use credit facility borrowings, from time to time, to repay borrowings under its commercial paper program. The Corporation's committed corporate credit facility is used for interim financing of acquisitions and for general corporate purposes. Depending on the timing of cash payments from subsidiaries, borrowings under the Corporation's committed corporate credit facility may be required from time to time to support the servicing of debt and payment of dividends. As at June 30, 2017, over the next five years, average annual consolidated fixed-term debt maturities and repayments are expected to be approximately $730 million. The combination of available credit facilities and reasonable annual debt maturities and repayments provides the Corporation and its subsidiaries with flexibility in the timing of access to capital markets. As at June 30, 2017, the Corporation and its subsidiaries had consolidated credit facilities of approximately $5.4 billion, of which approximately $4.0 billion was unused, including $940 million unused under the Corporation's committed revolving corporate credit facility. The credit facilities are syndicated mostly with large banks in Canada and the United States, with no one bank holding more than 20% of these facilities. Approximately $5.0 billion of the total credit facilities are committed facilities with maturities ranging from 2017 through 2022. The following summary outlines the credit facilities of the Corporation and its subsidiaries. As at June 30, 2017 and December 31, 2016, certain borrowings under the Corporation's and subsidiaries' long-term committed credit facilities were classified as long-term debt. It is management's intention to refinance these borrowings with long-term permanent financing during future periods. There were no material changes in credit facilities from that disclosed in the Corporation's 2016 annual audited consolidated financial statements except as follows. In March 2017 the Corporation repaid short-term borrowings using net proceeds from the issuance of common shares (Note 7). The reporting currency of ITC, UNS Energy, Central Hudson, Caribbean Utilities, Fortis Turks and Caicos and Belize Electric Company Limited is the US dollar. The Corporation's earnings from, and net investments in, foreign subsidiaries are exposed to fluctuations in the US dollar-to-Canadian dollar exchange rate. The Corporation has decreased the above-noted exposure through the use of US dollar-denominated borrowings at the corporate level. The foreign exchange gain or loss on the translation of US dollar-denominated interest expense partially offsets the foreign exchange gain or loss on the translation of the Corporation's foreign subsidiaries' earnings. As at June 30, 2017, the Corporation's corporately issued US$3,440 million (December 31, 2016 - US$3,511 million) long-term debt had been designated as an effective hedge of a portion of the Corporation's foreign net investments. As at June 30, 2017, the Corporation had approximately US$7,522 million (December 31, 2016 - US$7,250 million) in foreign net investments that were unhedged. Foreign currency exchange rate fluctuations associated with the translation of the Corporation's corporately issued US dollar-denominated borrowings designated as effective hedges are recorded on the consolidated balance sheet in accumulated other comprehensive income and serve to help offset unrealized foreign currency exchange gains and losses on the net investments in foreign subsidiaries, which gains and losses are also recorded on the consolidated balance sheet in accumulated other comprehensive income. As a result of the acquisition of ITC, consolidated earnings and cash flows of Fortis are impacted to a greater extent by fluctuations in the US dollar-to-Canadian dollar exchange rate. On an annual basis, it is estimated that a 5 cent increase or decrease in the US dollar relative to the Canadian dollar exchange rate of US$1.00=CAD$1.30 as at June 30, 2017 would increase or decrease earnings per common share of Fortis by approximately 7 cents. Management will continue to hedge future exchange rate fluctuations related to the Corporation's foreign net investments and US dollar-denominated earnings streams, where appropriate, through future US dollar-denominated borrowings, and will continue to monitor the Corporation's exposure to foreign currency fluctuations on a regular basis. The Corporation and most of its subsidiaries are exposed to interest rate risk associated with borrowings under variable-rate credit facilities, variable-rate long-term debt and the refinancing of long-term debt. The Corporation and its subsidiaries may enter into interest rate swap agreements to help reduce this risk (Note 14). UNS Energy is exposed to commodity price risk associated with changes in the market price of gas, purchased power and coal. Central Hudson is exposed to commodity price risk associated with changes in the market price of electricity and gas. FortisBC Energy and Aitken Creek are exposed to commodity price risk associated with changes in the market price of gas. The risks have been reduced by entering into derivative contracts that effectively fix the price of natural gas, power and electricity purchases. These derivative instruments are recorded on the consolidated balance sheet at fair value and any change in the fair value is deferred as a regulatory asset or liability, as permitted by the regulators, for recovery from, or refund to, customers in future rates, except at Aitken Creek and wholesale trading contracts at UNS Energy where the changes in fair value are recorded in earnings (Note 14). Pending Acquisition of an Interest in Waneta Dam In May 2017 Fortis entered into an agreement with Teck Resources Limited ("Teck") to acquire a two-thirds ownership interest in the Waneta Dam and related transmission assets in British Columbia for a purchase price of $1.2 billion (the "Waneta Acquisition"), subject to certain adjustments. The Waneta Acquisition will be funded by a combination of cash on hand, debt and equity. The Waneta Dam is a renewable energy facility that is currently operated and maintained by FortisBC Inc. Under the purchase agreement, Teck Metals Ltd. will be granted a 20-year lease, with an option to extend for a further 10 years, to use the two-thirds interest in the Waneta Dam to produce power for its industrial operations in Trail, British Columbia. BC Hydro, the owner of the remaining one-third ownership interest in the Waneta Dam, has a right of first offer. Closing of the Waneta Acquisition will also be subject to certain customary conditions, including receipt of certain approvals and consents from Canadian and U.S. governmental authorities. Provided BC Hydro does not exercise its right to purchase Teck's two-thirds interest in the Waneta Dam, the transaction is expected to close in the fourth quarter of 2017. On October 14, 2016, Fortis and GIC acquired all of the outstanding common shares of ITC for an aggregate purchase price of approximately US$11.8 billion ($15.7 billion) on closing, including approximately US$4.8 billion ($6.3 billion) of ITC consolidated indebtedness. ITC is now a subsidiary of Fortis, with an affiliate of GIC owning a 19.9% minority interest in ITC. Under the terms of the transaction, ITC shareholders received US$22.57 in cash and 0.7520 of a Fortis common share per ITC share, representing total consideration of approximately US$7.0 billion ($9.4 billion). The net cash consideration totalled approximately US$3.5 billion ($4.7 billion) and was financed using: (i) net proceeds from the issuance of US$2.0 billion unsecured notes in October 2016; (ii) net proceeds from GIC's US$1.228 billion minority investment, which includes a shareholder note of US$199 million; and (iii) drawings of approximately US$404 million ($535 million) under the Corporation's non-revolving term senior unsecured equity bridge credit facility. On October 14, 2016, approximately 114.4 million common shares of Fortis were issued to shareholders of ITC, representing share consideration of approximately US$3.5 billion ($4.7 billion), based on the closing price for Fortis common shares of $40.96 and the closing foreign exchange rate of US$1.00=CAD$1.32 on October 13, 2016. The financing of the acquisition was structured to allow Fortis to maintain investment-grade credit ratings. The following table summarizes the preliminary allocation of the purchase consideration to the assets and liabilities acquired as at October 14, 2016 based on their fair values, using an exchange rate of US$1.00=CAD$1.32. The purchase price allocation remains preliminary pending final assessment of fair value estimates, income taxes, consideration transferred, and identification of assets and liabilities. The acquisition has been accounted for using the acquisition method, whereby financial results of the business acquired have been consolidated in the financial statements of Fortis commencing on October 14, 2016. Acquisition-related transaction costs totalled approximately $118 million ($90 million after tax) in 2016. Acquisition-related transaction costs included: (i) investment banking, legal, consulting and other fees totalling approximately $79 million ($62 million after tax) in 2016, which were included in operating expenses; and (ii) fees associated with the Corporation's acquisition credit facilities and deal-contingent interest rate swap contracts totalling approximately $39 million ($28 million after tax) in 2016, which were included in finance charges. From the date of acquisition, ITC also recognized US$21 million ($27 million) in after-tax expenses associated with the accelerated vesting of the Company's stock-based compensation awards as a result of the acquisition, of which the Corporation's share was US$17 million ($22 million). The unaudited pro forma financial information below gives effect to the acquisition of ITC as if the transaction had occurred at the beginning of 2016. This pro forma data is presented for information purposes only, and does not necessarily represent the results that would have occurred had the acquisition taken place at the beginning of 2016, nor is it necessarily indicative of the results that may be expected in future periods. On April 1, 2016, Fortis acquired Aitken Creek Gas Storage ULC from Chevron Canada Properties Ltd. for approximately $349 million (US$266 million), plus the cost of working gas inventory. The net cash purchase price was initially financed through US dollar-denominated borrowings under the Corporation's committed revolving credit facility. In December 2015 the Corporation paid a deposit of $38 million (US$29 million) as part of the purchase consideration for the transaction (Note 13). The allocation of purchase consideration to the assets and liabilities acquired as at April 1, 2016, based on their fair values, resulted in the recognition of approximately $27 million in goodwill, which is associated with deferred income tax liabilities. The acquisition has been accounted for using the acquisition method, whereby financial results of the business acquired have been consolidated in the financial statements of Fortis commencing on April 1, 2016. The purchase price allocation was finalized during the first quarter of 2017. There were no material changes in the nature and amount of the Corporation's commitments from those disclosed in the Corporation's 2016 annual audited consolidated financial statements. The Corporation and its subsidiaries are subject to various legal proceedings and claims associated with the ordinary course of business operations. The following describes the nature of the Corporation's contingencies. Prior to and after its acquisition by Fortis, various asbestos lawsuits have been brought against Central Hudson. While a total of 3,365 asbestos cases have been raised, 1,175 remained pending as at June 30, 2017. Of the cases no longer pending against Central Hudson, 2,034 have been dismissed or discontinued without payment by the Company, and Central Hudson has settled the remaining 156 cases. The Company is presently unable to assess the validity of the outstanding asbestos lawsuits; however, based on information known to Central Hudson at this time, including the Company's experience in the settlement and/or dismissal of asbestos cases, Central Hudson believes that the costs that may be incurred in connection with the remaining lawsuits will not have a material effect on its financial position, results of operations or cash flows and, accordingly, no amount has been accrued in the consolidated financial statements. In April 2013 FHI and Fortis were named as defendants in an action in the B.C. Supreme Court by the Coldwater Indian Band ("Band"). The claim is in regard to interests in a pipeline right of way on reserve lands. The pipeline on the right of way was transferred by FHI (then Terasen Inc.) to Kinder Morgan Inc. in April 2007. The Band seeks orders cancelling the right of way and claims damages for wrongful interference with the Band's use and enjoyment of reserve lands. In May 2016 the Federal Court entered a decision dismissing the Coldwater Band's application for judicial review of the ministerial consent. The Band has appealed that decision. The outcome cannot be reasonably determined and estimated at this time and, accordingly, no amount has been accrued in the consolidated financial statements. Following announcement of the acquisition of ITC in February 2016, complaints which named Fortis and other defendants were filed in the Oakland County Circuit Court in the State of Michigan ("Superior Court") and the United States District Court in and for the Eastern District of Michigan. The complaints generally allege, among other things, that the directors of ITC breached their fiduciary duties in connection with the merger agreement and that ITC, Fortis, FortisUS Inc. and Element Acquisition Sub Inc. aided and abetted those purported breaches. The complaints seek class action certification and a variety of relief including, among other things, unspecified damages, and costs, including attorneys' fees and expenses. In July 2016 the federal actions were voluntarily dismissed by the federal plaintiffs. The federal plaintiffs reserved the right to make certain other claims, and ITC and the individual members of the ITC board of directors reserved the right to oppose any such claim. In June 2016 the Superior Court granted a motion for summary disposition dismissing the aiding and abetting claims asserted against Fortis, FortisUS Inc. and Element Acquisition Sub Inc. In January 2017 the defendants filed an additional motion for summary disposition, which was to be heard by the court in March 2017. A hearing on class certification occurred in February 2017. In March 2017 an agreement in principle was reached to settle the case, subject to formal documentation and court approval. The court has stayed the matter, except for all settlement-related proceedings. In May 2017 the court preliminarily approved the settlement and set a final settlement approval hearing for September 2017. Certain comparative figures have been reclassified to comply with current period presentation. To correct the treatment of related-party transactions to be in accordance with accounting standards for rate-regulated entities, Fortis no longer eliminates related-party transactions between non-regulated and regulated entities. As a result, the sale of energy from the Waneta Expansion to FortisBC Electric and the lease of natural gas storage from Aitken Creek to FortisBC Energy are no longer eliminated, increasing both revenue and energy supply costs for the three and six months ended June 30, 2016 by $8 million and $23 million, respectively (Note 4).


