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UAlberta partners with top Chinese institution, Tsinghua University, to create Joint Research Centre for Future Energy and Environment during recent Alberta mission. EDMONTON, Alberta, April 22, 2017 /PRNewswire/ -- The University of Alberta is teaming up with research partners in China to develop low-carbon, sustainable energy solutions while tackling global environmental challenges. Officials from the U of A and Tsinghua University were in Beijing on April 20 to sign an agreement to create the Joint Research Centre for Future Energy and Environment. It was one of several key agreements the U of A signed with Chinese partners as part of a wider Government of Alberta trade mission, led by Premier Rachel Notley, to strengthen ties with the province's second-largest trading partner. "The University of Alberta values our long-standing partnerships with China and Tsinghua University, which bring together world-leading talent to address globally important issues such as clean energy, environment and climate change," said U of A President David Turpin. "Strengthening these collaborations will open even more avenues of discovery and lead to new ideas, technologies and innovations that will benefit both countries and the world." Larry Kostiuk, the U of A's associate vice-president of research, said the Joint Research Centre for Future Energy and Environment is the latest evolution in more than two decades of collaborations between the U of A and Tsinghua University—arguably China's best research institution and among the top in the world. In 2012, the U of A and Tsinghua created the Sino-Canadian Energy and Environment Research and Education Initiative, which has led to more than 30 partnerships in clean energy, environment, water, energy transport and policy. Kostiuk said the new centre elevates relations with Tsinghua to a "completely new level." Researchers will collaborate on a range of problems related to energy, environment and climate change, renewable energy, advanced power systems, energy transport and more. "This is a rare opportunity for a Canadian university to partner with Tsinghua University in such a significant way," said Kostiuk, who was in China for the signing. "We come from different places and backgrounds, but we're going to come together and leverage our different perspectives to solve common problems." The centre will be based at Tsinghua in a state-of-the-art research facility. Once operational, the centre will be able to apply for grant funding through the Chinese Ministry of Education, which is establishing strategic international research centres across the country. This centre would be the only one created in partnership with a Canadian university. Kostiuk will serve as the new centre's deputy director while retaining his position as director of U of A's Future Energy Systems initiative, which brings together researchers across disciplines to improve and develop new low-carbon energy technologies, integrate them into today's infrastructure and understand the social and economic impacts of their adoption. Kostiuk said the U of A-Tsinghua centre will be even broader in scope than Future Energy Systems, addressing environment and water issues not necessarily tied to energy. "Tsinghua University is a world leader in clean, low-carbon and renewable energy research and technologies. We all look forward to getting to work with incredibly bright people on both sides." "We are pleased to work with the University of Alberta, which has a global reputation in energy systems research," said Qikun Xue, vice-president of research with Tsinghua University. "We look forward to bringing our strengths together to tackle many critical issues facing our planet." In addition to the joint research centre, the Faculty of Rehabilitation Medicine signed a memorandum of understanding with Guanghua International Education Association to develop training for health professionals that will help China enhance and expand rehabilitation capacity. TEC Edmonton signed an agreement with Tsinghua University's research innovation incubator, TusPark/TusStar, on a new joint incubator. TusPark/TusStar operates the largest university science park in the world, and the new partnership would expand its global reach, creating economic opportunities for Edmonton and Alberta. "I am extremely proud to support the University of Alberta and TEC Edmonton in forming relationships with such innovative partners in China," said Premier Notley. "We look forward to seeing this partnership thrive, and to watching Alberta's expertise across a variety of areas, not only create opportunities for Albertans, but make a difference around the world." For further information: Bryan Alary, Communications Manager, Marketing & Communications, University of Alberta, Office: 780-492-0336  |  Email: bryan.alary@ualberta.ca


News Article | April 17, 2017
Site: www.marketwired.com

EDMONTON, ALBERTA--(Marketwired - April 10, 2017) - ICE District Joint Venture (ICE District JV) has announced its intention, with the assistance of the Government of Alberta and Homeward Trust, to support residents of MacDonald Lofts to find permanent, safe and affordable housing. A relocation notice was provided to residents of the MacDonald Lofts Property today that provides them one full year, 365 days, to secure alternate housing. Alberta Health Services inspectors declared several of the units unfit for human habitation in August 2016, citing several ongoing public health issues in the structure. ICE District JV acquired the MacDonald Lofts property in late 2016. A thorough evaluation of the building has been completed and its condition has been found to be detrimental to the health and safety of the residents. ICE District Joint Venture will work with the province and Homeward Trust to provide assistance to as many residents as required until every resident is re-housed. An office has been set up on the main floor of MacDonald Lofts Building. During the relocation process, residents will receive a Relocation Package that will include items such as a furniture package, cleaning of personal effects, return or transfer of damage deposit, provision of bare essentials and transportation to new premises.