News Article | July 27, 2017
Site: www.marketwired.com

All dollar amounts expressed in this news release are in Canadian dollars unless otherwise noted. VANCOUVER, BRITISH COLUMBIA--(Marketwired - July 27, 2017) - Teck Resources Limited (TSX:TECK.A and TECK.B)(NYSE:TECK) ("Teck") reported profit attributable to shareholders of $577 million ($1.00 per share) in the second quarter compared with $15 million ($0.03 per share) a year ago. "I'm pleased with our results," said Don Lindsay, President and CEO. "We generated adjusted EBITDA of $1.3 billion in the second quarter and $5.4 billion over the last twelve months. After a challenging first quarter we set second quarter steelmaking coal sales and production records of 6.9 and 6.8 million tonnes, respectively, and we reduced our outstanding notes to US$4.8 billion, achieving our target of less than US$5 billion." This management's discussion and analysis is dated as at July 26, 2017 and should be read in conjunction with the unaudited consolidated financial statements of Teck Resources Limited ("Teck") and the notes thereto for the three and six months ended June 30, 2017 and with the audited consolidated financial statements of Teck and the notes thereto for the year ended December 31, 2016. In this news release, unless the context otherwise dictates, a reference to "the company" or "us," "we" or "our" refers to Teck and its subsidiaries. Additional information, including our Annual Information Form and Management's Discussion and Analysis for the year ended December 31, 2016, is available on SEDAR at www.sedar.com. This document contains forward-looking statements. Please refer to the cautionary language under the heading "CAUTIONARY STATEMENT ON FORWARD-LOOKING INFORMATION." In the second quarter our operational performance improved. Production for most of our principal products increased. Steelmaking coal production rose to a second quarter record of 6.8 million tonnes, up from 6.1 million tonnes in the first quarter of 2017, and also exceeded the 6.7 million tonnes produced in the second quarter of 2016. However, steelmaking coal unit costs rose as a result of high input costs and our decision to advance annual plant maintenance shutdowns, originally planned for later in the year. As anticipated in the mine plans, copper production in the second quarter rose 9% from the first quarter to 70,000 tonnes as grades at Highland Valley Copper improved. Our zinc in concentrate production rose by 8% from the first quarter as a result of record zinc production from Antamina. In commodity markets, prices moved higher year-over-year with copper, zinc and lead prices rising 20%, 35%, and 26% in U.S. dollars, respectively, from the same period a year ago. Our realized steelmaking coal price in the second quarter doubled from a year ago and averaged US$169 per tonne. Steelmaking coal spot prices retreated from above US$300 per tonne in mid-April after Cyclone Debbie disrupted key Australian supplies and are now trading above US$170 per tonne. The higher commodity prices combined with increased sales volumes for most of our principal products, including record second quarter sales of 6.9 million tonnes of steelmaking coal, contributed to our improved financial results compared with a year ago. We announced the sale of our two-thirds interest in the Waneta Dam and related transmission assets to Fortis for $1.2 billion cash. Under the agreement, we will be granted a 20-year lease with an option to extend for an additional ten years to use Fortis' two-thirds interest in the power generated by Waneta for our Trail Operations. BC Hydro has a right of first offer with respect to the sale of our two-thirds interest in Waneta. Closing of the transaction is subject to receipt of certain consents and other customary conditions and is not expected before the fourth quarter of 2017. Closing of the transaction will further strengthen our balance sheet and provide significant new capital that can be reinvested to enhance our overall business, including our Trail Operations. Construction progress on the Fort Hills oil sands project has surpassed 92%. Four of the six major project areas have now been turned over to operations. The project remains on track to produce first oil in late 2017. We established a new dividend policy that reflects our commitment to return cash to shareholders balanced against the needs and opportunities to invest in, and the inherent cyclicality of, our underlying businesses. The policy will be anchored by an annual base dividend of $0.20 per share, which we intend to declare and pay quarterly, commencing in the third quarter of this year. Each year the Board will review the free cash flow generated by the business, the outlook for business conditions and priorities regarding capital allocation and determine whether a supplemental dividend should be paid. If declared, supplemental dividends may be highly variable from year to year, given the volatility of commodity prices and the potential need to conserve cash for certain project capital expenditures or other corporate priorities. The $0.10 base dividend declared and paid in the second quarter of 2017 reflects the quarterly dividends for both the first and second quarters of 2017. Profit attributable to shareholders was $577 million, or $1.00 per share, in the second quarter compared with $15 million, or $0.03 per share in the same period a year ago. Adjusted profit attributable to shareholders in the second quarter, after adjusting for the items identified in the table below was $577 million, or $1.00 per share, compared with $3 million, or $0.01 per share, in the same period last year. The substantial increase in our profit in the second quarter of 2017 was primarily the result of significantly higher contribution from our steelmaking coal business unit due to higher prices and sales volumes, partly offset by higher unit operating costs. In addition, our profit was also positively affected by higher base metal prices as well as the weaker U.S./Canadian dollar average exchange rate compared with a year ago. In addition to the items described above, our results include gains and losses due to changes in market prices and interest rates in respect of pricing adjustments, commodity derivatives, share based compensation and changes in the discounted value of decommissioning and restoration costs of closed mines. Taken together, these items resulted in a $5 million charge to our after-tax profits ($7 million before tax) in the second quarter, or $0.01 per share. We do not adjust our reported profit for these items as they occur on a regular basis. Our revenues, gross profit before depreciation and amortization, and gross profit by business unit are summarized in the table below. Gross profit in the second quarter from our steelmaking coal business unit was $785 million compared with $52 million a year ago. Gross profit before depreciation and amortization increased by $777 million from a year ago (see table below) as the benefits of significantly higher realized steelmaking coal prices and record second quarter sales of 6.9 million tonnes more than offset the effect of higher unit production costs. The average realized steelmaking coal price of US$169 per tonne was US$86 per tonne higher than the second quarter of 2016, reflecting improved steelmaking coal market conditions and supply constraints in the quarter due to a cyclone in Queensland. Second quarter production of 6.8 million tonnes was slightly higher than the same period a year ago, setting a new record for this quarter of the year. However, production was slightly lower than our expected run rate of approximately 7.0 million tonnes. This was the result of our decision to advance annual processing plant maintenance shutdowns, originally planned for later in the year, into the second quarter. This decision reduced onsite inventories, restoring operational flexibility going forward. With the majority of our processing plant shutdowns behind us, we expect production to be stronger in the second half of 2017. The advancing of plant maintenance activities into the quarter resulted in increased use of contractors and repair parts. Costs also increased relative to the year ago period due to increased strip ratios and cost pressures from labour, diesel, power and natural gas. The table below summarizes the year-over-year gross profit changes, before depreciation and amortization, in our steelmaking coal business unit for the quarter: Property, plant and equipment expenditures totaled $10 million in the second quarter. Capitalized stripping costs were $132 million in the second quarter compared with $76 million a year ago. Record second quarter sales volumes of 6.9 million tonnes were 10% higher than a year ago, reflecting improved steelmaking coal market conditions. This record was achieved despite irregular purchasing during a period of rapidly changing prices in the aftermath of Cyclone Debbie in Queensland, Australia. Very few transactions were observed in the five-week period from mid-April to mid-May when spot prices exceeded US$300 per tonne for the fourth time since 2008. Customers covered short-term requirements and then retreated from the market until spot prices returned nearer to pre cyclone levels. As a result, we also experienced weak sales during that five-week period, slightly reducing total volumes shipped in the quarter. Cyclone Debbie also delayed the quarterly benchmark price negotiations and triggered changes to that pricing system. Steel mills, and the majority of steelmaking coal producers, have now agreed to an index-linked pricing mechanism based on the average of key premium steelmaking coal spot price assessments to replace the negotiated quarterly benchmark, effective April 1, 2017. Lower grade semi-soft coals and PCI coal pricing will continue to be negotiated on a quarterly benchmark basis and we will continue to make spot sales reflecting market conditions as sales are concluded. While the index-linked mechanism varies between customers, we expect our realized price relative to the premium steelmaking coal assessments to be similar to our historical relationship to the negotiated quarterly benchmark. This change in the pricing mechanism affects approximately 40% of our sales and further changes may occur. Our product mix and timing of sales will continue to affect our realized pricing, as was previously the case. Significantly improved logistics performance combined with earlier than planned processing plant maintenance shutdowns have substantially reduced onsite steelmaking coal stockpiles and returned operational flexibility to each of our operations. Unfortunately, challenging winter weather conditions in southern British Columbia and northwestern Alberta, above average employee turnover and geotechnical issues in two pits affected our ability to move planned waste volumes in both of the first two quarters of 2017 and has negatively affected production. We fully anticipate recovering that shortfall in waste volumes through the second half of the year and will be back on plan by year end. Unit cost of sales in the second quarter were $53 per tonne compared with $42 per tonne a year ago, exceeding the top of our guidance range for the quarter of $51 per tonne. The decision to advance scheduled maintenance increased repair and maintenance costs while reducing production. Strip ratios increased, as we are mining in recently permitted areas at a number of our operations, contributing to the cost increases, along with higher labour and energy costs. Higher costs were also attributed to the increased use of contractors to address employee turnover and to accelerate waste removal. In addition, higher equipment utilization resulted in cost increases. The decision to advance scheduled maintenance and reduce production in the quarter allowed us to draw down inventories at the mine sites and provide more flexibility for production and shipping in the second half of the year. The tables below report the components of our unit costs in Canadian and equivalent U.S. dollars. Our total cost of sales for the quarter also included a $12 per tonne charge for the amortization of capitalized stripping costs and $16 per tonne for other depreciation. The markets have stabilized over the past month and we are seeing good demand for our products. Spot prices for top quality products have moved up by more than US$30 per tonne and are currently trading above US$170 per tonne, well up from the lows near US$140 per tonne in mid-June. We expect coal sales in the third quarter of 2017 of at least 7.0 million tonnes. Vessel nominations for contract shipments are determined by customers and final sales and average prices for the quarter will depend on product mix, market direction for spot priced sales, timely arrival of vessels, as well as the performance of the rail transportation network and port-loading facilities. We expect total production for the year in the range of 27 to 27.5 million tonnes. Our previous guidance was 27 to 28 million tonnes. We expect unit cost of sales in the range of $49 to $53 per tonne, up from our previous guidance of $46 to $50 per tonne. Our original guidance for transportation costs remains unchanged at $35 to $37 per tonne. Gross profit from our copper business unit for the quarter was $128 million compared with $62 million a year ago. Gross profit before depreciation and amortization increased by $47 million in the second quarter compared with a year ago (see table below). This was primarily due to higher realized prices and substantially higher zinc sales from Antamina as a result of record zinc production. These items were partially offset by lower copper sales volumes and associated higher unit costs. Copper production declined by 23% from a year ago primarily due to lower ore grades at Highland Valley Copper as anticipated in the mine plan. Production was expected to be lower in the first half of 2017 and is anticipated to gradually improve as the year progresses. Due to the lower copper production and despite continued good site cost performance, our cash unit costs before by-products increased 17% to US$1.69 per pound compared to US$1.44 per pound during the same period a year ago. Significantly higher production of zinc and molybdenum resulted in cash unit costs after by-products decreasing 6% to US$1.26 per pound compared to US$1.34 per pound during the same period last year. The table below summarizes the changes in gross profit, before depreciation and amortization, in our copper business unit for the quarter: Property, plant and equipment expenditures totaled $58 million, including $19 million for sustaining capital and $29 million for new mine development related to the Quebrada Blanca Phase 2 project. Capitalized stripping costs were $35 million in the second quarter, the same as a year ago. London Metal Exchange (LME) copper prices in the second quarter of 2017 averaged US$2.57 per pound, down 3% from the prior quarter but up 20% from the same quarter a year ago. Year to date prices have averaged US$2.61 per pound, a 22% increase over the same period last year. Copper prices peaked in the first quarter at US$2.80 per pound due to production disruptions at two of the world's largest copper mines, but then drifted lower in the second quarter to US$2.45 per pound as production resumed at these mines. An improved outlook for demand in Europe and Asia combined with reported exchange stocks falling during the second quarter by 145,000 tonnes, allowed prices to recover back above US$2.60 per pound by the end of the quarter. Total reported exchange stocks fell 145,850 tonnes during the second quarter to 572,500 tonnes. Total reported global copper exchange stocks are now estimated to be 9.2 days of global consumption, below the estimated 25 year average of 11.9 days of global consumption. Stocks on the LME declined by 42,000 tonnes and stocks at SHFE warehouses also declined 130,000 tonnes and currently stand at 177,000 tonnes, their lowest level since the end of January. The reduction in year to date refined imports into China, lower Chinese domestic production due to smelter maintenance as well as improved domestic consumption, combined to draw down inventories through the second quarter. Mine production disruptions continued from the first quarter into the second quarter with labour disruptions curtailing the majority of production. With several ongoing issues remaining unresolved, the potential for additional unplanned interruptions remains. We expect the lack of investment made over the past six years due to the downtrend in copper prices to constrain new mine production growth to the end of this decade. Copper production was significantly reduced in the second quarter at 21,100 tonnes, or 45% lower than a year ago. This was primarily due to planned lower grades and recoveries as a higher grade phase of the Valley pit was exhausted in 2016 and significantly more lower-grade ore from the Lornex pit was processed than in the same period last year. As previously disclosed, ore grades and recoveries are expected to remain lower than in prior years, but are anticipated to gradually improve as the year progresses. Molybdenum production of 2.2 million pounds was more than twice the production of a year ago due to higher grades. Operating costs, before a $2 million inventory writedown, were $108 million in the second quarter, 5% lower than a year ago. Unit costs rose substantially as a result of lower production. Our labour agreement at Highland Valley Copper expired at the end of the third quarter of 2016 and negotiations are ongoing. A strike vote was approved by union members on July 16, 2017, but no strike notice has yet been delivered to the company. Antamina processed significantly less copper-only ore while the processing of copper-zinc ore almost tripled from the same period a year ago, which was anticipated in the mine plan. The mix of mill feed in the quarter was 58% copper-only ore and 42% copper-zinc ore, compared with 87% and 13% respectively a year ago. As a result, copper production in the second quarter of 118,500 tonnes was similar to a year ago, while second quarter zinc production increased by 79,500 tonnes to a record 102,300 tonnes, primarily due to increased processing of copper-zinc ores combined with higher grades and recoveries. Operating costs in the second quarter, as reported in U.S. dollars, were 6% higher than a year ago, primarily due to processing more copper-zinc ores and higher maintenance costs. Copper production in the second quarter of 17,000 tonnes was similar to a year ago as improved grades were offset by lower mill throughput. Operating costs rose by US$5 million in the second quarter compared with a year ago due to higher milling costs related to processing harder ore and the timing of maintenance activities. As previously announced, all supergene ore mined is now being sent directly to the dump leach circuit. This results in lower recovery and a longer leaching cycle at reduced operating costs. As a result of these changes, copper production in the second quarter decreased by 37% to 5,300 tonnes compared with a year ago. Operating costs in the second quarter were US$13 million lower than a year ago, primarily as a result of suspending the crushing, agglomeration and stacking circuits associated with the previous heap leaching operation. Depreciation and amortization charges decreased by $18 million compared to a year ago as a result of lower production levels. Unit cash costs of product sold in the second quarter of 2017 as reported in U.S. dollars, before cash margins for by-products, were US$1.69 per pound compared to US$1.44 per pound in the same period a year ago. The higher unit costs were primarily due to the significant decline in production at Highland Valley Copper as a result of lower grades. Cash margin for by-products increased significantly to US$0.43 per pound compared with US$0.10 per pound in the same period a year ago. This was primarily due to higher zinc prices as well as significantly higher sales volumes of zinc from Antamina and molybdenum from Highland Valley Copper. The higher by-product credits more than offset the significantly lower copper production in the quarter resulting in unit cash costs for copper, after by-products, of US$1.26 per pound compared to US$1.34 in the same period a year ago. Project activities during the quarter focused primarily on execution readiness activities including advancing detailed engineering and design, as well as continuing progress on the Social and Environmental Impact Assessment (SEIA) regulatory approval process. Quebrada Blanca Phase 2 is expected to have an annual production capacity of 300,000 tonnes of copper equivalent production per year for the first five years of mine life, equating to a capital intensity of approximately US$16,000 per annual tonne. A decision to proceed with development would be contingent upon regulatory approvals and market conditions, among other considerations. Given the timeline of the regulatory process, such a decision is not expected before mid-2018. Activities continued to advance the pre-feasibility study in the quarter, including environmental baseline studies and ongoing community engagement with indigenous and non-indigenous communities. We expect to complete the pre-feasibility study by the end of the fourth quarter of 2017. In March 2017, we launched our Project Satellite initiative, the focus of which is to surface value from five substantial base metals assets - Zafranal, San Nicolás, Galore Creek, Schaft Creek, and Mesaba - all of which are located in stable mining-friendly jurisdictions in the Americas. Our approach is to work with existing and potentially new partners on appropriate and prudently-funded work to advance engineering and design as well as social and environmental activities. Value capture could be achieved through various commercial or development options, including full divestment, further investment by Teck, partnering, vend-in or public offering. In January 2017, we increased our ownership of Compañia Minera Zafranal S.A.C., which owns the Zafranal copper-gold project located in Southern Peru, to 80% through an acquisition of all of the outstanding shares of AQM Copper Inc. not already owned by us. Additional drilling and engineering studies began in the second quarter along with additional community engagement activities, environmental and archaeological studies, and permitting work necessary to potentially prepare an Environmental Impact Assessment and initiate a Feasibility Study of the project. On June 29, 2017, we entered into an agreement with Goldcorp Inc. to acquire their 21% interest in the San Nicolás copper-zinc asset for cash consideration of US$50 million. As a result of the transaction, we will hold a 100% interest in the San Nicolás copper-zinc asset. The transaction is expected to close before the end of 2017. Planning for the environmental and social baseline studies and hydrologic and hydrogeological studies began in the second quarter, along with early community engagement work and drill program planning in support of preparation and submission of an Environmental Impact Assessment. We continue to expect 2017 copper production to be in the range of 275,000 to 290,000 tonnes and full year copper unit costs to be in the range of US$1.75 to US$1.85 per pound before margins from by-products and US$1.40 to US$1.50 per pound after by-products. Full year molybdenum production at Highland Valley Copper is also unchanged at 6.0 to 6.5 million pounds contained in concentrate. Gross profit from our zinc business unit was $153 million in the second quarter compared with $99 million a year ago. Gross profit before depreciation and amortization increased by $65 million due primarily to higher zinc prices. Refined zinc production at our Trail Operations was 6% higher than the same period a year ago primarily due to higher feed rates. At Red Dog, zinc production was 16% lower than the same period a year ago due to lower zinc grade and recoveries, which were partially offset by higher mill throughput. The table below summarizes the gross profit change, before depreciation and amortization, in our zinc business unit for the quarter in comparison to the same period in 2016. Property, plant and equipment expenditures include $42 million for sustaining capital, which included $29 million at Trail Operations and $11 million at Red Dog. LME zinc prices averaged US$1.18 per pound in the second quarter of 2017, a decrease of 7% from the first quarter, but 35% higher than the second quarter of 2016. Year to date LME zinc prices have averaged US$1.22 per pound, up US$0.40 per pound or 50% over the same period last year. Total reported zinc exchange stocks fell 198,800 tonnes during the second quarter to 356,180 tonnes. Total exchange stocks are down almost 300,000 tonnes from the same point last year and are now estimated at 9.5 days of global consumption, well below the 25 year average of 23.4 days. Global demand for refined zinc remained strong in the second quarter of 2017 with galvanized steel production up 4.6% year to date over the same period last year according to CRU. In China, CRU estimates that galvanized steel production rose 8.1% in the first half of 2017 compared with the same period last year. Galvanized steel prices have fallen slightly in the quarter in most regions. Slightly lower, but still-steady, demand contributed to this as well as higher imports in the U.S. Wood Mackenzie is forecasting an increase in global refined zinc demand in 2017 of 3.0% to 14.7 million tonnes, and that refined zinc production will be limited to a 2.0% increase, to 13.8 million tonnes, leaving the market in deficit again this year. Even with mine production increases, production is not keeping pace with prior smelter capacity growth, leaving refined zinc production constrained by lack of concentrates. A series of smelter maintenance shutdowns at the end of the first quarter and into the second provided temporary relief to the smelters with spot treatment charges rising slightly in China. However, as smelter production comes back on line, concentrate availability will again be limited by near-term supply. We remain of the view that zinc prices are likely to remain strong in the short and medium-term. Zinc production of 127,800 tonnes in the second quarter was 16% lower than the same period a year ago primarily due to lower grades and recoveries which were partially offset by higher mill throughput. Lead production increased 17% compared to last year, primarily due to higher grades. During the quarter, we lowered the amount of higher-grade Qanaiyaq ore processed as this ore is metallurgically complex, particularly in the early stages of pit development where ores are highly oxidized. Qanaiyaq ore is expected to become less oxidized as the pit is deepened, and we expect to include more of this higher grade material in the feed as we gain more processing experience with this ore. Zinc sales of 83,300 tonnes in the second quarter were slightly ahead of our guidance for the quarter as smelters continued to accelerate the treatment of inventory due to the general tightness in the global concentrate market. This tightness is reflected in spot treatment charges, which continue to be significantly below annual contract terms. Offsite zinc inventory available for sale as of July 1, 2017 was approximately 28,000 tonnes of contained metal. Operating costs in the second quarter of US$20 million were the same as a year ago. Capitalized stripping costs were US$5 million in the second quarter compared with US$9 million a year ago due to reduced waste movement. Refined zinc production of 73,400 tonnes in the second quarter was 6% higher than the same period a year ago as higher feed rates were partially offset by increases in in-process inventories. Refined lead production was 17% lower in the second quarter compared with a year ago. This was partly due to an increase in maintenance downtime and changes to the feed mix due to operating disruptions at some mines that supply lead concentrates, which required alternative concentrates to be processed. Silver production was also affected, resulting in production being 8% lower than a year ago. Operating costs in the second quarter of $111 million were $14 million higher than a year ago, primarily as a result of increased energy prices and repair expenses. Sustaining capital expenditures in the quarter included $16 million for advancing the Number 2 Acid Plant and $13 million for various small projects. A mediated settlement for a new five-year collective agreement is currently in the voting process for unionized employees at Trail Operations. Zinc production during the second quarter of 7,200 tonnes was 9% lower than a year ago due to lower mill throughput, partially offset by higher grades. The current mine plan sustains the operation through to early 2018, although there is still significant potential to extend the mine life. In 2016, we identified highly prospective areas in the currently producing East Mine area and we are continuing a major exploration and drilling program with good success so far. We continue to expect zinc in concentrate production in 2017, including co-product zinc production from our copper business unit, to be in the range of 590,000 to 615,000 tonnes. The Red Dog concentrate shipping season commenced on July 1, with the first sailing on July 4. We expect sales of 145,000 tonnes of contained zinc in the third quarter and 165,000 tonnes in the fourth quarter, reflecting the normal seasonal pattern of Red Dog sales. In accordance with the operating agreement governing the Red Dog mine between Teck and NANA Regional Corporation Inc. (NANA), we currently pay a 30% royalty on net proceeds of production to NANA. This royalty increases by 5% every fifth year to a maximum of 50%, with the next adjustment to 35% occurring in the fourth quarter of 2017. Overall construction of the Fort Hills oil sands project has surpassed 92% completion. Four of the six major project areas (mining, ore preparation plant, primary extraction and infrastructure) have been turned over to operations. The construction of utilities is greater than 95% complete and the focus is on mechanical completion and commissioning. First oil facilities in secondary extraction are 81% complete. At the end of the second quarter, over 90% of this year's budgeted operations personnel had been hired. In September, Suncor plans to initiate froth production in order to accelerate plant commissioning. In the second quarter, our share of capital expenditures was $201 million. Our share of Fort Hills cash expenditures in 2017 is estimated at $780 million. A disagreement has recently arisen among the Fort Hills partners regarding future funding for the project and discussions are ongoing regarding the partners' relative funding obligations. Suncor advises that the disagreement is not expected to affect the plan to achieve first oil by the end of 2017. Oil production from the first of three secondary extraction units is expected near the end of 2017. The other two secondary extraction units are scheduled to be completed and commissioned in the first half of 2018 and production is expected to reach 90% of nameplate capacity by the end of 2018. Suncor, as the operator of the Fort Hills project, is also exploring the opportunity to reduce the ramp-up period. The Fort Hills partners have executed long-term blend service and pipeline transportation agreements for the delivery of diluent from Edmonton to Fort Hills and blended bitumen to Hardisty from Fort Hills. Construction activities for the regional bitumen, diluent and blend pipelines and the East Tank Farm blending facility are complete and will be in service prior to mine start-up. Each Fort Hills partner will be responsible for meeting its diluent blend requirements, transporting and selling its share of diluted bitumen to the market. The development of our comprehensive diluent acquisition and blended bitumen sales strategies is ongoing and we continue to review options to sell diluted bitumen into the North American and overseas markets. Fort Hills blended bitumen is anticipated to have similar quality characteristics to production recently introduced into the marketplace from other large-scale oil sands mining projects. Our share of Fort Hills production will be marketed through a combination of long and short-term contracts. To this end, we are currently reviewing draft contract provisions with prospective customers. In support of our diverse market access strategy, we have contracted for 425,000 blended bitumen barrels of terminal storage at Hardisty. The regulatory review for Frontier is continuing with a federal-provincial panel reviewing information filed to date. The process is expected to continue through 2017, making 2018 the earliest a federal decision statement is expected, for Frontier. Our expenditures are limited to supporting this process. We are evaluating 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 $45 million in the second quarter compared with $28 million a year ago. The most significant of these items was $21 million of commodity derivative losses related to derivatives embedded in our gold and silver streaming agreements and to our zinc and lead positions related to Red Dog, which matches our economic exposure to the average zinc and lead prices over our shipping season. Pricing adjustments in the current quarter and prior year were minimal, as copper and zinc prices were relatively unchanged during those quarters. The table below outlines our outstanding receivable positions, provisionally valued at June 30, 2017 and March 31, 2017. Our finance expense of $59 million in the second quarter decreased by $25 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 was due to a higher amount of interest capitalized against our development projects, including $40 million for Fort Hills and $38 million for Quebrada Blanca Phase 2, reflecting our increased carrying values of both of these projects compared with a year ago and lower debt interest as a result of lower outstanding debt balances. Interest capitalization will cease when each project reaches completion. These were partly offset by higher letter of credit fees and accretion on our decommissioning and restoration provisions. Non-operating expense in the second quarter of 2017 was $4 million, which included a $38 million loss on the repurchase of our debt, partly offset by foreign exchange gains of $10 million and a $23 million gain on the revaluation of our call options on certain long-term debt notes. Income and resource taxes for the second quarter were $330 million, or 36% of pre-tax profits. This rate is higher than the Canadian statutory rate of 26% as a result of resource taxes and higher rates in 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: In the first half of 2017, we retired US$1.3 billion of our term notes pursuant to cash tender offers, make-whole redemptions and open market repurchases, of which US$260 million was completed in the second quarter. As a result, the principal balance of our public notes is now US$4.8 billion. At June 30, 2017 our debt to debt-plus-equity ratio was 26%. Our committed credit facilities comprised of a US$3.0 billion revolving credit facility maturing July 2020 and a US$1.2 billion revolving credit facility maturing June 2019. As at June 30, 2017, there were no amounts outstanding under the US$3.0 billion facility and US$804 million of letters of credit were outstanding under the US$1.2 billion facility. Of those letters of credit, an aggregate of US$672 million were issued in respect of long-term power purchase agreements for the Quebrada Blanca Phase 2 project and $167 million in respect of long-term transport service agreements for our share of the Fort Hills oil sands project. We also have various other credit facilities and arrangements that secure our reclamation obligations in the amount of approximately $1.9 billion. We may be required to post additional security in respect of reclamation at our sites in future periods as regulatory requirements change and closure plans are updated. Cash flow from operations was $1.4 billion in the second quarter compared with $339 million a year ago with the increase primarily due to substantially higher steelmaking coal prices and sales volumes. Changes in working capital items provided a source of funds of $382 million in the second quarter compared with a use of cash of $109 million a year ago. The source of cash in the quarter was primarily due to a reduction in accounts receivables in our steelmaking coal business unit. With the settlement of the second quarter's steelmaking coal prices, provisional payments of US$144 million made by our customers on second quarter coal sales will be repaid in the third quarter of the year. Expenditures on property, plant and equipment were $329 million in the second quarter, including $201 million of new mine development for the Fort Hills oil sands project, $71 million on sustaining capital and $11 million on major enhancement projects. The largest components of sustaining expenditures were $29 million at our Trail Operations and $11 million each at Antamina and Red Dog. Capitalized production stripping costs were $173 million in the second quarter compared with $122 million a year ago. The majority of this item represents the advancement of pits for future production at our steelmaking coal mines. The table below summarizes our year-to-date capital spending for 2017: In the second quarter we repurchased US$260 million principal amount of our outstanding notes by way of make-whole redemptions and open market repurchases, reducing the balance of our outstanding notes to US$4.8 billion. Debt interest and finance charges paid were $87 million in the second quarter compared with $74 million a year ago. The sales of our products are denominated in U.S. dollars, while a significant portion of our expenses are incurred in local currencies, particularly the Canadian dollar and the Chilean peso. Foreign exchange fluctuations can have a significant effect on our operating margins, unless such fluctuations are offset by related changes to commodity prices. Our U.S. dollar denominated debt is subject to revaluation based on changes in the Canadian/U.S. dollar exchange rate. As at June 30, 2017, $4.2 billion of our U.S. dollar denominated debt is designated as a hedge against our foreign operations that have a U.S. dollar functional currency. As a result, any foreign exchange gains or losses arising on that amount of our U.S. dollar debt are recorded in other comprehensive income, with the remainder being charged to profit. We hold a number of financial instruments and derivatives which are recorded on our balance sheet at fair value with gains and losses in each period included in other comprehensive income and profit for the period as appropriate. The most significant of these instruments are marketable securities, metal-related forward contracts including those embedded in our silver and gold streaming agreements, and settlements receivable and payable, and prepayment rights on certain long-term debt notes. Some of our gains and losses on metal-related financial instruments are affected by smelter price participation and are taken into account in determining royalties and other expenses. All are subject to varying rates of taxation depending on their nature and jurisdiction. ADOPTION OF NEW ACCOUNTING STANDARDS AND ACCOUNTING DEVELOPMENTS New IFRS pronouncements that have been issued but are not yet effective are listed below. We plan to apply the new standards or interpretations in the annual period for which they are first required. In May 2014, the IASB issued IFRS 15, Revenue from Contracts with Customers (IFRS 15) as a result of a joint revenue project with the Financial Accounting Standards Board (FASB). The new revenue standard introduces a single principles-based five-step model for the recognition of revenue when control of goods is transferred to, or a service is performed, for the customer. The five steps are to: identify the contract(s) with the customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price, and recognize revenue when the performance obligation is satisfied. IFRS 15 also requires enhanced disclosures about revenue to help investors better understand the nature, amount, timing and uncertainty of revenue and cash flows from contracts with customers. The standard initially has an effective date of January 1, 2018. We are required to adopt the provisions of IFRS 15 on either a full or modified retrospective basis. We are currently assessing our transition approach and expect to make a determination by the third quarter of 2017. As at June 30, 2017 we have gathered relevant facts and identified our significant revenue contracts. Through the evaluation of the facts and contracts, we have established possible areas where changes to revenue recognition or presentation may be required. This issue identification has provided a framework for our contract review. We will continue to perform our contract review process and evaluate possible areas of change as identified in the third quarter of 2017. The most significant item that we are continuing to review is in relation to the treatment of insurance and freight costs. In many of our sales contracts, we are responsible for arranging shipping and insurance services which occur after the date at which control of the product passes to the customer. Under IFRS 15, these services likely represent a separate performance obligation which would require separate accounting and disclosure. We are also evaluating whether we are a principal or an agent to these transactions and consequently whether the revenue should be reported on a gross or net basis, which is a presentation issue only on our statement of income. We are also evaluating whether there is any effect of IFRS 15 on our gold and silver streaming arrangements. In addition to potential changes in recognition and measurement, IFRS 15 will require additional financial statement disclosures about revenue from contracts with customers than is currently required under existing IFRS. Once we complete our accounting analysis, we will focus on updating systems and processes to facilitate this additional reporting as well as any changes relating to revenue recognition that may be required. IFRS 9, Financial Instruments (IFRS 9), addresses the classification, measurement and recognition of financial assets and financial liabilities. The July 2014 publication of IFRS 9 is the completed version of the standard, replacing earlier versions of IFRS 9 and superseding the guidance relating to the classification and measurement of financial instruments in IAS 39, Financial Instruments: Recognition and Measurement (IAS 39). IFRS 9 requires financial assets to be classified into three measurement categories on initial recognition: those measured at fair value through profit and loss, those measured at fair value through other comprehensive income and those measured at amortized cost. Investments in equity instruments are required to be measured by default at fair value through profit or loss. However, there is an irrevocable option for each equity instrument to present fair value changes in other comprehensive income. Measurement and classification of financial assets is dependent on the entity's business model for managing the financial assets and the contractual cash flow characteristics of the financial asset. For financial liabilities, the standard retains most of the IAS 39 requirements. The main change is that, in cases where the fair value option is taken for financial liabilities, the part of a fair value change relating to an entity's own credit risk is recorded in other comprehensive income rather than the income statement, unless this creates an accounting mismatch. IFRS 9 introduces a new three-stage expected credit loss model for calculating impairment for financial assets. IFRS 9 no longer requires a triggering event to have occurred before credit losses are recognized. An entity is required to recognize expected credit losses when financial instruments are initially recognized and to update the amount of expected credit losses recognized at each reporting date to reflect changes in the credit risk of the financial instruments. In addition, IFRS 9 requires additional disclosure requirements about expected credit losses and credit risk. The new hedge accounting model in IFRS 9 aligns hedge accounting with risk management activities undertaken by an entity. Components of both financial and non-financial items will now be eligible for hedge accounting, as long as the risk component can be identified and measured. The hedge accounting model includes eligibility criteria that must be met, but these criteria are based on an economic assessment of the strength of the hedging relationship. New disclosure requirements relating to hedge accounting will be required and are meant to simplify existing disclosures. The IASB currently has a separate project on macro hedging activities and until the project is completed, the IASB has provided a policy choice for entities to either apply the hedge accounting model in IFRS 9 or IAS 39 in full. Additionally, there is a hybrid option to use IAS 39 to account for macro hedges only and to use IFRS 9 for all other hedges. The completed version of IFRS 9 is effective for us on January 1, 2018. We are currently assessing the effect of this standard and its related amendments on our financial statements. As at June 30, 2017, we have completed our initial review of the new standard and have identified a limited number of potential differences relevant to Teck. In particular, we are reviewing our portfolio of investments to consider the application of the irrevocable classification choice related to fair value changes and we are reviewing our processes for managing and estimating provisions for credit loss on our trade receivables. At this stage, we do not expect this standard to have a material effect on our financial statements. In January 2016, the IASB issued IFRS 16, Leases (IFRS 16), which eliminates the classification of leases as either operating or finance leases for a lessee. Under IFRS 16, all leases are considered finance leases and will be recorded on the balance sheet. The only exemptions to this classification will be for leases that are 12 months or less in duration or for leases of low-value assets. The requirement to record all leases as finance leases under IFRS 16 will increase lease assets and lease liabilities on an entity's financial statements. IFRS 16 will also change the nature of expenses relating to leases as the straight-line lease expense previously recognized for operating leases will be replaced with depreciation expense for lease assets and finance expense for lease liabilities. IFRS 16 includes an overall disclosure objective and requires a company to disclose (a) information about lease assets and expenses and cash flows related to leases; (b) a maturity analysis of lease liabilities; and (c) any additional company-specific information that is relevant to satisfying the disclosure objective. IFRS 16 is effective from January 1, 2019 and can be applied before that date but only if IFRS 15 is also applied. We are currently assessing the effect of this standard on our financial statements. As at June 30, 2017, we have developed an understanding of the requirements of IFRS 16 but have not commenced analysis of existing arrangements or possible changes that may result from adoption of IFRS 16. As at July 26, 2017 there were 570.0 million Class B subordinate voting shares and 7.8 million Class A common shares outstanding. In addition, there were approximately 24 million stock options outstanding with exercise prices ranging between $4.15 and $58.80 per share. More information on these instruments and the terms of their conversion is set out in Note 21 of our 2016 audited financial statements. Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Any system of internal control over financial reporting, no matter how well designed, has inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. There have been no significant changes in our internal controls during the quarter ended June 30, 2017 that have materially affected, or are reasonably likely to materially affect, internal control over financial reporting. In preparing consolidated financial statements, management makes estimates that affect the reported amounts of assets, liabilities, revenue and expenses across all reportable segments. Management makes estimates that are believed to be reasonable under the circumstances. Our estimates are based on historical experience and other factors we consider to be reasonable, including expectations of future events. Critical accounting estimates are those that could affect the consolidated financial statements materially, are highly uncertain and where changes are reasonably likely to occur from period to period. Our critical accounting estimates that have a risk of resulting in a material adjustment to the carrying amounts of assets and liabilities within the next year include the recoverable amounts of long-lived assets, fair value of embedded derivatives associated with streaming transactions, estimated recoverable reserves and resources and the valuation of other assets and liabilities such as decommissioning and restoration provisions and the accounting for income taxes. These critical accounting estimates are consistent with those outlined in more detail in our 2016 annual consolidated financial statements and Management's Discussion and Analysis. Our revenue and gross profit by business unit are summarized in the tables below: Our cost of sales information by business unit is summarized in the tables below: Production statistics for each of our operations are presented in the tables below. Operating results are on a 100% basis. USE OF NON-GAAP FINANCIAL MEASURES Our financial results are prepared in accordance with International Financial Reporting Standards (IFRS). This document refers to adjusted profit, adjusted earnings per share, EBITDA, adjusted EBITDA, gross profit before depreciation and amortization, gross profit margins before depreciation, cash unit costs, adjusted cash costs of sales, cash margins for by-products, adjusted revenue, net debt, debt to debt-plus-equity ratio, and the net debt to net debt-plus-equity ratio, which are not measures recognized under IFRS in Canada and do not have a standardized meaning prescribed by IFRS or Generally Accepted Accounting Principles (GAAP) in the United States. For adjusted profit, we adjust profit attributable to shareholders as reported to remove the effect (after taxes) of certain types of transactions that in our judgment are not indicative of our normal operating activities or do not necessarily occur on a regular basis. EBITDA is profit attributable to shareholders before net finance expense, income and resource taxes, and depreciation and amortization. Adjusted EBITDA is EBITDA before the pre-tax effect of the adjustments that we make to profit attributable to shareholders described above. These adjustments to profit attributable to shareholders and EBITDA highlight items and allow us and readers to analyze the rest of our results more clearly. We believe that disclosing these measures assist readers in understanding the ongoing cash generating potential of our business in order to provide liquidity to fund working capital needs, service outstanding debt, fund future capital expenditures and investment opportunities, and pay dividends. Gross profit before depreciation and amortization is gross profit with the depreciation and amortization expense added back. Gross profit margins before depreciation are gross profit before depreciation and amortization, divided by revenue for each respective business unit. Unit costs are calculated by dividing the cost of sales for the principal product by sales volumes. We include this information as it is frequently requested by investors and investment analysts who use it to assess our cost structure and margins and compare it to similar information provided by many companies in our industry. We sell both copper concentrates and refined copper cathodes. The price for concentrates sold to smelters is based on average London Metal Exchange prices over a defined quotational period, from which processing and refining deductions are made. In addition, we are paid for an agreed percentage of the copper contained in concentrates, which constitutes payable pounds. Adjusted revenue excludes the revenue from co-products and by-products, but adds back the processing and refining allowances to arrive at the value of the underlying payable pounds of copper. Readers may compare this on a per unit basis with the price of copper on the LME. Adjusted cash cost of sales for our steelmaking coal operations is defined as the cost of the product as it leaves the mine excluding