News Article | May 4, 2017
Site: www.marketwired.com

EDMONTON, ALBERTA--(Marketwired - May 4, 2017) - EPCOR Utilities Inc. (EPCOR) today filed its quarterly results for the period ended March 31, 2017. "EPCOR's financial performance was in line with our expectations for the quarter. There were a number of events in the first quarter of 2016 that resulted in higher net income and did not repeat this year," said Stuart Lee, EPCOR President & CEO. "From an operational perspective, our facilities and infrastructure continued to run safely and reliably. We look forward to the transfer of the City of Edmonton's Drainage utility to EPCOR and its successful integration into our water utility operations." Highlights of EPCOR's financial performance are as follows: Management's discussion and analysis (MD&A) of the quarterly results are shown below. The MD&A and the unaudited condensed consolidated interim financial statements are available on EPCOR's website (www.epcor.com) and SEDAR (www.sedar.com). EPCOR's wholly owned subsidiaries build, own and operate electrical transmission and distribution networks, water and wastewater treatment facilities and infrastructure in Canada and the United States. The Company's subsidiaries also provide electricity, natural gas and water products and services to residential and commercial customers. EPCOR, headquartered in Edmonton, is an Alberta Top 70 employer. EPCOR's website address is www.epcor.com. This management's discussion and analysis (MD&A) dated May 4, 2017, should be read in conjunction with the condensed consolidated interim financial statements of EPCOR Utilities Inc. for the three months ended March 31, 2017, and 2016, including significant accounting policies (note 3), changes in liabilities arising from financing activities (note 4), financial instruments (note 5), the consolidated financial statements and MD&A for the year ended December 31, 2016, including standards and interpretations not yet applied (note 3(v)), related party transactions (note 27) and financial instruments (note 28), and the cautionary statement regarding forward-looking information at the end of this MD&A. In this MD&A, any reference to "the Company", "EPCOR", "it", "its", "we", "our" or "us", except where otherwise noted or the context otherwise indicates, means EPCOR Utilities Inc., together with its subsidiaries. In this MD&A, Capital Power refers to Capital Power Corporation and its directly and indirectly owned subsidiaries including Capital Power L.P., except where otherwise noted or the context otherwise indicates. Financial information in this MD&A is based on the condensed consolidated interim financial statements, which were prepared in accordance with International Financial Reporting Standards (IFRS), and is presented in Canadian dollars unless otherwise specified. In accordance with its terms of reference, the Audit Committee of the Company's Board of Directors reviews the contents of the MD&A and recommends its approval by the Board of Directors. This MD&A was approved and authorized for issue by the Board of Directors on May 4, 2017. EPCOR is wholly owned by The City of Edmonton (the City). EPCOR, through wholly owned subsidiaries, builds, owns and operates electrical transmission and distribution networks and provides Regulated Rate Option (RRO) and default supply electricity related services. EPCOR sells electricity and natural gas to Alberta residential consumers under contracts through its Encor brand. In addition, EPCOR builds, owns and operates water and wastewater treatment facilities and infrastructure in Canada and the Southwestern United States (U.S.). The water business also includes design, build, finance, operating and maintenance services for municipal and industrial customers in Western Canada. Net income was $38 million for the three months ended March 31, 2017, compared with net income of $78 million for the comparative period in 2016. The decrease of $40 million in the quarter is primarily due to lower income from core operations, as described below, unfavorable fair value adjustments related to financial electricity purchase contracts and no dividend income due to the sale of Capital Power shares (also referred to as the "available-for-sale investment in Capital Power"). Partially offsetting these decreases was the recognition of the fair value gain resulting from the final sale of Capital Power shares and an unfavorable fair value adjustment related to interest swaps in the first quarter of 2016 with no corresponding transaction in the current year. Net income from core operations was $38 million for the three months ended March 31, 2017, compared with $75 million for the comparative period in 2016. The decrease of $37 million in the quarter was driven in part by lower net system access collections, lower gains as a result of sales of surplus land in the first quarter of 2016, lower income related to industrial service contracts and lower Energy Price Setting Plan margins. Partially offsetting these decreases were higher distribution, transmission and water customer rates. Income from core operations is a non-IFRS financial measure as described in Net Income on page 3 of this MD&A. Transfer of Drainage Utility Services from the City of Edmonton In April 2017, Edmonton City Council approved the transfer of its Drainage Utility Services (Drainage) to EPCOR. Following the transfer, City Council will continue to regulate Drainage customer rates and set performance standards for the utility. Once the transfer is complete, EPCOR will own and operate the entire water utility cycle in the City of Edmonton, consisting of drinking water treatment and distribution, sanitary and stormwater collection and wastewater treatment. EPCOR anticipates that finalization of the terms of the Drainage transfer, including completion of a franchise agreement, will occur over the next several months with the transfer of the assets and assumption of liabilities expected to take place on September 1, 2017. Refer to the Capital Requirements and Contractual Obligations section for additional information. Consolidated revenues were lower by $20 million for the three months ended March 31, 2017, compared with the corresponding period in 2016 primarily due to the net impact of the following: We use income from core operations to distinguish operating results from the Company's water and electricity businesses from results with respect to its investment in Capital Power and changes in the fair value of financial instruments. The change in the fair value of financial instruments is the difference between the opening fair value of the derivative instruments for the period and the closing fair value of the derivative instruments. Income from core operations is a non-IFRS financial measure which does not have any standardized meaning prescribed by IFRS and is unlikely to be comparable to similar measures published by other entities. However, it is presented below as it provides a useful income performance measure of the Company's core operations and may be referred to by debt holders and other interested parties in evaluating the Company's financial performance and in assessing its creditworthiness. Changes in each business segment's operating results compared with the corresponding period in 2016 are described in Segment Results below. Explanations of the remaining variances in net income for the three months ended March 31, 2017 are: Water Services' operating income decreased by $17 million for the three months ended March 31, 2017, compared with the corresponding period in 2016, primarily due to gains on sale of surplus land in the first quarter of 2016, lower income related to industrial service contracts and lower water volumes due to decline in customer consumption, partially offset by higher customer rates and growth. Distribution and Transmission's operating income decreased by $19 million for the three months ended March 31, 2017, compared with the corresponding period in 2016, primarily due to lower net system access collections and lower income related to commercial services, partially offset by higher distribution and transmission customer rates. Energy Services' operating income, excluding change in the fair value of contracts-for-differences, decreased by $3 million for the three months ended March 31, 2017, compared with the corresponding period in 2016, primarily due to lower Energy Price Setting Plan margins. Total capital spending and investment was higher for the three months ended March 31, 2017, compared with the corresponding period in 2016, primarily due to increased spending in the Distribution and Transmission segment on the installation of advanced meter infrastructure for customers in Edmonton and ongoing renovations to its major