depreciation and amortization charges. Adjusted cash cost of sales for our copper operations is defined as the cost of the product delivered to the port of shipment, excluding depreciation and amortization charges. It is common practice in the industry to exclude depreciation and amortization as these costs are 'non-cash' and discounted cash flow valuation models used in the industry substitute expectations of future capital spending for these amounts. In order to arrive at adjusted cash costs of sales for copper we also deduct the costs of by-products and co-products. Total cash unit costs include the smelter and refining allowances added back in determining adjusted revenue. This presentation allows a comparison of unit costs, including smelter allowances, to the underlying price of copper in order to assess the margin. Unit costs, after deducting co-product and by-product margins, are also a common industry measure. By deducting the co- and by-product margin per unit of the principal product, the margin for the mine on a per unit basis may be presented in a single metric for comparison to other operations. Readers should be aware that this metric, by excluding certain items and reclassifying cost and revenue items, distorts our actual production costs as determined under GAAP. Net debt is total debt less cash and cash equivalents. The debt to debt-plus-equity ratio takes total debt as reported and divides that by the sum of total debt plus total equity. The net debt to net debt-plus-equity ratio is net debt divided by the sum of net debt plus total equity, expressed as a percentage. These measures are disclosed as we believe they provide readers with information that allows them to assess our credit capacity and the ability to meet our short and long-term financial obligations. The measures described above do not have standardized meanings under IFRS, may differ from those used by other issuers, and may not be comparable to such measures as reported by others. These measures have been derived from our financial statements and applied on a consistent basis as appropriate. We disclose these measures because we believe they assist readers in understanding the results of our operations and financial position and are meant to provide further information about our financial results to investors. These measures should not be considered in isolation or used in substitute for other measures of performance prepared in accordance with IFRS. Reconciliation of Earnings per share to Adjusted Earnings per share Reconciliation of Gross Profit Before Depreciation and Amortization This news release contains certain forward-looking information and forward-looking statements as defined in applicable securities laws (collectively referred to in this news release as "forward-looking statements"). All statements other than statements of historical fact are forward-looking statements. Forward-looking statements involve known and unknown risks, uncertainties and other factors which may cause the actual results, performance or achievements of Teck to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. These forward-looking statements, including under the headings "Outlook," that appear in various places in this release, include estimates, forecasts, and statements as to management's expectations with respect to, among other things, anticipated cost and production forecasts at our business units and individual operations and expectation that we will meet our production guidance, sales volume and selling prices for our products (including settlement of steelmaking coal contracts with customers), our expectations regarding future dividends, the timing of the closing of the Waneta Dam sale, expectation that coal production will improve in the second half of the year, the expectation that our realized price for premium steelmaking coal under the evolving index-linked pricing system will be similar to our historical relationship to the quarterly benchmark, anticipation of recovery in shortfall in coal waste volumes, expectation that copper production will increase in the second half of the year, plans and expectations for our development projects, expectation that grades at Highland Valley Copper will improve, expected production capacity of Quebrada Blanca Phase 2, goal of surfacing value through our Project Satellite initiative, the impact of currency exchange rates, the expected timing and amount of production at the Fort Hills oil sands project, total Fort Hills project capital costs, the expected amount and timing of Teck's share of costs, the expectation that the Fort Hills plan to achieve first oil by the end of 2017 will not be affected by the disagreement among the Fort Hills partners regarding future funding, the timing of completion and commissioning of the secondary extraction units, the expected timing of achieving 90% of the expected production rate and demand and market outlook for commodities. These forward-looking statements involve numerous assumptions, risks and uncertainties and actual results may vary materially. These statements are based on a number of assumptions, including, but not limited to, assumptions regarding general business and economic conditions, the supply and demand for, deliveries of, and the level and volatility of prices of, zinc, copper and steelmaking coal and other primary metals and minerals as well as oil, and related products, the timing of the receipt of regulatory and governmental approvals for our development projects and other operations, our costs of production and production and productivity levels, as well as those of our competitors, power prices, continuing availability of water and power resources for our operations, market competition, the accuracy of our reserve estimates (including with respect to size, grade and recoverability) and the geological, operational and price assumptions on which these are based, conditions in financial markets, the future financial performance of the company, our ability to attract and retain skilled staff, our ability to procure equipment and operating supplies, positive results from the studies on our expansion projects, our steelmaking coal and other product inventories, our ability to secure adequate transportation for our products, our ability to obtain permits for our operations and expansions, our ongoing relations with our employees and business partners and joint venturers, and an assumption that no strike will take place at our Highland Valley Copper or Trail Operations. Assumptions regarding Quebrada Blanca Phase 2 are based on current project assumptions and the final feasibility study. Assumptions regarding Fort Hills are based on the approved project development plan and the assumption that the project will be developed and operated in accordance with that plan, assumptions regarding the performance of the plant and other facilities at Fort Hills and the operation of the project, as well as the assumption that the future funding discussions will not impact the plan to achieve first oil by the end of 2017. Assumptions regarding the impact of foreign exchange are based on current commodity prices. The foregoing list of assumptions is not exhaustive. Events or circumstances could cause actual results to vary materially. Factors that may cause actual results to vary materially include, but are not limited to, changes in commodity and power prices, changes in market demand for our products, changes in interest and currency exchange rates, acts of foreign governments and the outcome of legal proceedings, inaccurate geological and metallurgical assumptions (including with respect to the size, grade and recoverability of mineral reserves and resources), unanticipated operational difficulties (including failure of plant, equipment or processes to operate in accordance with specifications or expectations, cost escalation, unavailability of materials and equipment, government action or delays in the receipt of government approvals, industrial disturbances or other job action, adverse weather conditions and unanticipated events related to health, safety and environmental matters), union labour disputes, political risk, social unrest, failure of customers or counterparties (including logistics suppliers) to perform their contractual obligations, changes in our credit ratings, unanticipated increases in costs to construct our development projects, difficulty in obtaining permits, inability to address concerns regarding permits of environmental impact assessments, and changes or further deterioration in general economic conditions. A strike or lockout at our Highland Valley Copper or Trail Operations may cause our copper or zinc production to vary from our projections. Our Fort Hills project is not controlled by us and construction and production schedules and costs may be adjusted by our partners, and timing of spending and construction is not in our control. Statements concerning future production costs or volumes are based on numerous assumptions of management regarding operating matters and on assumptions that demand for products develops as anticipated, that customers and other counterparties perform their contractual obligations, that operating and capital plans will not be disrupted by issues such as mechanical failure, unavailability of parts and supplies, labour disturbances, interruption in transportation or utilities, adverse weather conditions, and that there are no material unanticipated variations in the cost of energy or supplies. Statements regarding anticipated steelmaking coal sales volumes and average steelmaking coal prices for the second quarter depend on timely arrival of vessels and performance of our steelmaking coal-loading facilities, as well as the level of spot pricing sales. We assume no obligation to update forward-looking statements except as required under securities laws. Further information concerning risks and uncertainties associated with these forward-looking statements and our business can be found in our Annual Information Form for the year ended December 31, 2016, filed under our profile on SEDAR (www.sedar.com) and on EDGAR (www.sec.gov) under cover of Form 40-F. Teck will host an Investor Conference Call to discuss its Q2/2017 financial results at 11:00 AM Eastern time, 8:00 AM Pacific time, on Thursday, July 27, 2017. A live audio webcast of the conference call, together with supporting presentation slides, will be available at our website at www.teck.com. The webcast will be archived at www.teck.com We prepare our annual consolidated financial statements in accordance with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB). These condensed interim consolidated financial statements have been prepared in accordance with IAS 34, Interim Financial Reporting (IAS 34). These condensed interim consolidated financial statements follow the same accounting policies and methods of application as our most recent annual financial statements. Accordingly, they should be read in conjunction with our most recent annual financial statements. On July 26, 2017, the Audit Committee of the Board of Directors authorized these financial statements for issuance. During the second quarter of 2017, we announced an agreement to sell our two-thirds interest in the Waneta Dam and related transmission assets for $1.2 billion cash to Fortis Inc. (Fortis). Under the agreement, we will be granted a 20-year lease with an option to extend for an additional ten years to use Fortis' two-thirds interest in Waneta which entitles us to power for our Trail Operations. The closing of the transaction is subject to receipt of certain consents and other customary conditions and is not expected before the fourth quarter of 2017. BC Hydro has a right of first refusal in respect of the transaction. We have reclassified the carrying value of the Waneta Dam and related transmission assets to "assets held for sale" in accordance with the requirements of IFRS 5, Non-current Assets Held for Sale and Discontinued Operations. There were no adjustments required to the carrying amount of the Waneta Dam on reclassification to assets held for sale as the fair value less costs of disposal exceed the carrying amount. The Waneta Dam is a hydro-electric dam that is located near the Trail smelter. We hold a two-thirds interest in the Waneta Dam and report this asset in our zinc operating segment. The fair values of debt are determined using market values, if available, and discounted cash flows based on our cost of borrowing where market values are not available. The latter are considered Level 2 fair value measurements with significant other observable inputs on the fair value hierarchy (Note 11). During the first two quarters of 2017, we purchased US$1.26 billion aggregate principal amount of our outstanding notes pursuant to cash tender offers, make-whole redemptions and open-market purchases of which US$260 million was purchased in the second quarter. The principal amount of notes purchased was US$278 million of 3.00% notes due 2019, US$280 million of 4.50% notes due January 2021, US$650 million of 8.00% notes due June 2021 (June 2021 notes), US$28 million of 4.75% notes due 2022 and US$24 million of 3.75% notes due 2023. The total cost of the purchases, which was funded from cash on hand, including the premiums, was US$1.36 billion. We recorded a pre-tax accounting charge of $216 million ($159 million after-tax) in non-operating income (expense) (Note 4) in connection with these purchases, of which $38 million ($27 million after-tax) related to the second quarter purchases. The accounting charge of $216 million included $75 million relating to the write-off of the prepayment option recorded in other assets for the June 2021 notes (Note 6(b)). The June 2021 notes and 2024 notes include prepayment options that are considered to be embedded derivatives. During the second quarter, the aggregate principal amount of the outstanding June 2021 notes was purchased and the prepayment option asset was written off (Note 6(a)). At June 30, 2017, the prepayment option included in the 2024 notes is recorded as other assets on the balance sheet at a fair value of $105 million, based on current market interest rates for a similar instrument and our credit spread. For the three months ended June 30, 2017, the value of the 2024 prepayment option and the June 2021 prepayment option, up to the date of purchase, increased by $23 million, which has been recorded as a gain in non-operating income (expense) (Note 4). At June 30, 2017, we had two committed revolving credit facilities in the amounts of US$3.0 billion and US$1.2 billion, respectively. The US$3.0 billion facility is available until July 2020 and is undrawn at June 30, 2017. The US$1.2 billion facility is available until June 2019 and has an aggregate of US$804 million in outstanding letters of credit drawn against it at June 30, 2017. Under our US$3.0 billion and US$1.2 billion facilities, our uncommitted credit facilities and certain hedging lines, we have provided subsidiary guarantees for the benefit of the credit facilities. As a result our obligations under these agreements are guaranteed on a senior unsecured basis by Teck Metals Ltd (TML), Teck Coal Partnership, Teck South American Holdings Ltd., TCL U.S. Holdings Ltd., Teck Alaska Incorporated and Teck Highland Valley Copper Partnership, each a wholly owned subsidiary of Teck. Any amounts drawn under the committed revolving credit facilities can be repaid at any time and are due in full at maturity. Amounts outstanding under the US$3.0 billion facility bear interest at LIBOR plus an applicable margin based on our credit ratings. Amounts outstanding under the US$1.2 billion facility bear interest at LIBOR plus an applicable margin based on our leverage ratio. Both facilities require that our total debt-to-capitalization ratio, which was 0.26 to 1.0 at June 30, 2017, not exceed 0.5 to 1.0. When our credit ratings are below investment grade, we are required to deliver letters of credit to satisfy financial security requirements under power purchase agreements at Quebrada Blanca and transportation, tank storage and pipeline capacity agreements for our interest in Fort Hills. At June 30, 2017, we had an aggregate of US$834 million in letters of credit outstanding for these security requirements. These letters of credit will be terminated if and when we regain investment grade ratings or reduced if and when certain project milestones are reached. We maintain uncommitted bilateral credit facilities primarily for the issuance of letters of credit to support our future reclamation obligations. As at June 30, 2017, we were party to various uncommitted credit facilities providing for a total of $1.48 billion of capacity and the aggregate outstanding letters of credit issued thereunder were $1.25 billion. In addition to the letters of credit outstanding under these uncommitted credit facilities, we also had stand-alone letters of credit of $336 million outstanding at June 30, 2017, which were not issued under a credit facility. These uncommitted credit facilities and stand-alone letters of credit are typically renewed on an annual basis. We also have $305 million in surety bonds outstanding at June 30, 2017 to support current and future reclamation obligations. During the first two quarters of 2017, we granted 2,010,520 Class B subordinate voting share options to employees. These options have a weighted average exercise price of $27.79, a term of 10 years and vest in equal amounts over three years. The weighted average fair value of Class B subordinate voting share options issued was estimated at $8.32 per share option at the grant date using the Black-Scholes option-pricing model. The option valuations were based on an average expected option life of 4 years, a risk-free interest rate of 1.06%, a dividend yield of 2.20% and an expected volatility of 42%. We have issued and outstanding deferred share units, restricted share units, performance and performance deferred share units (collectively referred to as units). Deferred and restricted share units are granted to both employees and directors. Performance and performance deferred share units are granted to employees only. During the first two quarters of 2017, we issued 947,194 units to employees and directors. Deferred and restricted share units issued vest immediately for directors and vest in three years for employees. Performance and performance deferred share units vest in three years. Furthermore, the performance and performance deferred share units have performance vesting criteria that may result in 0% to 200% of units ultimately vesting. The total number of units outstanding at June 30, 2017 was 8,273,029. A share-based compensation recovery of $15 million (2016 - $42 million compensation expense) and a share-based compensation expense of $9 million (2016 - $69 million) was recorded for the three and six months ended June 30, 2017, respectively, in respect of all outstanding share options and units. Dividends of $0.10 per share (totaling $58 million) were paid on June 30, 2017 on our Class A common and Class B subordinate voting shares to shareholders of record on June 15, 2017. Based on the primary products we produce and our development projects, we have five reportable segments - steelmaking coal, copper, zinc, energy and corporate - which is the way we report information to our Chief Executive Officer. The corporate segment includes all of our initiatives in other commodities, our corporate growth activities and groups that provide administrative, technical, financial and other support to all of our business units. Other operating expenses include general and administration costs, exploration, research and development, and other operating income (expense). Sales between segments are carried out on terms that arm's-length parties would use. Total assets does not include intra-group receivables between segments. Deferred tax assets and liabilities have been allocated amongst segments. We consider provisions for all our outstanding and pending legal claims to be adequate. The final outcome with respect to actions outstanding or pending as at June 30, 2017, or with respect to future claims, cannot be predicted with certainty. Significant contingencies not disclosed elsewhere in the notes to our financial statements are as follows: Teck American Inc. (TAI) continues studies under the 2006 settlement agreement with the U.S. Environmental Protection Agency (EPA) to conduct a remedial investigation on the Upper Columbia River in Washington State. Residential soil testing within the study site has identified certain properties where remediation is required. TAI and EPA reached an agreement regarding the remediation to be undertaken in 2015, which has been completed, and additional sampling has been conducted which suggests that limited additional time-critical remediation will be required. The Lake Roosevelt litigation involving TML in the Federal District Court for the Eastern District of Washington continues. In September 2012, TML entered into an agreement with the plaintiffs, agreeing that certain facts were established for purposes of the litigation. The agreement stipulated that some portion of the slag discharged from TML's Trail Operations into the Columbia River between 1896 and 1995, and some portion of the effluent discharged from Trail Operations, have been transported to and are present in the Upper Columbia River in the United States, and that some hazardous substances from the slag and effluent have been released into the environment within the United States. In December 2012, the Court found in favour of the plaintiffs in phase one of the case, issuing a declaratory judgment that TML is liable under the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) for response costs, the amount of which will be determined in later phases of the case. In August 2016 the trial court judge ruled in favour of the Tribal plaintiffs awarding approximately $9 million in past response costs and that decision, along with certain other findings in the first phase of the case, is under appeal in the Ninth Circuit Court of Appeals. A District Court ruling in favour of plaintiffs on a motion seeking recovery from TML for environmental response costs, and in a subsequent proceeding, natural resource damages and assessment costs, arising from the alleged deposition of hazardous substances in the United States from aerial emissions from TML's Trail Operations was overturned on appeal in the Ninth Circuit in July 2016, with the result that alleged damages associated with air emissions are no longer part of the case. A hearing with respect to natural resource damages and assessment costs is expected to follow after resolution of appeals with respect to issues raised in the first phase of the litigation and completion of the remedial investigation and feasibility study being undertaken by TAI. There is no assurance that we will ultimately be successful in our defence of the litigation or that we or our affiliates will not be faced with further liability in relation to this matter. Until the studies contemplated by the EPA settlement agreement and additional damage assessments are completed, it is not possible to estimate the extent and cost, if any, of any additional remediation or restoration that may be required or to assess our potential liability for damages. The studies may conclude, on the basis of risk, cost, technical feasibility or other grounds, that no remediation other than some residential soil removal should be undertaken. If other remediation is required and damage to resources found, the cost of that remediation may be material. Due to ice conditions, the port serving our Red Dog mine is normally only able to ship concentrates from July to October each year. As a result, zinc and lead concentrate sales volumes are generally higher in the third and fourth quarter of each year than in the first and second quarter. Depending on commodity prices, this could result in Red Dog's profits and cash flows being higher in the last two quarters of the year as finished inventories are sold. Certain of our financial assets and liabilities are measured at fair value on a recurring basis and classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Certain non-financial assets and liabilities may also be measured at fair value on a non-recurring basis. There are three levels of the fair value hierarchy that prioritize the inputs to valuation techniques used to measure fair value, with Level 1 inputs having the highest priority. The levels and the valuation techniques used to value our financial assets and liabilities are described below: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. Cash equivalents and marketable equity securities are valued using quoted market prices in active markets. Accordingly, these items are included in Level 1 of the fair value hierarchy. Quoted prices in markets that are not active, quoted prices for similar assets or liabilities in active markets, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. Derivative instruments and embedded derivatives are included in Level 2 of the fair value hierarchy as they are valued using pricing models or discounted cash flow models. These models require a variety of inputs, including, but not limited to, market prices, forward price curves, yield curves, and credit spreads. These inputs are obtained from or corroborated with the market. Also included in Level 2 are settlements receivable and settlements payable from provisional pricing on concentrate sales and purchases because they are valued using quoted market prices for forward curves for copper, zinc and lead. Unobservable (supported by little or no market activity) prices. We include investments in debt securities in Level 3 of the fair value hierarchy because they trade infrequently and have little price transparency. We review the fair value of these instruments periodically and estimate an impairment charge based on management's best estimates, which are unobservable inputs. The fair values of our financial assets and liabilities measured at fair value on a recurring basis at June 30, 2017 and December 31, 2016 are summarized in the following table: For our non-financial assets and liabilities measured at fair value on a non-recurring basis, no fair value measurements were made as at June 30, 2017. As at December 31, 2016, we measured certain non-financial assets at their recoverable amounts using a FVLCD basis, which is classified as a Level 3 measurement.