work center. In addition, the Water segment had increased spending on the Gold Bar Hydrovac Sanitary Grit Treatment Facility project continuing from 2016 into 2017 and various projects in the U.S. This was partially offset by decreased spending in the Water Services segment due to the Gold Bar Grit Tanks project being substantially completed and placed into service in 2016. The Company maintains its financial position through rate-regulated utility and contracted operations which generate stable cash flows. The Company expects to have sufficient liquidity to finance its plans and fund its obligations for the remainder of 2017 with a combination of cash on hand, cash flow from operating activities, interest and principal payments related to long-term loans receivable from Capital Power, the issuance of commercial paper, public or private debt offerings and draws upon existing credit facilities described below under Financing. Cash flows from operating activities would be impaired by events that cause severe damage to our facilities and would require unplanned cash outlays for system restoration repairs. Under those circumstances, more reliance would be placed on our credit facilities for working capital requirements until a regulatory approved recovery mechanism or insurance proceeds are put in place. In April 2017, Edmonton City Council approved the transfer of Drainage to EPCOR as described in the Significant Subsequent Event section. Under the proposed terms, EPCOR intends to increase the dividend paid to the City by $20 million in 2018 (and by a prorated amount in 2017) subject to Board and Shareholder approval. In addition, the Company will pay $75 million to the City over a period of time to be determined by the City to compensate the City for costs related to the transfer. EPCOR will become responsible for future capital costs and assume responsibility for approximately $600 million to $650 million in current drainage-related City debt through a back-to-back agreement with the City. For the first full year of operations, capital spending is expected to be approximately $120 million to $200 million. The timing of the total commitment of $91 million for several Distribution and Transmission projects, as directed by Alberta Electricity System Operator, has changed since the fourth quarter of 2016 to $2 million in 2017, $38 million in 2018, $46 million in 2019 and $5 million in 2020. During the first quarter of 2017 there were no other material changes to the Company's capital requirements or purchase obligations, including payments for the next five years and thereafter, as previously disclosed in the 2016 annual MD&A. Generally, our external capital is raised at the corporate level and invested in the operating business units. Our external financing has consisted of commercial paper issuance, borrowings under committed syndicated bank credit facilities, debentures payable to the City, publicly issued medium-term notes, U.S. private debt notes and issuance of preferred shares. The Company has bank credit facilities which are used principally for the purpose of backing the Company's commercial paper program and providing letters of credit, as outlined below: Letters of credit are issued to meet the credit requirements of energy market participants and conditions of certain service agreements. Letters of credit totaling $61 million (December 31, 2016 - $73 million) were issued and outstanding at March 31, 2017. The committed syndicated bank credit facilities cannot be withdrawn by the lenders until expiry, provided that the Company operates within the related terms and covenants. The extension feature of EPCOR's committed syndicated bank credit facilities gives the Company the option each year to re-price and extend the terms of the facilities by one or more years subject to agreement with the lending syndicate. The Company regularly monitors market conditions and may elect to enter into negotiations to extend the maturity dates. The Company has a Canadian base shelf prospectus under which it may raise up to $1 billion of debt with maturities of not less than one year. At March 31, 2017, the available amount remaining under this base shelf prospectus was $1 billion (December 31, 2016 - $1 billion). The base shelf prospectus expires in December 2017. No commercial paper was issued and outstanding at March 31, 2017 (December 31, 2016 - nil). If the economy were to deteriorate in the longer term, particularly in Canada and the U.S., the Company's ability to extend the maturity or revise the terms of bank credit facilities, arrange long-term financing for its capital expenditure programs and acquisitions, or refinance outstanding indebtedness when it matures could be adversely impacted. We believe that these circumstances have a low probability of occurring. We continually monitor our capital programs and operating costs to minimize the risk that the Company becomes short of cash or unable to honor its debt servicing obligations. If required, the Company would look to reduce capital expenditures and operating costs. In August 2016, DBRS confirmed its A (low) / stable senior unsecured debt and R-1 (low) / stable short-term debt ratings for EPCOR and Standard & Poor's Ratings Services confirmed its A- / stable long-term corporate credit and senior unsecured debt ratings for EPCOR. We do not anticipate any changes to EPCOR's credit ratings due to the transfer of Drainage. EPCOR is currently in compliance with all of its financial covenants in relation to its syndicated bank credit facilities, Canadian public medium-term notes and U.S. private debt notes. Based on current financial covenant calculations, the Company has sufficient borrowing capacity to fund current and long-term requirements. Although the risk is low, breaching these covenants could potentially result in a revocation of EPCOR's credit facilities causing a significant loss of access to liquidity or resulting in the Company's publicly issued medium-term notes and private debt notes becoming immediately due and payable thereby causing the Company to find a means of funding which could include the sale of assets. For further information on the Company's contractual obligations, refer to the 2016 annual MD&A. This section should be read in conjunction with the Risk Management section of the 2016 annual MD&A. EPCOR believes that risk management is a key component of the Company's culture and we have put cost-effective risk management practices into place. At the same time, EPCOR views risk management as an ongoing process and we continually review our risks and look for ways to enhance our risk management processes. As part of ongoing risk management practices, the Company reviews current and proposed transactions to consider their impact on the risk profile of the Company. Due to the approval of the Drainage transfer, there have been changes to EPCOR's risk profile and risk management strategies as previously described in the 2016 annual MD&A. Currently, EPCOR's risks include new business integration, strategy execution risk, political and legislative risk, regulatory risk, health and safety risk, information technology related security risks, risk of reputational damage, environment risk, business interruption risks, failure to attract, retain or develop top talent, water scarcity risk, electricity price and volume risk, project risk, weather risk, financial liquidity risk, counterparty and credit risk, billing error risk, foreign exchange risk, conflicts of interest, and general economic conditions, business environment and other risks. The following risk has been revised since issuance of the 2016 annual MD&A as follows: EPCOR plans to diversify its utility infrastructure investments across investment types and North American geographies to reduce investment risk. The Company is planning to accomplish this through expansion into the natural gas distribution and drainage utility businesses. These types of utility businesses are new to EPCOR which introduces risk to the Company due to potential unfamiliarity with the associated operational, safety and regulatory risks in addition to the risks associated with integrating these businesses into EPCOR. In April 2017, the City of Edmonton approved the transfer of its Drainage utility to EPCOR. The transfer will be material to the Company due to the size of the utility, requiring substantial efforts to successfully integrate the operations into EPCOR. The integration will encompass many important elements that must be completed successfully. In addition, the Company may be integrating a new natural gas distribution business (Natural Gas Resources Limited or NRGL) concurrently with the Drainage integration. Failing to successfully integrate these new businesses and the