News Article | August 4, 2017
Site: www.theenergycollective.com

This week marks the three-year anniversary of the Mount Polley mine disaster, which sent 24 million cubic metres of mining waste into Quesnel Lake, making it one of the worst environmental disasters in Canadian history. It’ll be a stinging reminder of the tailings pond collapse for local residents, especially considering no charges have been laid against Imperial Metals, owner and operator of Mount Polley. Come August 5 it will be too late for B.C. to lay charges, given a three-year statute of limitations — however federal charges can be laid for another two years. But here’s the thing: under the federal Fisheries Act, Mount Polley can receive a maximum of $12 million in fines: $6 million for causing harm to fish and fish habitat and $6 million for dumping deleterious substances without a permit into fish bearing waters. Compare that with the estimated $40 million in Mount Polley cleanup costs borne by B.C. taxpayers. And take into account that in 2016, Imperial Metals generated over $428 million in revenue and owns more than $1.5 billion in assets, according to the company’s annual report. “Fines and sanctions are pitiful for environmental damages in Canada, and it’s part of the systemic and structural problem for ensuring greater environmental protection,” Ugo Lapointe, Canadian coordinator for MiningWatch, told DeSmog Canada. “There’s little incentive for corporations to comply with environmental laws, or invest in more protective measures, if the consequences for failing to comply are cheaper.” For examples of more meaningful environmental penalties, Canadians need look no further than the U.S. In 2016 a Florida fertilizer manufacturer’s tailings pond drained millions of litres of wastewater into an underlying aquifer when a giant sinkhole appeared under the impoundment, tearing through the pond’s liner. The company was fined $2 billion USD for improper waste and chemical management (that’s 167 times the maximum fine Mount Polley could face under the Fisheries Act). In 2014, Alpha Natural Resources was ordered to pay $27.5 million USD for thousands of environmental violations at the company’s 79 coal mines and 25 processing plants across the States. The company was also ordered by the EPA to pay $200 million in upgrades to its facilities to avoid future infractions. Meantime back in Canada, the largest fine in Canadian history for an environmental infraction was for $7.5 million. That penalty was handed out in 2014 to owners of the Bloom Lake mine in Quebec who pled guilty to 45 separate charges under the Fisheries Act. The second largest fine in Canada, at $4.4 million, was just handed out to Prairie Mines in Alberta for the release of 67 million cubic metres of tailings waste into two creeks that feed into the Athabasca River. That spill was nearly 40,000 times smaller than the Mount Polley disaster. Of that total, $3.5 million was paid in federal penalties, with the additional $900,000 paid in provincial fines. The third largest fine of $3.4 million was handed out to Teck Metals for three offences under the Fisheries Act after the company released effluent into B.C.’s Columbia River. Mount Polley Disaster Didn’t Change the Way Mining is Done in B.C. The absence of provincial fines or charges in the wake of the Mount Polley mine spill worries Nikki Skuce, director of Northern Confluence, an initiative that aims to improve land-use decisions in B.C. watersheds. “It just seems incredible for what is called the largest environmental disaster in B.C.’s history, there are no fines, no charges, no penalties,” Skuce told DeSmog Canada. Further increasing concern is the fact best practices, including recommendations made by the Independent Expert Panel on Mount Polley, haven’t consistently been applied in the approval of new mines along the B.C./Alaska border. Ten new mines are approved or under construction along the B.C.-Alberta border, including Imperial Metals’ Red Chris mine which was approved with a wet tailings pond impoundment similar in design to Mount Polley. After the Mount Polley tailings spill, experts recommended the use of safer, but more costly, dry stack tailings. “The Independent Expert Panel on Mount Polley concluded that we can expect two failures every decade if ‘business as usual continues,’ ” Skuce said, adding multiple wet tailings impoundments have been approved at mines of much greater scale than Mount Polley. “With no full bonding requirements and potential fines low under B.C. and federal laws, companies have few incentives to invest in techniques like dry stacking that lower reclamation costs and reduce risk of spills,” Skuce said. “Why use best practices and best available technology if you may never be held accountable if disaster strikes?”


News Article | August 2, 2017
Site: www.marketwired.com

VANCOUVER, BRITISH COLUMBIA--(Marketwired - Aug. 1, 2017) - Teck Resources Limited ("Teck"), (TSX: TECK.A and TECK.B, NYSE: TECK) today announced that BC Hydro has exercised its right of first offer to purchase Teck's two-thirds interest in the Waneta Dam in British Columbia, Canada, for $1.2 billion cash. There are no material changes to the commercial terms of the previously announced Waneta purchase agreement between Fortis Inc. ("Fortis"), and Teck. Under the agreement, Teck Metals Ltd. ("Teck Metals") will be granted a 20-year lease to use the two-thirds interest in Waneta to produce power for its industrial operations in Trail. Annual payments will begin at approximately $75 million per year and escalate at 2% per annum, equivalent to an initial power price of $40/MWh based on 1,880 GWh of energy per annum. Teck Metals will have an option to extend the lease for a further 10 years at comparable rates. Under the Waneta purchase agreement with Fortis, Teck expects to pay Fortis a break fee of approximately $28 million. Teck expects to realize a net book gain of approximately $800 million on closing. No cash tax will be payable on the proceeds. Closing of the transaction is subject to customary conditions, including receipt of regulatory approvals and certain consents, and is not expected before the first quarter of 2018. Teck is a diversified resource company committed to responsible mining and mineral development with major business units focused on copper, steelmaking coal, zinc and energy. Headquartered in Vancouver, Canada, its shares are listed on the Toronto Stock Exchange under the symbols TECK.A and TECK.B and the New York Stock Exchange under the symbol TECK. Learn more about Teck at www.teck.com or follow @TeckResources. This press release contains certain forward-looking statements within the meaning of the United States Private Securities Litigation Reform Act of 1995 and forward-looking information as defined in the Securities Act (Ontario). The forward-looking statements in this news release include statements concerning the expected closing and timing of closing of the proposed transaction. Forward-looking statements involve known and unknown risks, uncertainties and other factors, which may cause the actual results, performance or achievements of Teck to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. Factors that may cause actual results to vary include, but are not limited to, whether or not the closing conditions are met within a timely manner or at all.


News Article | October 28, 2016
Site: www.marketwired.com

All dollar amounts expressed in this news release are in Canadian dollars unless otherwise noted. Teck Resources Limited (TSX: TCK.A and TCK.B, NYSE: TCK) ("Teck") reported profit attributable to shareholders of $234 million ($0.41 per share) and adjusted profit of $152 million ($0.26 per share) compared with $29 million ($0.05 per share) a year ago. "Our operations have performed very well throughout the year, setting a number of quarterly and year-to-date production records while continuing to reduce costs," said Don Lindsay, President and CEO. "As a result of the recent increase in steelmaking coal prices, we are generating a significant amount of additional cash which we have used to reduce our debt by repurchasing $1.0 billion of our outstanding notes." This management's discussion and analysis is dated as at October 26, 2016 and should be read in conjunction with the unaudited consolidated financial statements of Teck Resources Limited ("Teck") and the notes thereto for the three and nine months ended September 30, 2016 and with the audited consolidated financial statements of Teck and the notes thereto for the year ended December 31, 2015. In this news release, unless the context otherwise dictates, a reference to "the company" or "us," "we" or "our" refers to Teck and its subsidiaries. Additional information, including our annual information form and management's discussion and analysis for the year ended December 31, 2015, is available on SEDAR at www.sedar.com. This document contains forward-looking statements. Please refer to the cautionary language under the heading "CAUTIONARY STATEMENT ON FORWARD-LOOKING INFORMATION" below. Prices for most of our principal products continued to improve in the third quarter and were higher than a year ago and during the second quarter of this year. Our steelmaking coal price realized in the third quarter (US$92 per tonne) reflects the quarterly benchmark price that was settled in late June as well as spot price sales in the third quarter. Since then, steelmaking coal prices on the spot market have risen sharply, exceeding US$200 per tonne from mid-September. The recent spike in steelmaking coal prices is due to a number of supply side factors including: production curtailments at seaborne supplier mines since the start of 2014 due to the low price environment, supply side reform in the Chinese domestic coal sector where mine operating days were reduced to 276 from 330 days and supply disruptions in Australia and China. The ability of suppliers to increase production to respond to demand is being hampered by the prolonged period of low pricing which resulted in cancelled or delayed projects and the shutdown or bankruptcy of a number of mines. We are encouraged by the improved commodity price environment, but remain cautious about how long the supply/demand imbalance will last. We expect improved prices to provide additional profits and cash resources and have taken this opportunity to strengthen our balance sheet by repurchasing $1.0 billion of our debt in September and early October. On completion of this transaction, our debt to debt-plus-equity ratio has been reduced to 33% from 35%. We are focused on returning to an investment grade rating and may take the opportunity to purchase further debt from time to time. Our operations continued to perform well with 11 of our 13 operations increasing production while decreasing unit costs compared with a year ago. In the third quarter, our steelmaking coal operations achieved record production of 7.0 million tonnes and Trail achieved record production of 83,700 tonnes of refined zinc. This reflects our continued drive for productivity efficiencies across our entire business and our highly focused cost reduction efforts. Construction of the Fort Hills oil sands project continues to progress well with engineering and module fabrication essentially complete and overall construction progress surpassing 70% completion. The project is currently in its peak construction period with site activity above levels seen before the Fort McMurray wild fire. First oil is expected to be near the end of 2017, with 90% of the project's gross planned production capacity of 180,000 barrels per day expected within 12 months of first oil. Profit attributable to shareholders was $234 million, or $0.41 per share, in the third quarter compared with a loss of $2.1 billion or $3.73 per share in the same period last year. In the third quarter of 2015, we recorded asset and goodwill impairment charges on a number of our assets that totaled $2.2 billion on an after-tax basis ($2.9 billion on a pre-tax basis). Adjusted profit attributable to shareholders, after adjusting for the items identified in the table below, was $152 million, or $0.26 per share, in the third quarter compared with $29 million or $0.05 per share in the same period last year. The most significant of these adjustments relates to a gain on the repurchase of our debt at below face value and the positive revaluation of our call options on our most recently issued debt. The revaluation of the call options was a result of the decline of both interest rates and our own credit spread since the debt was issued. The value of the options represents the value of interest savings we would realize if we called the options on September 30, 2016 and reissued debt at current rates. In addition to the items described above, our results include various gains and losses due to changes in market prices and rates in respect of pricing adjustments, commodity derivatives, share based compensation and changes in the discounted value of decommissioning and restoration costs of closed mines. Taken together, these items resulted in a $41 million after-tax charge ($52 million before tax) in the third quarter, or $0.07 per share. We do not adjust our reported profit for these items as they occur on a regular basis. Our revenues, gross profit before depreciation and amortization, and gross profit by business unit are summarized in the table below. Gross profit from our steelmaking coal business unit before depreciation and amortization increased by $108 million in the third quarter compared with a year ago (see table below). Higher realized steelmaking coal prices and sales volumes in combination with lower unit costs and diesel prices all contributed to improved performance. Third quarter production of 7.0 million tonnes of steelmaking coal is a quarterly record for the business unit. Year-to-date production of 20.3 million tonnes also represents an all-time record for the first nine months of a calendar year, beating the previous nine month record by more than 400,000 tonnes. Third quarter production was also 27% higher than the same period a year ago, however, production last year was affected by our decision to shut down each operation for three weeks due to weak market conditions at the time. Sales volumes of 7.3 million tonnes were 18% higher than the same period a year ago and represent the second highest quarterly sales in our history. This strong performance resulted from a combination of tightness in supply, robust demand in all market areas and excellent performance in the logistics chain. The table below summarizes the gross profit changes, before depreciation and amortization, in our steelmaking coal business unit for the quarter: Property, plant and equipment expenditures totaled $25 million in the third quarter. Capitalized stripping costs were $43 million in the third quarter compared with $84 million a year ago. We are continuing to strip at all operations based on their respective mine plans, however, as a result of the sequencing at Fording River and Elkview this quarter, we mined in lower strip ratio areas at both sites and therefore capitalized a lower amount of costs. The effect of concurrent lower strip ratio sequences at our two largest mines, in combination with lower mining costs compared with a year ago at all sites, resulted in the reduction. Our realized price of US$92 per tonne was very close to the benchmark price of US$92.50 per tonne for the quarter as the increase in spot price assessments was reflected in our spot priced sales. Sales are generally recognized upon shipment and there is typically a four to six week lag between the time that a sales agreement is reached and when the shipment actually occurs. Therefore, quarterly sales and pricing reflect a mix of quarterly contract sales, current quarter spot sales, and previous quarter spot sales, across our steelmaking coal product mix. With the increase in price in the third quarter substantially commencing in mid-August and spot prices exceeding US$200 in mid-September, third quarter realized pricing was not significantly different from the quarterly contract price. The higher spot and contract prices will be reflected gradually in fourth quarter pricing. Steelmaking coal prices for the fourth quarter of 2016 have been agreed with the majority of our quarterly priced customers based on US$200 per tonne for the highest quality products. This is consistent with prices reportedly achieved by our competitors. This price has increased by US$107.50 per tonne from the reported third quarter settlement of US$92.50 per tonne and spot price assessments currently exceed the benchmark level by more than 20%. Additional sales priced on a spot basis will reflect market conditions at the time sales are concluded. Tightness in supply has driven prices up rapidly. This situation is the result of numerous factors including: While we cannot predict how long supply tightness will last, additional supply, beyond what we expect to materialize when Australian mines work through their disruptions, will take some time to come online. Mines will need to find people, equipment and capital before production enters the market. Our operations are well positioned to respond to this market opportunity. We continue to drive productivity and cost discipline across our business and we are well prepared for various market scenarios in the future. Our Elkview and Line Creek Operations each set new all-time quarterly and year-to-date records. Unit cash production costs at the mines were 10% lower this quarter than in the third quarter of 2015 as a result of significantly increased production rates, the impacts of initiatives undertaken to improve productivity and lower energy prices. Our continuous improvement initiatives continue to deliver significant results and our 2016 focus on capturing cost efficiencies in maintenance and supply have been particularly successful. In addition to these areas, we remain focused on making further improvements in equipment and labour productivity while, where possible, reducing the quantity of contractor support and consumables used. However, a number of factors have partially offset the impact of these efforts, including the effect of the stronger U.S. dollar on some inputs. In the third quarter of 2016, we continued to experience the positive effects of lower diesel prices compared with a year ago, although they have increased relative to the first half of 2016. Combined with reduced usage from a number of our cost reduction initiatives and slightly shorter haul distances, diesel costs per tonne produced have decreased by 11% compared to the third quarter of 2015. Our West Line Creek active water treatment facility is operating consistent with design parameters and in compliance with permit limits. We are currently investigating an issue regarding selenium compounds in effluent. Work is ongoing to assess the potential implications of this issue, and if associated environmental impacts are identified, modifications to operating parameters or facilities may be required. The cost of modifications may be material, and permitting of future mine expansions and construction of additional water treatment facilities may be delayed while we determine the significance of the issue and how to address it. Site cost of sales in the third quarter of 2016, before transportation and depreciation, was $43 per tonne, $2 per tonne or 5% lower than a year ago. Our total cost of sales for the quarter also included an $11 per tonne charge for the amortization of capitalized stripping costs and $12 per tonne for other depreciation. In U.S. dollar terms, unit costs have been reduced to $33 per tonne, $1 per tonne lower than a year ago due to reductions in site cost of sales as shown in the Canadian dollar unit cost table and the change in exchange rates. During the third quarter, our Elkview Operation was granted an environmental assessment certificate for the Baldy Ridge Extension project. The original capital estimate for this project as submitted in the environmental assessment application was $600 million over five years. Since the submission late last year, additional optimization work has resulted in a significantly less capital intensive plan and the spending over the next five years is currently estimated to be approximately $60 million versus the original capital estimate included in the submission filed late last year. The reduction in the estimated five year capital requirement for the Baldy Ridge Extension project relates primarily to resequencing the mine plan to defer the movement of critical site infrastructure including the maintenance shop, warehouse and offices to a point later in the mine life. Additionally, while new raw steelmaking coal conveyance infrastructure was contemplated in the original submission, detailed engineering work completed post submission has determined that the existing infrastructure will be adequate after a relatively low cost refurbishment program is completed. The capital to execute this project will be included within our 2017 and subsequent years' capital guidance, which will be issued along with our fourth quarter release. First steelmaking coal production from the mining areas at Elkview, which are included within the environmental assessment certificate area, is planned for early 2018. Also during the third quarter, Neptune Bulk Terminals received the final permit required for execution of the project to expand steelmaking coal throughput capacity. Work is now underway to update engineering, which was previously put on hold in 2013, to determine potential throughput capacity and inform a development decision. If sanctioned, the project is currently scheduled to be completed by early 2020. We are expecting sales volumes in the fourth quarter of 2016 to exceed 6.5 million tonnes. Vessel nominations for quarterly contract shipments are determined by customers and final sales and average prices for the quarter will depend on product mix, market direction for spot priced sales, timely arrival of