resultant effects on the Company, including reputational impact, make this EPCOR's most significant risk for the time being. EPCOR has developed comprehensive integration plans and integration of the Drainage and natural gas distribution businesses will be a top priority for the Company, ensuring that personnel with appropriate skills are in place to operate the business safely and properly immediately upon the effective date of the transfer. The Company is not involved in any material litigation at this time. A number of new standards, amendments to standards and interpretations have been issued by the IASB and the International Financial Reporting Interpretations Committee the application of which is effective for periods beginning on or after January 1, 2018. Those which may be relevant to the Company and may impact the accounting policies of the Company are set out below. The Company does not plan to adopt these standards early. IFRS 9 - Financial Instruments (IFRS 9), which replaces IAS 39 - Financial Instruments: Recognition and Measurement, eliminates the existing classification of financial assets and requires financial assets to be measured based on the business model in which they are held and the characteristics of their contractual cash flows. The effective date for implementation of IFRS 9 has been set for annual periods beginning on or after January 1, 2018. Based on the Company's existing financial instruments, the Company is currently evaluating the impact of the application of IFRS 9 but does not expect it to have a significant impact on its consolidated financial statements. IFRS 15 - Revenue from Contracts with Customers (IFRS 15), which replaces IAS 11 - Construction Contracts and IAS 18 - Revenue and related interpretations, is effective for annual periods commencing on or after January 1, 2018. IFRS 15 introduces a new single revenue recognition model for contracts with customers and two approaches to recognizing revenue: at a point in time or over time. The model features a contract-based five-step analysis of transactions to determine whether, how much and when revenue is recognized. The Company has developed an implementation plan and is in the process of identifying the revenue streams and underlying contracts with customers that may be impacted on adoption of IFRS 15. The Company will continue to assess the impact of IFRS 15 on the consolidated financial statements and disclose applicable quantitative data in subsequent reporting periods. IFRS 16 - Leases (IFRS 16), which replaces IAS 17 - Leases (IAS 17), is effective for annual periods commencing on or after January 1, 2019. IFRS 16 combines the existing dual model of operating and finance leases in IAS 17 into a single lessee model. The Company is currently reviewing contracts that are identified as leases in order to evaluate the impact of adoption of IFRS 16 on the consolidated financial statements. The Company continues to assess the impact of IFRS on the consolidated financial statements. However, based on its preliminary assessment the Company expects that there will be a material impact on its statements of financial position requiring the recognition of lease assets and lease obligations with respect to its leases for office space, which are currently classified as operating leases. In preparing the condensed consolidated interim financial statements, management necessarily made judgments and estimates in determining transaction amounts and financial statement balances. The following are the items for which significant estimates were made in the condensed consolidated interim financial statements: electricity revenues and costs, unbilled consumption of electricity and water, fair values and income taxes. Although the current condition of the economy has not impacted our methods of estimating accounting values, it has impacted the inputs in those determinations and the resulting values. Interim results will fluctuate due to the seasonal demands for electricity and water, changes in electricity prices, and the timing and recognition of regulatory decisions. Consequently, interim results are not necessarily indicative of annual results. For further information on the Company's other critical accounting estimates, refer to the 2016 annual consolidated financial statements and 2016 annual MD&A. For the remainder of 2017, EPCOR will focus on the transfer and integration of the Drainage utility. In addition, we will continue to target growth in rate-regulated water, electricity and natural gas infrastructure. We expect much of this investment to come from new infrastructure to accommodate customer growth and lifecycle replacement of existing infrastructure primarily related to the Edmonton and U.S. based operations. EPCOR intends to expand our water and electricity commercial services activities and to invest in the area of renewable energy generation, including solar and bio gas facilities, to enhance our environmental performance. Over the long-term, demand for water is expected to increase and we anticipate escalating requirements for better water management practices including watershed management and conservation. We will pursue expansion of our portfolio of commercial water contracts. EPCOR has been awarded franchises by three municipalities in the Southern Bruce region of Ontario near Kincardine to build and operate a natural gas distribution system. In March 2016 EPCOR applied to the Ontario Energy Board (OEB) for the approval of these franchise agreements. In January 2017 the OEB requested indications of interest from any parties interested in servicing these areas. A single company did indicate an interest. The OEB has subsequently issued a Procedural Order including an issues list as a first step in developing a process for hearing competing applications. It is not clear at this time when the OEB will finalize its competitive process and adjudicate EPCOR's Franchise Application. In December 2016, the Government of Alberta passed Bill 21: the Modernized Municipal Government Act which could impose restrictions on the ability of a municipally controlled corporation (MCC) to conduct its business. EPCOR, which is a MCC of the City of Edmonton, was previously exempted by regulation from the MGA and a similar exemption by way of regulation has not been tabled. EPCOR is working to ensure the previous exemption is re-instated as the related regulations are developed. Municipal Affairs has advised that the posting of the draft MCC regulation is expected to occur in the second quarter of 2017. In November 2016 the Company entered into a definitive asset purchase agreement to acquire substantially all of the assets of NRGL for consideration of $21 million, subject to certain adjustments. NRGL is a natural gas distributor in southwestern Ontario near London, providing services to approximately 8,000 residential, commercial and industrial customers in the counties of Elgin, Middlesex, Oxford and Norfolk. The OEB is currently reviewing the application for approval of this arrangement and the Company expects to complete the transaction in the second half of 2017. Events for the past eight quarters compared to the same quarters of the prior year that have significantly impacted net income included: Certain information in this MD&A is forward-looking within the meaning of Canadian securities laws as it relates to anticipated financial performance, events or strategies. When used in this context, words such as "will", "anticipate", "believe", "plan", "intend", "target", and "expect" or similar words suggest future outcomes. The purpose of forward-looking information is to provide investors with management's assessment of future plans and possible outcomes and may not be appropriate for other purposes. Material forward-looking information within this MD&A, including related material factors or assumptions and risk factors, are noted in the table below: Whether actual results, performance or achievements will conform to the Company's expectations and predictions is subject to a number of known and unknown risks and uncertainties which could cause actual results to differ from expectations and are discussed in the Risk Management section above. Readers are cautioned not to place undue reliance on forward-looking statements as actual results could differ materially from the plans, expectations, estimates or intentions expressed in the forward-looking statements. Except as required by law, EPCOR disclaims any intention and assumes no obligation to update any forward-looking statement even if new information becomes available, as a result of future events or for any other reason. Additional information relating to EPCOR including the Company's 2016 Annual Information Form is available on SEDAR at www.sedar.com.


News Article | May 5, 2017
Site: www.prnewswire.com

"The decision to convert six of our units to natural gas positions us to be a strong competitor in the Alberta power market as carbon is priced and capacity becomes more valuable," said Mrs. Farrell. "We have a clear path forward that is aligned with policy, and the need to provide clean and affordable solutions for Albertans," added Mrs. Farrell. Reported net earnings attributable to common shareholders for the quarter was nil (nil per share) compared to net earnings of $62 million ($0.22 net earnings per share) in 2016 due to higher net earnings attributable to TransAlta Renewables Inc. shareholders. Last year, net earnings in the first quarter were also positively impacted by the reduction of our reclamation obligation at our Centralia mine caused by a higher discount rate. This year, higher depreciation arose due to the shortening of useful lives of Keephills 3 and Genesee 3. Adjusted availability for the three months ended March 31, 2017 was 88.5 per cent compared to 92.3 per cent for the same period in 2016. Higher unplanned outages at Canadian and US Coal were the main cause of the decrease. Lower availability had a minimal impact on our results due to current low prices in Alberta and the Pacific Northwest. Production for the three months ended March 31, 2017 was 9,051 gigawatt hours ("GWh"), compared to 8,867 GWh for the same period in 2016, mainly due to higher production at US Coal as a result of later economic dispatching in 2017 due to higher prices, partially offset by the cessation of operations at our Mississauga cogeneration facility, effective Jan. 1, 2017, in accordance with the terms of a new contract with Ontario's Independent Electricity System Operator ("IESO"). We will continue to receive monthly capacity payments from the IESO until Dec. 31, 2018. For the first quarter, sustaining capital expenditures decreased by $13 million compared to 2016, mainly due to lower planned outage expenditures. In 2016 we executed pit stops on our Sundance 1 and 2 Units as well as a large outage on Sundance Unit 4. During the first quarter of 2017, only one planned outage was performed on Sundance Unit 6. First Quarter 2017 Financial and Operational Highlights The complete report for the quarter, including MD&A and unaudited interim financial statements, as well as our quarterly presentation, will be available on the Investors section of our website: www.transalta.com. Conference call We will hold a conference call and webcast at 9:00 a.m. MT (11:00 a.m. ET) on Monday, May 8, 2017 to discuss our first quarter 2017 results. The call will begin with a short address by Dawn Farrell, President and CEO, and Donald Tremblay, Chief Financial Officer, followed by a question and answer period for investment analysts, investors and other interested parties. A question and answer period for the media will immediately follow. Please contact the conference operator five minutes prior to the call, noting "TransAlta Corporation" as the company and "Jaeson Jaman" as moderator. A link to the live webcast will be available on the Investor Centre section of TransAlta's website at http://www.transalta.com/investors/events-and-presentations. If you are unable to participate in the call, the instant replay is accessible at 1-855-859-2056 (Canada and USA toll free) with TransAlta pass code 5938029 followed by the # sign. A transcript of the broadcast will be posted on TransAlta's website once it becomes available. About TransAlta TransAlta is a power generation and wholesale marketing company focused on creating long-term shareholder value. TransAlta maintains a low-to-moderate risk profile by operating a highly contracted portfolio of assets in Canada, the United States and Australia. TransAlta's focus is to efficiently operate wind, hydro, solar, natural gas and coal facilities in order to provide customers with a reliable, low-cost source of power. For over 100 years, TransAlta has been a responsible operator and a proud contributor to the communities in which it works and lives. TransAlta has been recognized on CDP's Canadian Climate Disclosure Leadership Index (CDLI), which includes Canada's top 20 leading companies reporting on climate change, and has been selected by Corporate Knights as one of Canada's Top 50 Best Corporate Citizens and is recognized globally for its leadership on sustainability and corporate responsibility standards by FTSE4Good. For more information about TransAlta, visit our web site at www.transalta.com or follow us on Twitter @TransAlta. Cautionary Statement Regarding Forward Looking Information This news release contains forward-looking statements and forward-looking information within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "continue", "estimate", "may", "will", "project", "should", "believe", "plans", "intends" and similar expressions are intended to identify forward-looking information or statements. More particularly, and without limitation, this news release contains forward-looking statements and information relating to: TransAlta's business and anticipated future financial performance; our expected strategies and opportunities; expected governmental regulatory regimes and legislation (including the Government of Alberta's Climate Leadership Plan) and the timing of the implementation of such regimes and regulations; the impact of the retirement of Sundance Unit 1 and mothballing of Sundance Unit 2 on our future cash flow; the construction and commissioning of the South Hedland power project and its expected timing, costs and benefits; the repositioning of the strategy by Energy Marketing; the expected settlement with the OEFC; our expected major turnaround costs; and our strategy to accelerate our transition to gas and renewable generation, including through coal-to-gas conversions. By their nature, forward-looking information requires us to make assumptions and are subject to inherent risks and uncertainties. There is significant risk that predictions and other forward-looking information will not prove to be accurate and readers are cautioned not to place undue reliance on our forward-looking information as a number of factors could cause actual future results, conditions, actions or events to differ materially from the targets, expectations, estimates or intentions expressed in the forward-looking information. Some of the factors that could cause such differences include: operational risks involving our facilities; changes in market prices where we operate; equipment failure and our ability to carry out repairs in a cost effective and timely manner, including unplanned outages at generating facilities and associated capital investments; the effects of weather; disruptions in the source of fuels, water or wind required to operate our facilities; energy trading risks; failure to obtain necessary regulatory approvals in a timely fashion; legislative or regulatory developments and their impacts, including development of regulations facilitating coal-to-gas conversions; increasingly stringent environmental requirements and their impacts; increased competition; global capital markets activity (including our ability to access financing at a reasonable cost); changes in prevailing interest rates; currency exchange rates; inflation levels and commodity prices; general economic conditions in the geographic areas where we operate; deterioration of credit markets; and impediments to the construction and commissioning of South Hedland. Readers are cautioned not to place undue reliance on these forward-looking statements, which reflect TransAlta's expectations only as of the date of this news release. TransAlta disclaims any intention or obligation to update or revise these forward-looking statements, whether as a result of new information, future events or otherwise, except as required by law.