vessels, as well as the performance of the rail transportation network and port-loading facilities. As a result of record third quarter and year-to-date production performance from the business unit, we now expect our production for the year to be between 27 and 27.5 million tonnes. With margins at current levels, we expect unit costs to increase in the fourth quarter as we focus on maximizing production and profitability, which will include increasing our use of contractors and higher cost equipment. We may also incur some one-time costs if we settle collective bargaining agreements. If these collective agreements are settled in the fourth quarter as a result of one-time costs, we would expect our annual cost of sales to be at the top end of the guidance range of $42 to $46 per tonne. Gross profit before depreciation and amortization from our copper business unit decreased by $25 million in the third quarter compared with a year ago (see table below). This was primarily due to lower realized copper prices and sales volumes, which more than offset positive effects of our cost reduction efforts. Third quarter copper production decreased by 10% from a year ago primarily due to reduced production from Highland Valley Copper as a result of lower ore grades, which was anticipated in the mine plan. This was partly offset by production increases at Quebrada Blanca and Carmen de Andacollo. Despite the lower production levels, our cash unit costs, after by-product margins, declined by 7% to US$1.34 per pound compared with a year ago as a result of continued cost reduction efforts at all of our operations. The table below summarizes the changes in gross profit, before depreciation and amortization, in our copper business unit for the quarter: Property, plant and equipment expenditures totaled $46 million, including $26 million for sustaining capital and $17 million for new mine development related to the Quebrada Blanca Phase 2 project. Capitalized stripping costs were $34 million in the third quarter, lower than $51 million a year ago, with the reduction primarily due to mining currently taking place in the lower strip ratio areas and to significantly lower costs at Highland Valley Copper. LME copper prices averaged US$2.16 per pound in the third quarter of 2016, up 1% from last quarter, but down 9.3% from the third quarter a year ago. Copper prices came under pressure in late August and early September, falling to just below US$2.10 per pound before recovering to just below $2.20 per pound by the end of the quarter. Copper prices year-to-date have averaged US$2.14 in 2016 versus US$2.58 in the same period in 2015. Total reported exchange stocks rose 137,650 tonnes during the quarter to 0.5 million tonnes. Total reported global copper exchange stocks are now estimated to be 8 days of global consumption, well below the estimated 25 year average of 12 days of global consumption. Availability of copper scrap remains constrained with imports of scrap into China down an estimated 8%. Copper consumption continues to rise at better than projected rates, although still lower than in 2015. Chinese demand growth is projected by Wood Mackenzie to reach 3% this year and slightly below that in 2017. Stronger than expected construction and automotive growth have offset manufacturing declines. Demand growth this quarter in both the U.S. and Europe was above previous forecasts on better automotive sales, while a stronger U.S. dollar has had an impact on U.S. manufacturing exports. Longer term, we believe that government commitments to improving and repairing aging infrastructure in Europe and North America along with China's aggressive targets on electric vehicle market penetration should be positive for copper demand going forward. Global market fundamentals over the medium to long-term remain positive as current low prices and weak margins continue to constrain new production growth and cap future copper mining investments. We increased our interest in Highland Valley Copper in the quarter, acquiring the remaining 2.5% interest in the mine for $33 million. We now have a 100% interest in the mine. Copper production was 27,300 tonnes in the third quarter or 32% lower than a year ago, due to lower copper grades and lower recoveries. Mill throughput was higher than a year ago due to reduced volumes of harder Valley pit ore and an increasing volume of softer, but lower grade, Lornex pit ore as planned. The transition to more Lornex ores will accelerate during the final quarter of the year as the current high grade phase of the Valley pit was exhausted in the third quarter. As previously disclosed, copper production is expected to be lower than normal over the next 18 months as we mine lower-grade phases of the pits before gradually recovering in 2018 and 2019. Molybdenum production in the third quarter of 1.4 million pounds doubled compared with a year ago as a result of higher grades. Operating cost of sales in the third quarter declined by $26 million, or 20%, compared with the same period a year ago as a result of significant cost reduction efforts and lower diesel and consumable costs. Our labour agreement at Highland Valley Copper expired at the end of the third quarter, and negotiations are ongoing. Copper production in the third quarter of 104,900 tonnes decreased by 3% compared with a year ago primarily as a result of lower grade and mill throughput, offset by improved recoveries. The mix of mill feed in the quarter was 73% copper-only ore and 27% copper-zinc ore compared to 57% and 43%, respectively, in the same period a year ago. Zinc production of 54,200 tonnes in the third quarter decreased by 18,400 tonnes compared with a year ago due to the reduction in copper-zinc ore processed, partially offset by higher zinc grades and recoveries. Mill throughput in the third quarter decreased by 5% compared with a year ago to 13.5 million tonnes, or an average of 147,000 tonnes per day due to ore hardness. Operating cost of sales in the third quarter were the same as a year ago, despite higher sales volumes in the quarter. We continue to make good progress on cost savings and productivity initiatives and overall site production costs in the quarter were lower than a year ago. Copper production in the third quarter increased by 2,500 tonnes to 8,600 tonnes compared with a year ago when production was temporarily suspended to address geotechnical issues. Operating costs in the third quarter were $40 million lower than a year ago as a result of lower supply costs, reduced material movement and our continued cost reduction efforts. In addition, higher operating costs arising out of geotechnical issues resulted in inventory write-downs of $31 million in the comparable quarter last year. Depreciation and amortization charges increased by $49 million in the third quarter compared with a year ago as a result of uncertainty regarding the mine life of the supergene deposit. On a year-to-date basis, depreciation and amortization expenses are $73 million higher compared to 2015. During the quarter we received our updated environmental permits for the existing facilities of the supergene operation. Work is continuing on optimizing the mine plan based on the lower operating cost profile and current copper price. Opportunities to recover additional copper from previously processed material continue to be evaluated. Copper production in the second quarter increased by 12% compared with a year ago primarily as a result of increased throughput due to deferral of major plant maintenance to later in the year and a focus on improving operational efficiency in the flotation circuit. Unit operating cost of sales in the third quarter decreased by 26% compared with a year ago primarily as a result of lower costs as described below. Overall site production costs have been reduced by US$23 million on a year-to-date basis compared to last year due to lower costs for operating supplies, reduced contractor costs and numerous other cost reduction initiatives. This was despite a 4% increase in throughput. Unit cash costs of product sold in the third quarter of 2016 as reported in U.S. dollars, before cash margins for by-products, were US$1.59 per pound compared with US$1.65 per pound in the same period a year ago. Total operating costs have been reduced substantially at all sites, however, the favourable effects of our cost reduction efforts were partly offset by lower production at Highland Valley Copper in the quarter as a result of mining and processing substantially lower grade material. Unit costs are anticipated to increase in the fourth quarter as production at Highland Valley Copper is expected to further decline. Cash margin for by-products increased to US$0.25 per pound compared with US$0.21 per pound in the same period a year ago. This was primarily due to significantly higher sales volumes of molybdenum at Antamina and Highland Valley Copper. Compared to the first half of this year, the cash margin for by-products more than doubled due to higher zinc sales volumes at Antamina and the additional molybdenum. Despite significantly lower production in the third quarter, unit cash costs for copper, after cash margin for by-products, were similar to the second quarter of 2016 and 7% lower than the same period a year ago at US$1.34 per pound. As part of the regulatory process, we submitted the Social and Environmental Impact Assessment (SEIA) to the Region of Tarapacá Environmental Authority, consistent with the timing previously noted in the company's second quarter 2016 release. A decision to proceed with development would be contingent upon regulatory approvals and market conditions, among other considerations. Given the timeline of the regulatory process, such a decision is not expected before mid-2018. Project optimization work currently underway targets capital costs in the range of US$4.5 to US$5 billion with an initial mine life of 25 years, consistent with the capacity of the revised tailings facility that is located closer to the mine. This compares to the 2012 feasibility study estimate of US$5.6 billion. The initial 25-year mine life will target processing about 1.25 billion tonnes, which does not include approximately 840 million tonnes of measured and indicated resources and 2.2 billion tonnes of inferred resources in the current resource estimate for the Quebrada Blanca hypogene deposit. The updated feasibility study, including capital and operating cost estimates and revised reserve and resource estimates for the project, is expected to be completed in the first quarter of 2017. Quebrada Blanca Phase 2 is expected to have an annual production capacity of over 250,000 tonnes of copper and 8,000 tonnes of molybdenum in concentrate for the first ten years of mine life. On the basis of copper equivalent production of approximately 280,000 tonnes per year, this equates to a capital intensity of approximately US$16,000 to US$17,850 per annual tonne. During the quarter, we completed trade-off studies in advance of the pre-feasibility study which started in October this year. In combination with ongoing community consultations, environmental baseline studies are also commencing this quarter. During the third quarter, we reviewed the pre-feasibility study that was completed at the Zafranal copper-gold project located in southern Peru, in which we hold a 50% interest. We continued discussions with our partners as to the next steps to advance the project. We expect 2016 copper production to be near the high end of our current guidance range of 310,000 to 320,000 tonnes. Production is expected to further decline over the final quarter as previously announced, due to significantly lower grades at Highland Valley Copper. Based on the continued strong cost performance in the third quarter and higher by-product revenues, we expect our full year copper unit costs, after by-products, to be near the lower end of our current range of US$1.40 to US$1.50 per pound. Unit costs are still expected to increase significantly in the final quarter due to reduced production levels at Highland Valley Copper. Gross profit before depreciation and amortization from our zinc business unit increased by $64 million compared to the third quarter of 2015 (see table below). Contributing to the increased gross profit were higher zinc and lead prices and our cost reduction efforts. Zinc in concentrate production in the third quarter increased by 14% compared with a year ago primarily as a result of higher mill throughput at Red Dog. Refined zinc production at Trail set a quarterly record, rising by 8% compared to the same quarter a year ago due to better plant availability and operational improvements. The table below summarizes the gross profit change, before depreciation and amortization, in our zinc business unit for the quarter. Property, plant and equipment expenditures included $37 million for sustaining capital in the third quarter. LME zinc prices averaged US$1.02 per pound in the third quarter of 2016, an increase of 21% from the same period a year ago, and an increase of 17% over the prior quarter. Zinc prices increased during the quarter from just below US$0.95 per pound early in the quarter to US$1.08 per pound at the end of the quarter. Zinc prices hit a five year high at US$1.09 per pound in early October. Total reported zinc exchange stocks fell 51,600 tonnes during the quarter to 597,670 tonnes, and year-to-date exchange stocks are down 67,160 tonnes. Total global reported exchange stocks are estimated at 17 days of global consumption, down from the 25 year average of 23 days. Excess zinc metal stocks also continue to be drawn down from non-LME warehouses. Demand for refined zinc in our key North American markets was firm in the third quarter with galvanized steel production up 2.8% according to CRU. Recent trade actions by the U.S. government against unfairly subsidized imports of coated steels from several countries including China, Italy and South Korea have resulted in a 21% reduction in imports of galvanized steel sheet into the U.S. Stocks of zinc concentrates continued to decline during the quarter and are, we believe, close to critical levels as zinc mine closures are now impacting spot concentrate treatment charges. Tightness in the concentrate market is starting to limit refined production, putting pressure on the market to remove additional stocks of metal from the terminal market and other off-exchange stocks. Despite the increasing zinc price, Chinese mine production is down 6% or 205,000 tonnes to August 2016 compared with last year and imports of concentrates are down 41% to August, or 365,000 tonnes. At the same time, demand for refined metal remains strong with imports up 55% year-to-date in August or up 140,000 tonnes. Zinc production in the third quarter was 14% higher than a year ago as a result of significantly higher mill throughput and slightly higher grades. Mill throughput was helped by softer ores being fed to the plant, as well as benefiting from operational improvements including higher plant availability. Lead production rose by 3% compared to a year ago primarily due to the higher throughput, partially offset by lower recoveries. Zinc sales of 190,500 tonnes were 2% higher than the third quarter of 2015. Sales volumes in the third quarter were substantially higher than our original guidance of 150,000 tonnes. The higher volumes reflect accelerated consumption rates by smelters due to continued tightness in the concentrate market, which is reflected in spot treatment charges being significantly below benchmark terms. Operating costs of $93 million in the third quarter were $11 million lower than in the same period a year ago primarily due to lower diesel costs. Capitalized stripping costs were $11 million in the third quarter, the same as a year ago. Refined zinc production of 83,700 tonnes set a new quarterly production record, primarily due to higher plant availability resulting in additional zinc concentrate treatment. Refined lead production of 23,600 tonnes was 8% higher than a year ago. Increased lead production volumes in 2016 were a result of improved operating reliability and higher lead inputs in the feed mix compared to last year, which included a major maintenance shutdown on the lead furnace. Operating costs in the third quarter of $95 million were 5% lower than a year ago as a result of cost reduction initiatives, despite higher treatment throughput volumes. Sustaining capital expenditures in the quarter included $4 million each for the water treatment plant and acid plant and $9 million for various other small projects. Mill throughput was 1,700 tonnes per day in the third quarter, similar to the second quarter. Zinc production during the quarter was 17% higher than the same period last year primarily due to increased mill throughput, higher ore grades and improved mill recoveries. Lead production was slightly higher at 1,600 tonnes. In response to production challenges, we have undertaken extensive geological studies to improve our knowledge of the mineralization at Pend Oreille and its impact in mineral resources and reserves. We have concluded that mineral reserves in the new MX area, currently under development, are less than previously anticipated. We have developed a new mine plan for the operation through to early 2018, although there is still significant potential to extend the mine life to at least 2020. We have identified highly prospective areas in the currently producing East Mine area and plan to undertake a major exploration and drilling program in 2017. On October 18, we announced the exercise of a right of first refusal to acquire the outstanding 49% interest in the Teena/Reward zinc project held by Rox Resources Limited for staged payments of up to AUD$20.6 million in cash and securities. Teena is located eight kilometers west of the MacArthur River Mine in the Northern Territory of Australia, which is one of the premier zinc provinces globally. The Red Dog concentrate shipping season is expected to be completed in the first week of November after extending the season by two weeks due to favourable ice conditions. We expect to ship approximately 1,075,000 tonnes of zinc concentrate and 220,000 tonnes of lead concentrate. This represents all of Red Dog's concentrates available to be shipped from the operation. We expect sales of 180,000 tonnes of zinc contained in concentrate in the fourth quarter reflecting the normal seasonal pattern of Red Dog sales. We expect 2016 zinc production to be near the high end of our current guidance range of 645,000 to 665,000 tonnes. As disclosed in the previous quarter results, Red Dog production is expected to be lower in the fourth quarter due to lower grades and a planned maintenance shutdown. The Fort Hills project is currently in its peak construction period with site activity above levels seen before the Fort McMurray wild fire. Suncor, the operator of the project, expects to be in a position to provide a project cost and schedule update around year end. This update will incorporate the effects of the wild fire, progress on module installation, foreign exchange and labour productivity through peak construction activities. In the third quarter, our share of capital expenditures was $254 million. Our share of Fort Hills cash expenditures in 2016 is estimated at $960 million, of which approximately $700 million has been spent to September 30, 2016. Engineering and module fabrication are essentially complete and overall construction progress has surpassed 70%. First oil is expected to be near the end of 2017, with 90% of Fort Hills gross planned production capacity of 180,000 barrels per day (bpd) expected within 12 months of first oil. Our share of production is expected to be 36,000 bpd (13 million barrels per year) of high-quality bitumen. The Fort Hills partners have executed long-term pipeline transportation agreements for the delivery of diluent from Edmonton to Fort Hills, and blended bitumen to Hardisty from Fort Hills. Each Fort Hills partner will be responsible to meet its diluent blend requirements, and to transport and sell its share of diluted bitumen to the market. The development of our comprehensive diluent acquisition and blended bitumen sales strategies is ongoing and we continue to review options to sell diluted bitumen into the North American and overseas markets. In support of our diverse market access strategy we have contracted for 425,000 barrels of terminal storage at Hardisty. We will provide an update to our marketing plans mid-2017. The Frontier project regulatory application review continues with the appointed three member Frontier hearing panel reviewing available information on the Frontier Project. The panel chair announced a 60-day comment period, from August 17 to October 17, for interested parties to comment on the sufficiency of information we filed to support our application. The regulatory review process is expected to continue through 2016, making 2017 the earliest a federal decision statement is expected for Frontier. Our expenditures on Frontier are limited to supporting this process. We are evaluating the future project schedule and development options as part of our ongoing capital review and prioritization process in response to current market conditions. During the third quarter, our share of the power generation from Wintering Hills was 25 GWhs, resulting in 16,000 tonnes of CO equivalent offsets. Our share of expected power generation in 2016 is 135 GWhs, resulting in approximately 85,000 tonnes of CO equivalent offsets, although actual generation will depend on weather conditions and other factors. Other operating expenses, net of other income, were $81 million in the third quarter compared with $174 million a year ago. We recorded various non-cash gains and losses due to changes in market prices and rates in respect of pricing adjustments, commodity derivatives, stock based compensation and the discounted value of decommissioning and restoration provisions for closed mines, which totaled $52 million net charge on a pre-tax basis ($41 million after-tax). Pricing adjustments in the third quarter included positive pricing adjustments on zinc and copper of $20 million and $5 million, respectively. The table below outlines our outstanding receivable positions, provisionally valued at June 30, 2016 and September 30, 2016. Finance expense was $89 million in the third quarter, $10 million higher than a year ago. Debt interest expense increased due to the effect of higher interest rates on recently issued debt, which was offset by increased capitalized interest. We expect our interest expense to decrease by approximately US$43 million in 2017 as a result of the US$759 million of notes we repurchased in September and early October. In addition, fees for letters of credit increased by $15 million. See the discussion below for further information regarding our letters of credit. Non-operating income in the third quarter totaled $131 million compared with a $44 million non-operating expense in the same period last year. We recorded a $98 million pre-tax gain on the revaluation of our call options on our most recently issued debt as interest rates and our own credit spread have declined significantly since issuance. In addition, we realized a pre-tax gain of $49 million on the repurchase of our debt below face value in the quarter. Income and resource taxes for the third quarter were $119 million, or 34% of pre-tax profits. This rate is higher than the Canadian statutory rate of 26% as a result of resource taxes and higher rates in foreign jurisdictions. These were partially reduced by the lower effective tax rate on the gain on debt purchases. 