News Article | February 16, 2017
Site: www.marketwired.com

CALGARY, ALBERTA--(Marketwired - Feb. 16, 2017) - Inter Pipeline Ltd. (Inter Pipeline) (TSX:IPL) announced today financial and operating results for the three and twelve month periods ended December 31, 2016. * Please refer to the "Non-GAAP Financial Measures" section of the MD&A. Inter Pipeline generated record financial results in 2016 as FFO increased by $74.7 million, or approximately 10 percent, to $848.8 million. The NGL processing business segment generated the majority of the increase, driven by a full quarter of cash flow from the recently acquired Williams Canada NGL midstream business and higher propane-plus frac-spread pricing at the Cochrane straddle plant. Fourth quarter results were also a record with FFO of $254.7 million, up approximately 21 percent or $43.3 million compared to the fourth quarter of 2015. Corporate costs for the three and twelve months ended December 31, 2016 were $50.1 million and $199.2 million, respectively. Both periods saw an increase in general and administrative and financing costs, which were largely offset by lower cash taxes. For the fourth quarter and full year 2016, Inter Pipeline's four business segments generated FFO as follows: Declared dividend payments to shareholders were a record $539.2 million or $1.57 per share in 2016, yielding an attractive annual payout ratio of 66 percent. In November 2016, Inter Pipeline announced its 14th consecutive dividend increase to $1.62 per share annually, representing an increase of $0.06 per share. In the fourth quarter, Inter Pipeline declared dividends of $145.1 million or $0.40 per share, resulting in a conservative payout ratio of 58 percent. Inter Pipeline's oil sands transportation segment produced strong, stable results in 2016. Funds from operations reached a record $581.6 million in 2016, compared to $569.1 million in 2015. The year-over-year improvement was primarily driven by incremental revenues associated with the expansion of the Kearl oil sands project and other increases in capital fee payments. Bitumen blend and diluent volumes averaged 1,095,900 b/d for the year, a five percent increase over 2015. In the fourth quarter, funds from operations reached a new quarterly record of $158.5 million. Total throughput volumes averaged a record of 1,172,500 b/d or 60,700 b/d higher than the same period in 2015. The increase was primarily the result of higher volumes from the Foster Creek oil sands project on the Cold Lake pipeline system and increased production from the Jackpine mine on the Corridor pipeline system. Volumes transported by pipeline systems in the fourth quarter and full year 2016 were as follows: Effective November 1, 2016, Inter Pipeline acquired Canadian Natural's 15 percent interest in the Cold Lake pipeline system for $527.5 million, resulting in 100 percent ownership of this strategic asset. During the year, Inter Pipeline was also successful in securing two long-term connection arrangements with Pembina Pipeline and North West Redwater Partnership. These connections will enhance the delivery and receipt options for our shippers on our Cold Lake and Polaris pipeline systems. Incremental revenue from these connection projects is expected to commence mid-2017. In December, Inter Pipeline also entered into a long-term, take-or-pay agreement with Canadian Natural to transport diluent and bitumen blend for its Kirby North SAGD oil sands project. The new transportation agreement increased contracted capacity commitments by approximately 30,000 b/d and 8,000 b/d on our Cold Lake and Polaris pipeline systems, respectively. Capital expenditures are estimated at $125 million, with an expected in-service date of the first quarter of 2020. Inter Pipeline's conventional oil pipeline's business segment generated record funds from operations of $198.6 million in 2016, up two percent from 2015. Strong financial performance from midstream marketing activities and steady volumes on the Mid-Saskatchewan pipeline system contributed to the positive results. Annual throughput volumes on Inter Pipeline's three conventional gathering systems totaled 200,700 b/d, representing a decrease of five percent compared to 2015. Volume growth from the Viking light oil play serviced by the Mid-Saskatchewan pipeline system partially offset throughput declines on the Bow River and Central Alberta pipeline systems. Funds from operations for the quarter were a record $52.4 million. Fourth quarter throughput volumes totaled 200,300 b/d, down seven percent compared to the same period in 2015. The lower annual and quarterly volumes are largely a result of natural production declines and reduced producer drilling activity due to persistently low oil prices. In the second half of 2016, Inter Pipeline successfully commissioned three new light oil tanks at the Kerrobert Terminal. This $60 million project adds 400,000 barrels of storage capacity at this key terminal and began generating revenue in August 2016. In the fourth quarter of 2016, Inter Pipeline signed a long-term agreement with CHS Inc. to transport 32,500 b/d of crude oil on the Bow River pipeline system. This 10-year agreement replaced an existing transportation arrangement effective January 1, 2017. As part of the new agreement CHS has increased its take-or-pay commitment by approximately 10 percent for the shipment of crude oil sourced from Hardisty, Alberta to the CHS refinery in Laurel, Montana. Funds from operations in the NGL processing business grew to $147.8 million in 2016 up 47 percent from $100.8 million in 2015. In late September 2016, Inter Pipeline completed the acquisition of the Williams Canada NGL midstream businesses for approximately $1.35 billion. This processing business extracts and fractionates liquids from oil sands upgrader offgas and contributed approximately $27 million to annual FFO. Inter Pipeline is one of Canada's largest NGL processing businesses with ownership in three major straddle plants, two offgas processing plants, an offgas liquids pipeline and a liquids fractionator, all located in Alberta. Improved frac-spread pricing on propane-plus volumes at the Cochrane straddle plant also contributed to the positive full year results. The average propane-plus realized frac-spread was $0.40 USD per US gallon in 2016, up from $0.33 USD per US gallon in 2015. Natural gas throughput volumes to the straddle plants were also strong. Gas flows averaged 2.9 billion cubic feet per day (bcf/d) for the year, up 9 percent compared to 2015 volumes. Approximately 103,600 b/d of NGL were extracted, an increase of 1,900 b/d from 2015 levels. In the fourth quarter of 2016, fund from operations from this business segment totaled a record $65.0 million, which includes a full quarter of results from offgas processing activities. This is a $39.8 million, or 158 percent, increase over the same period in 2015. The propane-plus price recovery also continued in the quarter, with realized frac-spread price for the Cochrane straddle plant reaching $0.47 USD per US gallon, up 47 percent from $0.32 USD per US gallon in 2015. Paraffinic and olefinic realized frac-spreads from offgas processing operations were $0.18 USD per US gallon and $0.89 USD per US gallon, respectively, for the quarter. The offgas business produces higher value olefinic liquids which are not produced at Inter Pipeline's straddle plants. Fourth quarter natural gas inlet volumes reached 3.1 bcf/d for the straddle plants with liquids production totalling an average of 113,700 b/d. Average sales volumes from the Redwater olefinic fractionator were 29,900 b/d for the fourth quarter of 2016. Inter Pipeline also continued to progress the development of its proposed propane dehydrogenation and polypropylene facilities in the quarter. This integrated $3.1 billion petrochemical complex converts low cost Alberta propane into higher value polypropylene. Subject to securing appropriate long-term, fee-based contracts, Inter Pipeline anticipates making a final investment decision by mid-2017. Both plants are expected to be operational by mid-2021. In December, Inter Pipeline announced it will receive $200 million in royalty credits from the Government of Alberta's Petrochemical Diversification Program in support of the propane dehydrogenation plant. The royalty credits will be available to Inter Pipeline once the proposed facility is in operation. Inter Pipeline's bulk liquid storage business generated funds from operations of $120.0 million in 2016, up 22 percent from 2015. The record results include the first full-year of operations from Inter Terminals Sweden and higher overall demand for storage services. Annual capacity utilization rates were very strong across Inter Terminals' operations, resulting in an average utilization rate of 98 percent, compared to 94 percent in 2015. The high utilization rate was a result of executing a number of new storage contracts throughout the year. Also, several capacity addition projects were initiated in 2016 including the construction of 175,000 barrels of new chemical storage capacity at the Seals Sands Terminal in the United Kingdom. This $25 million project is expected to be completed by mid-2017. Funds from operations in the fourth quarter were $28.9 million and consistent with $28.2 million generated in the same period last year. Fourth quarter utilization rates averaged 99 percent, up two percent compared to 97 percent in the fourth quarter of 2015. Inter Pipeline continues to maintain a strong balance sheet with significant liquidity available on its committed revolving credit facility. Earlier in the year, Inter Pipeline successfully raised $950 million in new equity and term debt to partially fund the acquisition of the Williams Canada business. The remaining balance of acquisition financing was drawn from Inter Pipeline's revolving credit facility. The premium component of Inter Pipeline's Premium Dividend™ and Dividend Reinvestment Plan (DRIP) was also re-instated in October 2016, which raises additional equity capital on a monthly basis. In December 2016, Inter Pipeline issued $450 million of 10-year senior unsecured notes in the Canadian public debt market. Proceeds from this offering, as well as a $177.5 million common share issuance to Canadian Natural, were used to fund the acquisition of the remaining 15 percent interest in the Cold Lake pipeline system and reduce bank indebtedness. As at December 31, 2016, Inter Pipeline had $587.0 million of available capacity on its $1.5 billion revolving credit facility and ended the year with a consolidated net debt to total capitalization ratio of 57.2 percent. Inter Pipeline continues to maintain strong investment grade credit ratings. Standard & Poor's and DBRS Limited have assigned Inter Pipeline credit ratings of BBB+ and BBB (high), respectively. Effective January 1, 2017, Christian Bayle has been appointed to Inter Pipeline's Board of Directors. Mr. Bayle has been an employee of Inter Pipeline for nearly 20 years, including serving as its President and Chief Executive Officer since January 2014. Inter Pipeline will hold a conference call and webcast on February 17 at 9:00 a.m. MT (11:00 a.m. ET) for interested shareholders, analysts and media representatives. To participate in the conference call, please dial 1-844-413-0863 or 216-562-0455 (international). The conference ID is: 52871230. A webcast of the conference call can be accessed on Inter Pipeline's website at www.interpipeline.com/investor/events.cfm. An archived version of the webcast will be available for approximately 90 days. The Management's Discussion and Analysis ("MD&A") and consolidated financial statements provide a detailed explanation of Inter Pipeline's operating results for the three and twelve month periods ended December 31, 2016 as compared to the three and twelve month periods ended December 31, 2015. These documents are available at www.interpipeline.com and at www.sedar.com. Inter Pipeline is a major petroleum transportation, natural gas liquids processing, and bulk liquid storage business based in Calgary, Alberta, Canada. Inter Pipeline owns and operates energy infrastructure assets in western Canada and Europe. Inter Pipeline is a member of the S&P/TSX 60 Index and its common shares trade on the Toronto Stock Exchange under the symbol IPL. www.interpipeline.com. Certain information contained herein may constitute forward-looking statements that involve known and unknown risks, assumptions, uncertainties and other factors. Forward-looking statements in this news release include, but are not limited to: (i) statements regarding timing, costs and completion of Inter Pipeline's current and future projects, including the pipeline connections to Pembina Pipeline and the Kirby North SAGD oil sands project, (ii) Inter Pipeline's ability to complete the PDH facility and realize on the royalty credits awarded from the Government of Alberta's Petrochemical Diversification Program, (iii) Inter Pipeline's belief that it is well positioned to maintain its current level of dividends to its shareholders and (iv) the additional equity capital to be raised by the DRIP. Readers are cautioned not to place undue reliance on forward-looking statements, as such statements are not guarantees of future performance. Inter Pipeline in no manner represents that actual results, levels of activity and achievements will be the same in whole or in part as those set out in the forward-looking statements herein. Such information, although considered reasonable by Inter Pipeline at the time of preparation, may later prove to be incorrect and actual results may differ materially from those anticipated in the statements made. For this purpose, any statements that are not statements of historical fact may be deemed to be forward-looking statements. Forward-looking statements often contain terms such as "may", "will", "should", "anticipate", "expects" and similar expressions. Such assumptions, risks, uncertainties and other factors include, but are not limited to, risks and assumptions associated with operations, such as Inter Pipeline's ability to successfully implement its strategic initiatives and achieve expected benefits, including the further development of its pipeline systems and other facilities; assumptions concerning operational reliability; Inter Pipeline's ability to maintain its investment grade credit ratings; the availability and price of labour, equipment and construction materials; the status, credit risk and continued existence of customers having contracts with Inter Pipeline and its affiliates; availability of energy commodities; volatility of and assumptions regarding prices of energy commodities; competitive factors, pricing pressures and supply and demand in the oil and gas transportation, natural gas liquids extraction and storage industries; assumptions based upon Inter Pipeline's current guidance; fluctuations in currency and interest rates; inflation; the ability to access sufficient capital from internal and external sources; risks and uncertainties associated with Inter Pipeline's ability to maintain its current level of cash dividends to its shareholders; risks inherent in Inter Pipeline's Canadian and foreign operations; risks of war, hostilities, civil insurrection, instability and political and economic conditions in or affecting countries in which Inter Pipeline and its affiliates operate; severe weather conditions; terrorist threats; risks associated with technology; Inter Pipeline's ability to generate sufficient cash flow from operations to meet its current and future obligations; Inter Pipeline's ability to access external sources of debt and equity capital; general economic and business conditions; the potential delays of and costs of overruns on construction projects, including, but not limited to Inter Pipeline's current projects and future expansions of Inter Pipeline's pipeline systems; risks associated with the failure to finalize formal agreements with counterparties in circumstances where letters of intent or similar agreements have been executed and announced by Inter Pipeline; Inter Pipeline's ability to make capital investments and the amounts of capital investments; changes in laws and regulations, including environmental, regulatory and taxation laws, and the interpretation of such changes to Inter Pipeline's business; the risks associated with existing and potential or threatened future lawsuits and regulatory actions against Inter Pipeline and its affiliates; increases in maintenance, operating or financing costs; availability of adequate levels of insurance; difficulty in obtaining necessary regulatory approvals or land access rights and maintenance of support of such approvals and rights; the realization of the anticipated benefits of acquisitions; and such other risks and uncertainties described from time to time in Inter Pipeline's reports and filings with the Canadian securities authorities. The impact of any one assumption, risk, uncertainty or other factor on a particular forward-looking statement cannot be determined with certainty, as these are interdependent and Inter Pipeline's future course of action depends on management's assessment of all information available at the relevant time. You can find a discussion of those risks and uncertainties in Inter Pipeline's securities filings at www.sedar.com. Readers are cautioned that the foregoing list of assumptions, risks, uncertainties and factors is not exhaustive. The forward-looking statements contained in this news release are made as of the date of this document, and, except to the extent required by applicable securities laws and regulations, Inter Pipeline assumes no obligation to update or revise forward-looking statements made herein or otherwise, whether as a result of new information, future events, or otherwise. The forward-looking statements contained in this document and all subsequent forward-looking statements, whether written or oral, attributable to Inter Pipeline or persons acting on Inter Pipeline's behalf are expressly qualified in their entirety by these cautionary statements. Certain financial measures referred to in this news release are not measures recognized by GAAP. These non-GAAP financial measures do not have standardized meanings prescribed by GAAP and therefore may not be comparable to similar measures presented by other entities. Investors are cautioned that these non-GAAP financial measures should not be construed as alternatives to other measures of financial performance calculated in accordance with GAAP.