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: In just over a year, we have retired US$1.06 billion of our term notes, including US$300 million in the fourth quarter of 2015, US$334 million in the third quarter of 2016 and a further US$425 million subsequent to September 30, 2016, such that the principal balance of our term notes is now US$6.14 billion. After giving effect to our debt purchases subsequent to September, our debt to debt-plus-equity ratio at September 30, 2016 would have been 33% compared to 34% as reported in the table above. Our committed credit facilities are our US$3.0 billion revolving credit facility and US$1.2 billion revolving credit facility. US$200 million of our US$1.2 billion revolving credit facility matures in June 2017 and the remaining US$1.0 billion matures in June 2019. As at September 30, there were no amounts outstanding under the US$3.0 billion facility and there were US$975 million of letters of credit outstanding under the US$1.2 billion facility. Of those letters of credit, an aggregate of US$672 million were issued in respect of long-term power purchase agreements for the Quebrada Blanca Phase 2 project. The remainder relates to certain pipeline and storage agreements for our Fort Hills project and reclamation obligations for our Red Dog mine. We also maintain an aggregate of US$1.62 billion of uncommitted bilateral credit facilities with various banks and with Export Development Canada for the issuance of letters of credit, primarily to support our future reclamation obligations. At September 30, 2016, there were US$1.53 billion of letters of credit outstanding under these other facilities. We may be required to post additional security in respect of reclamation at our sites in future periods as regulatory requirements change and closure plans are updated. Cash flow from operations was $854 million in the third quarter compared with $560 million a year ago with the increase primarily due to higher commodity prices and partly due to our cost reduction efforts. Changes in working capital items resulted in a source of cash of $54 million in the third quarter compared with $259 million a year ago. Typically in the third quarter of each year, working capital decreases primarily due to the seasonal drawdown of product inventories at Red Dog. The working capital drawdown last year was unusually high due to the downward revaluation of accounts receivable at quarter end resulting from the $141 million of negative pricing adjustments recorded in the period. In September and early October, we purchased US$759 million aggregate principal amount of our outstanding notes through private and open market purchases at a total cost of US$693 million, which was funded from cash on hand. The principal amount of notes purchased was US$80 million of 3.75% notes due 2023, US$91 million of 6.125% notes due 2035, US$159 million of 6.00% notes due 2040, US$205 million of 6.25% notes due 2041, US$101 million of 5.20% notes due 2042, and US$123 million of 5.40% notes due 2043. The purchases are discussed further in Note 6(a) to our financial statements. Expenditures on property, plant and equipment were $376 million in the third quarter, compared to $349 million a year ago. Included in the spending was $254 million for the Fort Hills oil sands project, $81 million on sustaining capital, $17 million for Quebrada Blanca Phase 2 and $16 million on major enhancement projects. The largest components of sustaining expenditures were $17 million at Trail, $20 million at Red Dog and $16 million at Antamina. Capitalized stripping expenditures were $88 million in the third quarter compared with $146 million a year ago, as mining at some of our key operations was taking place in lower strip ratio areas resulting in lower costs being capitalized. In addition, the effect of our lower unit costs also resulted in less costs being capitalized. We are continuing to strip at all our operations based on their respective mine plans and the majority of this constitutes the advancement of pits for future production at our steelmaking coal mines. The table below summarizes our year-to-date capital spending for 2016: Prices for steelmaking coal have improved dramatically and are contributing significant additional revenues and cash flows. While we expect these to continue into the first quarter of 2017, steelmaking coal prices may decline in 2017. Commodity markets have historically been volatile, prices can change rapidly and customers can alter shipment plans. This can have a substantial effect on our business. We are also significantly affected by foreign exchange rates. In the last nine months, the U.S. dollar average has strengthened by approximately 5% against the Canadian dollar. This has had a positive effect on the profitability of our Canadian operations and translation of profits from our foreign operations. It will, to a lesser extent, put upward pressure on the portion of our operating costs and capital spending that is denominated in U.S. dollars. Our labour agreement at Highland Valley Copper expired at the end of the third quarter, and negotiations will continue in the fourth quarter. Labour agreements at Elkview and Fording River have also expired and negotiations are ongoing. The sales of our products are denominated in U.S. dollars, while a significant portion of our expenses are incurred in local currencies, particularly the Canadian dollar and the Chilean peso. Foreign exchange fluctuations can have a significant effect on our operating margins, unless such fluctuations are offset by related changes to commodity prices. Our U.S. dollar denominated debt is subject to revaluation based on changes in the Canadian/U.S. dollar exchange rate. As at September 30, 2016, $5.3 billion of our U.S. dollar denominated debt is designated as a hedge against our foreign operations that have a U.S. dollar functional currency. As a result, any foreign exchange gains or losses arising on that amount of our U.S. dollar debt are recorded in other comprehensive income, with the remainder being charged to profit. We hold a number of financial instruments and derivatives which are recorded on our balance sheet at fair value with gains and losses in each period included in other comprehensive income and profit for the period as appropriate. The most significant of these instruments are marketable securities, metal-related forward contracts including those embedded in our silver and gold streaming agreements, and settlements receivable and payable, and prepayment rights on certain long-term debt notes. Some of our gains and losses on metal-related financial instruments are affected by smelter price participation and are taken into account in determining royalties and other expenses. All are subject to varying rates of taxation depending on their nature and jurisdiction. As at October 26, 2016 there were 567.1 million Class B subordinate voting shares and 9.4 million Class A common shares outstanding. In addition, there were 23.3 million director and employee stock options outstanding with exercise prices ranging between $4.15 and $58.80 per share. More information on these instruments and the terms of their conversion is set out in Note 22 of our 2015 audited financial statements. Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Any system of internal control over financial reporting, no matter how well designed, has inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. There have been no significant changes in our internal control over financial reporting during the quarter ended September 30, 2016 that have materially affected, or are reasonably likely to materially affect, internal control over financial reporting. In preparing consolidated financial statements, management makes estimates that affect the reported amounts of assets, liabilities, revenues and expenses across all reportable segments. Management makes estimates that are believed to be reasonable under the circumstances. Our estimates are based on historical experience and other factors we consider to be reasonable, including expectations of future events. Critical accounting estimates are those that could affect the consolidated financial statements materially, are highly uncertain and where changes are reasonably likely to occur from period to period. Our critical accounting estimates that have a risk of resulting in a material adjustment to the carrying amounts of assets and liabilities within the next year include the recoverable amounts of long-lived assets, fair value of embedded derivatives associated with streaming transactions, estimated recoverable reserves and resources and the valuation of other assets and liabilities such as decommissioning and restoration provisions and the accounting for income taxes. These critical accounting estimates are consistent with those outlined in more detail in our 2015 annual consolidated financial statements and Management's Discussion and Analysis. Our revenue and gross profit by business unit are summarized in the tables below: Our cost of sales information by business unit is summarized in the table below: Production statistics for each of our operations are presented in the tables below. Operating results are on a 100% basis. USE OF NON-GAAP FINANCIAL MEASURES Our financial results are prepared in accordance with International Financial Reporting Standards (IFRS). This document refers to gross profit before depreciation and amortization, gross profit margins before depreciation, EBITDA, adjusted EBITDA, adjusted profit, adjusted earnings per share, cash unit costs, adjusted cash costs of sales, cash margins for by-products, adjusted revenue, net debt, debt to debt-plus-equity ratio, and the net debt to net debt-plus-equity ratio, which are not measures recognized under IFRS in Canada and do not have a standardized meaning prescribed by IFRS or Generally Accepted Accounting Principles (GAAP) in the United States. Gross profit before depreciation and amortization is gross profit with the depreciation and amortization expense added back. EBITDA is profit attributable to shareholders before net finance expense, income and resource taxes, and depreciation and amortization. Adjusted EBITDA is EBITDA before impairment charges. For adjusted profit, we adjust profit attributable to shareholders as reported to remove the effect of certain types of transactions that in our judgment are not indicative of our normal operating activities or do not necessarily occur on a regular basis. This both highlights these items and allows us to analyze the rest of our results more clearly. We believe that disclosing these measures assists readers in understanding the cash generating potential of our business in order to provide liquidity to fund working capital needs, service outstanding debt, fund future capital expenditures and investment opportunities, and pay dividends. Gross profit margins before depreciation are gross profit before depreciation and amortization, divided by revenue for each respective business unit. Unit costs are calculated by dividing the cost of sales for the principal product by sales volumes. We include this information as it is frequently requested by investors and investment analysts who use it to assess our cost structure and margins and compare it to similar information provided by many companies in our industry. We sell both copper concentrates and refined copper cathodes. The price for concentrates sold to smelters is based on average London Metal Exchange prices over a defined quotational period, from which processing and refining deductions are made. In addition, we are paid for an agreed percentage of the copper contained in concentrates, which constitutes payable pounds. Adjusted revenue excludes the revenue from co-products and by-products, but adds back the processing and refining allowances to arrive at the value of the underlying payable pounds of copper. Readers may compare this on a per unit basis with the price of copper on the London Metal Exchange. Adjusted cash cost of sales for our steelmaking coal operations is defined as the cost of the product as it leaves the mine excluding depreciation and amortization charges. Adjusted cash cost of sales for our copper operations is defined as the cost of the product delivered to the port of shipment, excluding depreciation and amortization charges. It is common practice in the industry to exclude depreciation and amortization as these costs are 'non-cash' and discounted cash flow valuation models used in the industry substitute expectations of future capital spending for these amounts. In order to arrive at adjusted cash costs of sales for copper we also deduct the costs of by-products and co-products. Total cash unit costs include the smelter and refining allowances added back in determining adjusted revenue. This presentation allows a comparison of unit costs, including smelter allowances, to the underlying price of copper in order to assess the margin. Unit costs, after deducting co-product and by-product margins, are also a common industry measure. By deducting the co- and by-product margin per unit of the principal product, the margin for the mine on a per unit basis may be presented in a single metric for comparison to other operations. Readers should be aware that this metric, by excluding certain items and reclassifying cost and revenue items, distorts our actual production costs as determined under GAAP. Net debt is total debt less cash and cash equivalents. The debt to debt-plus-equity ratio takes total debt as reported and divides that by the sum of total debt plus total equity. The net debt to net debt-plus-equity ratio is net debt divided by the sum of net debt plus total equity, expressed as a percentage. These measures are disclosed as we believe they provide readers with information that allows them to assess our credit capacity and the ability to meet our short and long-term financial obligations. The measures described above do not have standardized meanings under IFRS, may differ from those used by other issuers, and may not be comparable to such measures as reported by others. These measures have been derived from our financial statements and applied on a consistent basis as appropriate. We disclose these measures because we believe they assist readers in understanding the results of our operations and financial position and are meant to provide further information about our financial results to investors. These measures should not be considered in isolation or used in substitute for other measures of performance prepared in accordance with IFRS. Reconciliation of Gross Profit Before Depreciation and Amortization This news release contains certain forward-looking information and forward-looking statements as defined in applicable securities laws. All statements other than statements of historical fact are forward-looking statements. These forward-looking statements, principally under the headings "Outlook," that appear in this release but also elsewhere in this document, include estimates, forecasts, and statements as to management's expectations with respect to, among other things, anticipated cost and production forecasts at our business units and individual operations and expectation that we will meet our production guidance, sales volume and selling prices for our products (including settlement of steelmaking coal contracts with customers), capital expenditure guidance, our expectation that we will end the year with a cash balance of approximately $1.0 billion, our expectation that improved prices will provide additional profits and cash resources, our focus on achieving an investment grade rating, plans and expectations for our development projects, the targeted capital cost and mine life of Quebrada Blanca Phase 2, expected production, production capacity and capital intensity of Quebrada Blanca Phase 2, the potential to extend the Pend Oreille mine life to 2020, our expectation that we will close the acquisition of the outstanding 49% interest in the Teena/Reward zinc project, the impact of currency exchange rates, the expected timing and amount of production at the Fort Hills oil sands project and our remaining capital commitment at Fort Hills, and demand and market outlook for commodities. These forward-looking statements involve numerous assumptions, risks and uncertainties and actual results may vary materially. These statements are based on a number of assumptions, including, but not limited to, assumptions regarding general business and economic conditions, the supply and demand for, deliveries of, and the level and volatility of prices of, zinc, copper and steelmaking coal and other primary metals and minerals as well as oil, and related products, the timing of the receipt of regulatory and governmental approvals for our development projects and other operations, our costs of production and production and productivity levels, as well as those of our competitors, power prices, continuing availability of water and power resources for our operations, market competition, the accuracy of our reserve estimates (including with respect to size, grade and recoverability) and the geological, operational and price assumptions on which these are based, conditions in financial markets, the future financial performance of the company, our ability to attract and retain skilled staff, our ability to procure equipment and operating supplies, positive results from the studies on our expansion projects, our steelmaking coal and other product inventories, our ability to secure adequate transportation for our products, our ability to obtain permits for our operations and expansions, our ongoing relations with our employees and business partners and joint venturers. Our expectation that we will end the year with a cash balance of approximately $1.0 billion is based on current prices and exchange rates and assumes no unusual transactions or events occur and that we meet our full year guidance for production, costs and capital expenditures. Assumptions regarding the capital cost, mine life and other parameters for Quebrada Blanca Phase 2 are based on current project assumptions and are subject to, among other matters, the final feasibility study. Acquisition of the 49% interest in the Teena/Reward zinc project is based on the assumption that all conditions to closing are satisfied. Assumptions regarding the impact of foreign exchange are based on current commodity prices. The foregoing list of assumptions is not exhaustive. Events or circumstances could cause actual results to vary materially. Factors that may cause actual results to vary materially include, but are not limited to, changes in commodity and power prices, changes in market demand for our products, changes in interest and currency exchange rates, acts of foreign governments and the outcome of legal proceedings, inaccurate geological and metallurgical assumptions (including with respect to the size, grade and recoverability of mineral reserves and resources), unanticipated operational difficulties (including failure of plant, equipment or processes to operate in accordance with specifications or expectations, cost escalation, unavailability of materials and equipment, government action or delays in the receipt of government approvals, industrial disturbances or other job action, adverse weather conditions and unanticipated events related to health, safety and environmental matters), union labour disputes, political risk, social unrest, failure of customers or counterparties to perform their contractual obligations, changes in our credit ratings, unanticipated increases in costs to construct our development projects, difficulty in obtaining permits, inability to address concerns regarding permits of environmental impact assessments, and changes or further deterioration in general economic conditions. Closing of the Teena/Rox acquisition may be affected by unanticipated difficulties with respect to satisfaction of closing conditions or other challenges. Our Fort Hills project is not controlled by us and construction and production schedules and costs may be adjusted by our partners. Statements concerning future production costs or volumes are based on numerous assumptions of management regarding operating matters and on assumptions that demand for products develops as anticipated, that customers and other counterparties perform their contractual obligations, that operating and capital plans will not be disrupted by issues such as mechanical failure, unavailability of parts and supplies, labour disturbances, interruption in transportation or utilities, adverse weather conditions, and that there are no material unanticipated variations in the cost of energy or supplies. Statements regarding anticipated steelmaking coal sales volumes and average steelmaking coal prices for the quarter depend on timely arrival of vessels and performance of our steelmaking coal-loading facilities, as well as the level of spot pricing sales. We assume no obligation to update forward-looking statements except as required under securities laws. Further information concerning risks and uncertainties associated with these forward-looking statements and our business can be found in our Annual Information Form for the year ended December 31, 2015, filed under our profile on SEDAR (www.sedar.com) and on EDGAR (www.sec.gov) under cover of Form 40-F. Teck will host an Investor Conference Call to discuss its Q3/2016 financial results at 11:00 AM Eastern time, 8:00 AM Pacific time, on Thursday, October 27, 2016. A live audio webcast of the conference call, together with supporting presentation slides, will be available on our website at www.teck.com. The webcast will be archived at www.teck.com. Teck Resources Limited Condensed Interim Consolidated Financial Statements For the Three and Nine Months Ended September 30, 2016 (Unaudited) Teck Resources Limited Consolidated Statements of Changes in Equity (Unaudited) We prepare our annual consolidated financial statements in accordance with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB). These condensed interim consolidated financial statements have been prepared in accordance with IAS 34, Interim Financial Reporting (IAS 34). These condensed interim consolidated financial statements follow the same accounting policies and methods of application as our most recent annual financial statements. Accordingly, they should be read in conjunction with our most recent annual financial statements. The Audit Committee of the Board of Directors authorized these financial statements for issue on October 26, 2016. During the three and nine months ended September 30, 2016, we recorded an impairment of non-core assets of $26 million. In light of economic conditions in the third quarter of 2015, we recorded asset impairments in our copper, zinc, steelmaking coal and energy business units totaling $2.895 billion. The impairment considered a market participant range of key inputs in determining the recoverable amounts of the assets on a fair value less costs of disposal basis. In the fourth quarter of 2015, market conditions continued to deteriorate and market prices were amended further in our copper and energy business units. Additional impairments totaling $736 million were recorded in these business units and in our steelmaking coal business unit relating to certain mine plan changes in the fourth quarter of 2015. For the year ended December 31, 2015, we recorded asset impairment charges of $3.631 billion across all of our business units. The fair values of debt are determined using market values, if available, and discounted cash flows based on our cost of borrowing where market values are not available. The latter are considered Level 2 fair value measurements with significant other observable inputs on the fair value hierarchy (Note 11). The fair values of debt increased due to a reduction in our credit spread and a reduction in risk-free interest rates, partially offset by a strengthening Canadian dollar. In September and October 2016, we purchased US$759 million aggregate principal amount of our outstanding notes through private and open market purchases. Of the US$759 million, US$334 million settled in the third quarter and the remainder settled in October 2016. The US$759 million of purchased notes are comprised of US$80 million of 3.75% notes due 2023, US$91 million of 6.125% notes due 2035, US$159 million of 6.00% notes due 2040, US$205 million of 6.25% notes due 2041, US$101 million of 5.20% notes due 2042 and US$123 million of 5.40% notes due 2043. The total cost of the purchases was US$693 million. We recorded a pre-tax accounting gain of $49 million (after-tax $43 million) in non-operating income (expense) (Note 4) in the three months ended September 30, 2016. We expect to record a pre-tax gain of $27 million (after-tax $24 million) in the fourth quarter of 2016 on purchases that settled in October 2016. A total of US$66 million of notes were purchased in September 2016, but settled subsequent to September 30, 2016. These notes have been reclassified to current liabilities on our consolidated balance sheet and consist of US$7 million of 6.00% notes due 2040 and US$59 million of 5.40% notes due 2043. All private and open market purchases of our outstanding notes during the third quarter and subsequent to September 30, 2016 were funded from cash on hand. In June 2016, we issued US$650 million of senior unsecured notes due June 2021 (2021 notes) and US$600 million of senior unsecured notes due June 2024 (2024 notes). The 2021 notes have a coupon of 8.00% per annum and an effective interest rate, after taking into account issuance costs and the prepayment option value, of 8.22%. These notes were issued at par value and are callable on or after June 1, 2018 at pre-defined prices based on the date of redemption. Prior to June 1, 2018, the 2021 notes can be redeemed, in whole or in part, at a redemption price equal to the principal amount plus accrued interest and a make-whole call premium. The 2024 notes have a coupon of 8.50% per annum and an effective interest rate, after taking into account issuance costs and the prepayment option value, of 8.49%. These notes were issued at par value and are callable on or after June 1, 2019 at predefined prices based on the date of redemption. Prior to June 1, 2019, the 2024 notes can be redeemed, in whole or in part, at a redemption price equal to the principal amount plus accrued interest and a make-whole call premium. Our obligations under these notes are guaranteed on a senior unsecured basis by Teck Metals Ltd. (TML), Teck Coal Partnership, Teck Financial Corporation Ltd., TCL U.S. Holdings Ltd., Teck Alaska Incorporated and Teck Highland Valley Copper Partnership, each a wholly owned subsidiary of Teck. The 2016 indenture limits the aggregate amount of additional indebtedness for borrowed money the subsidiary guarantors may guarantee or otherwise incur to 10% of consolidated net tangible assets, subject to certain specified exceptions. Net proceeds from these issuances, after underwriting and issuance costs, were US$1.227 billion. We used these proceeds and cash on hand to purchase US$1.25 billion aggregate principal amount of our outstanding notes pursuant to cash tender offers. The purchased notes comprise US$266 million of 3.15% notes due 2017, US$284 million of 3.85% notes due 2017, US$478 million of 2.50% notes due 2018 and US$222 million of 3.00% notes due 2019. The total cost of the purchases, including the premium for the purchase, was US$1.267 billion. We recorded a pre-tax accounting charge of $27 million (after-tax $23 million) in non-operating income (expense) (Note 4) in the second quarter. The 2021 notes and 2024 notes include prepayment options that are considered to be embedded derivatives. At September 30, 2016, these prepayment options are recorded as other assets on the balance sheet at fair values of $48 million and $72 million for the 2021 and 2024 notes, respectively, based on current market interest rates for similar instruments and our credit spread. For the three and nine months ended September 30, 2016, the value of the prepayment options increased by $98 million, which has been recorded as a gain in non-operating income (expense) (Note 4). At September 30, 2016, we had two committed revolving credit facilities in the amounts of US$3.0 billion and US$1.2 billion, respectively. The US$3.0 billion facility is available until July 2020, includes a letter of credit sub-limit of US$1.0 billion and is undrawn at September 30, 2016. The US$1.2 billion facility was amended in the second quarter of 2016 as described below and can be fully drawn for cash or letters of credit, and has an aggregate of US$975 million in outstanding letters of credit at September 30, 2016. In June 2016, we made certain amendments to the terms of our US$1.2 billion credit facility, including an extension of the maturity date from June 2017 to June 2019. Lenders holding aggregate commitments of US$200 million declined to extend and as such the size of the facility will reduce to US$1 billion in June 2017. As part of the extension, Teck agreed to provide subsidiary guarantees for the benefit of the credit facility and as a result our obligations under this agreement are guaranteed on a senior unsecured basis by TML, Teck Coal Partnership, Teck Financial Corporation Ltd., TCL U.S. Holdings Ltd., Teck Alaska Incorporated and Teck Highland Valley Copper Partnership, each a wholly owned subsidiary of Teck. The amended credit facility contains covenants in addition to those contained in the original facility, including restrictions on new liens and guaranteed indebtedness. The amendments limit the amount of secured debt and guaranteed debt that Teck may issue. The maximum amount of secured debt that Teck and the guarantor subsidiaries may incur without securing the credit facility is equal to 4% of Teck's consolidated net tangible assets, or US$1 billion, whichever is greater. The maximum amount of debt (including secured debt) guaranteed or incurred by the guarantor subsidiaries and other material subsidiaries (not including subsidiaries organized in Chile) is equal to 9% of Teck's consolidated net tangible assets, or US$2.25 billion, whichever is greater. There are specific exemptions to each of the restrictions. Teck is also subject to covenants regarding asset sales and future subsidiary guarantors. Teck has provided the same subsidiary guarantees noted above to our obligations under the US$3.0 billion credit facility maturing July 2020, our uncommitted credit facilities and certain hedging lines. At September 30, 2016, Teck's consolidated net tangible assets were $31 billion (US$24 billion). Any amounts drawn under the committed revolving credit facilities can be repaid at any time and are due in full at maturity. Amounts outstanding under the US$3.0 billion facility bear interest at LIBOR plus an applicable margin based on our credit ratings, which is 225 basis points when our credit ratings are below investment grade. Amounts outstanding under the US$1.2 billion facility bear interest at LIBOR plus an applicable margin based on our leverage. Based on our September 30, 2016 leverage ratio, the applicable margin is 325 basis points. Both facilities require that our total debt-to-capitalization ratio not exceed 0.5 to 1.0. As at September 30, 2016, our ratio was 0.34. As a result of the loss of our investment grade ratings, we have been required to deliver letters of credit to satisfy financial security requirements under power purchase contracts at Quebrada Blanca and transportation, tank storage and pipeline capacity agreements for our interest in Fort Hills. At September 30, 2016, we had an aggregate of US$837 million in outstanding letters of credit for these contracts, of which US$672 relates to the Quebrada Blanca power purchase contracts. These letters of credit will be terminated if and when we regain investment grade ratings or reduced if and when certain project milestones are reached. We also maintain uncommitted bilateral credit facilities primarily for the issuance of letters of credit to support our future reclamation obligations. As at September 30, 2016, these facilities totalled $1.62 billion and outstanding letters of credit issued thereunder were $1.53 billion. These facilities are typically renewed on an annual basis. From time to time, at our election, we may reduce the fees paid to banks issuing letters of credit by making short-term deposits of excess cash with those banks. The deposits earn a market rate of interest and are generally refundable on demand. At September 30, 2016, we had $490 million (2015 - $732 million) of such deposits. During the first three quarters of 2016, we granted 8,945,695 Class B subordinate voting share options to employees. These options have a weighted average exercise price of $5.48, a term of 10 years and vest in equal amounts over three years. The weighted average fair value of Class B subordinate voting share options issued was estimated at $1.81 per share option at the grant date using the Black-Scholes option-pricing model. The option valuations were based on an average expected option life of 4 years, a risk-free interest rate of 0.72%, a dividend yield of 1.85% and an expected volatility of 46%. During the first three quarters of 2016, we issued 4,887,104 deferred, restricted and performance share units to employees and directors. Deferred, restricted and performance share units issued vest immediately for directors and vest in three years for employees. Furthermore, the performance share units have a performance vesting criterion that may increase or decrease the number of units ultimately vested. The total number of deferred, restricted and performance share units outstanding at September 30, 2016 was 8,335,862. A share-based compensation expense of $57 million (2015 - $5 million compensation recovery) and $126 million (2015 - $7 million) was recorded for the three and nine months ended September 30, 2016, respectively, in respect of all outstanding share options and units. The components of accumulated other comprehensive income are: Based on the primary products we produce and our development projects, we have five reportable segments - steelmaking coal, copper, zinc, energy and corporate - which is the way we report information to our Chief Executive Officer. The corporate segment includes all of our initiatives in other commodities, our corporate growth activities and groups that provide administrative, technical, financial and other support to all of our business units. Other operating expenses include general and administration costs, exploration, research and development, and other operating income (expense). Sales between segments are carried out on terms that arm's-length parties would use. Total assets does not include intra-group receivables between segments. Deferred tax assets and liabilities have been allocated amongst segments. We consider provisions for all our outstanding and pending legal claims to be adequate. The final outcome with respect to actions outstanding or pending as at September 30, 2016, or with respect to future claims, cannot be predicted with certainty. Significant contingencies not disclosed elsewhere in the notes to our financial statements are as follows: Teck American Inc. (TAI) continues studies under the 2006 settlement agreement with the U.S. Environmental Protection Agency (EPA) to conduct a remedial investigation on the Upper Columbia River in Washington State. Residential soil testing within the study site has identified certain properties where remediation is required. TAI and EPA reached an agreement regarding the remediation to be undertaken in 2015, which has been completed, and additional sampling is under way. The Lake Roosevelt litigation involving TML in the Federal District Court for the Eastern District of Washington continues. In September 2012, TML entered into an agreement with the plaintiffs, agreeing that certain facts were established for purposes of the litigation. The agreement stipulates that some portion of the slag discharged from our Trail Operations into the Columbia River between 1896 and 1995, and some portion of the effluent discharged from Trail Operations, have been transported to and are present in the Upper Columbia River in the United States, and that some hazardous substances from the slag and effluent have been released into the environment within the United States. In December 2012, the Court found in favour of the plaintiffs in phase one of the case, issuing a declaratory judgment that TML is liable under the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) for response costs, the amount of which will be determined in phases of the case. A hearing with respect to the claims of the Tribal plaintiffs in respect of approximately $9 million of past response costs was held in December. In August the trial court judge ruled in favour of the plaintiffs and the decision is under appeal. In October 2013, the Confederated Tribes of the Colville Reservation filed an omnibus motion with the District Court seeking an order stating that they are permitted to seek recovery from TML for environmental response costs, and in a subsequent proceeding, natural resource damages and assessment costs, arising from the alleged deposition of hazardous substances in the United States from aerial emissions from TML's Trail Operations. Prior allegations by the Tribes related solely to solid and liquid materials discharged to the Columbia River. The motion did not state the amount of response costs allegedly attributable to aerial emissions, nor did it attempt to define the extent of natural resource damages, if any, attributable to past smelter operations. In December 2013, the District Court ruled in favour of the plaintiffs, who have subsequently filed amended pleadings in relation to air emissions. The Court dismissed a motion to strike the air claims on the basis that CERCLA does not apply to air emissions in the manner proposed by the plaintiffs, and a subsequent TML motion seeking reconsideration of the dismissal. On July 27, 2016 the Ninth Circuit unanimously ruled in favour of TML on its appeal of the District Court decision. Plaintiffs sought en banc review of the decision in the Ninth Circuit, which was denied in October. A hearing with respect to liability in connection with air emissions, if that claim survives, and past response costs has been deferred in light of the interlocutory appeals, and a subsequent hearing with respect to claims for natural resource damages and assessment costs is expected to follow, assuming the remedial investigation and feasibility study being undertaken by TAI are completed, which is now expected to occur in 2017. There is no assurance that we will ultimately be successful in our defence of the litigation or that we or our affiliates will not be faced with further liability in relation to this matter. Until the studies contemplated by the EPA settlement agreement and additional damage assessments are completed, it is not possible to estimate the extent and cost, if any, of any additional remediation or restoration that may be required or to assess our potential liability for damages. The studies may conclude, on the basis of risk, cost, technical feasibility or other grounds, that no remediation other than some residential soil removal should be undertaken. If other remediation is required and damage to resources found, the cost of that remediation may be material. Due to ice conditions, the port serving our Red Dog mine is normally only able to ship concentrates from July to October each year. As a result, zinc and lead concentrate sales volumes are generally higher in the third and fourth quarter of each year than in the first and second quarter resulting in the last two quarters of the year having higher profits and cash flows as finished inventories are sold. Certain of our financial assets and liabilities are measured at fair value on a recurring basis and classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Certain non-financial assets and liabilities may also be measured at fair value on a non-recurring basis. There are three levels of the fair value hierarchy that prioritize the inputs to valuation techniques used to measure fair value, with Level 1 inputs having the highest priority. The levels and the valuation techniques used to value our financial assets and liabilities are described below: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. Cash equivalents and marketable equity securities are valued using quoted market prices in active markets. Accordingly, these items are included in Level 1 of the fair value hierarchy. Quoted prices in markets that are not active, quoted prices for similar assets or liabilities in active markets, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. Derivative instruments and embedded derivatives are included in Level 2 of the fair value hierarchy as they are valued using pricing models or discounted cash flow models. These models require a variety of inputs, including, but not limited to, contractual terms, market prices, forward price curves, yield curves, and credit spreads. These inputs are obtained from or corroborated with the market where possible. Also included in Level 2 are settlements receivable and settlements payable from provisional pricing on concentrate sales and purchases because they are valued using quoted market prices for forward curves for copper, zinc and lead. Unobservable (supported by little or no market activity) prices. We include investments in debt securities in Level 3 of the fair value hierarchy because they trade infrequently and have little price transparency. We review the fair value of these instruments periodically and estimate an impairment charge based on management's best estimates, which are unobservable inputs. The fair values of our financial assets and liabilities measured at fair value on a recurring basis at September 30, 2016 and December 31, 2015 are summarized in the following table: As at September 30, 2016, we measured certain non-core assets at their recoverable amounts using a fair value less costs of disposal basis, which is classified as a Level 3 measurement. As at December 31, 2015, we measured certain non-financial assets at their recoverable amounts using a fair value less costs of disposal basis, which is classified as a Level 3 measurement.

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