News Article | March 2, 2017
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EDMONTON, ALBERTA--(Marketwired - March 2, 2017) - EPCOR Utilities Inc. (EPCOR) today filed its annual and fourth quarter results for 2016. "2016 was a defining year for EPCOR with consolidated net income at the highest in a decade reaching $309 million. This, in part, reflected a gain on the sale of EPCOR's remaining ownership interest in Capital Power Corporation," said Stuart Lee, EPCOR President & CEO. "As well, EPCOR entered Texas with its investment in the 130 Pipeline, a water supply pipeline, near Austin and is set to re-enter the Ontario market with the pending acquisition of the assets of Natural Resource Gas Limited utility in southwestern Ontario. EPCOR also reached substantial completion of the City of Regina's upgraded wastewater treatment plant - on time and on budget. EPCOR will operate and finance the new infrastructure under a 30-year contract with the City." Backed by a strong and sustainable long-term growth outlook, EPCOR increased its annual dividend to its Shareholder, the City of Edmonton, by $5 million to $146 million commencing in 2017. "In addition to a strong growth outlook and excellent financial results, EPCOR recorded its best safety performance and highest employee engagement scores in company history. These results were among the most gratifying of the year," said Mr. Lee. Highlights of EPCOR's financial performance are as follows: Management's discussion and analysis (MD&A) of the annual and fourth quarter results are shown below. The MD&A and the audited annual consolidated financial statements are available on EPCOR's website (www.epcor.com) and SEDAR (www.sedar.com). EPCOR's wholly owned subsidiaries build, own and operate electrical transmission and distribution networks, water and wastewater treatment facilities and infrastructure in Canada and the United States. The Company's subsidiaries also provide electricity, natural gas and water products and services to residential and commercial customers. EPCOR, headquartered in Edmonton, is an Alberta Top 70 employer. EPCOR's website address is www.epcor.com. This management's discussion and analysis (MD&A), dated March 2, 2017, should be read in conjunction with the audited consolidated financial statements of EPCOR Utilities Inc. for the years ended December 31, 2016 and 2015, including related party transactions (note 27) and financial instruments (note 28), and the cautionary statement regarding forward-looking information at the end of this MD&A. In this MD&A, any reference to "the Company", "EPCOR", "it", "its", "we", "our" or "us", except where otherwise noted or the context otherwise indicates, means EPCOR Utilities Inc., together with its subsidiaries. In this MD&A, Capital Power refers to Capital Power Corporation and its directly and indirectly owned subsidiaries including Capital Power L.P., except where otherwise noted or the context otherwise indicates. Financial information in this MD&A is based on the audited consolidated financial statements, which were prepared in accordance with International Financial Reporting Standards (IFRS), and is presented in Canadian dollars unless otherwise specified. In accordance with its terms of reference, the Audit Committee of the Company's Board of Directors reviews the contents of the MD&A and recommends its approval by the Board of Directors. This MD&A was approved and authorized for issue by the Board of Directors on March 2, 2017. EPCOR is wholly owned by The City of Edmonton (the City). EPCOR, through wholly owned subsidiaries, builds, owns and operates electrical transmission and distribution networks and provides Regulated Rate Option (RRO) and default supply electricity related services. EPCOR sells electricity and natural gas to Alberta residential consumers under contracts through its Encor brand. In addition, EPCOR builds, owns and operates water and wastewater treatment facilities and infrastructure in Canada and the Southwestern United States (U.S.). The water business includes design, build, finance, operating and maintenance services for municipal and industrial customers in Western Canada. Net income was $88 million and $309 million for the three and twelve months ended December 31, 2016, respectively, compared with net income of $65 million and $260 million, for the comparative periods in 2015, respectively. The increase of $23 million in the quarter is primarily due to the recognition of the fair value gain resulting from the sale of Capital Power shares (also referred to as the "available-for-sale investment in Capital Power") and greater favorable fair value adjustments related to financial electricity purchase contracts and interest rate swaps, partially offset by lower income from core operations, as described below. The increase of $49 million for the twelve months ended December 31, 2016 was primarily due to the recognition of the fair value gain resulting from the sale of Capital Power shares, greater favorable fair value adjustments related to financial electricity purchase contracts and higher income form core operations as described below. Net income from core operations was $51 million and $255 million for the three and twelve months ended December 31, 2016, respectively, compared with $74 million and $251 million for the comparative periods in 2015, respectively. The decrease of $23 million in the quarter is primarily due to lower transmission customer rates, lower billing charge rates, higher depreciation, and lower income related to industrial services contracts, partially offset by higher approved distribution and water customer rates. The increase of $4 million for the twelve months ended December 31, 2016 was primarily due to higher approved distribution, transmission and water customer rates, gains on sale of surplus land, and water customer growth, partially offset by higher depreciation, lower billing charge rates and lower water volumes in Canada due to higher precipitation. EPCOR's vision is to be a premier essential services utility company in North America, trusted by our customers and valued by our shareholder. To achieve this vision, EPCOR must excel at its utility operations and be successful in its pursuit of new business growth opportunities. EPCOR's electricity strategy includes maintaining and developing new distribution and transmission infrastructure in its franchise service area as well as the development and / or acquisition of new rate-regulated or contracted assets and operations outside of its service area. EPCOR's water strategy includes maintaining and developing new water and wastewater infrastructure within its municipal franchise service areas and the development and / or acquisition of new rate-regulated or contracted assets and operations outside of its service areas. This includes design, build, finance and operate services for municipal water and wastewater treatment infrastructure and the provision of water and wastewater treatment services and potable and process water for industrial customers. We believe the long-term outlook for the North American electricity and water and wastewater treatment businesses remains strong. The demand for electricity and water and wastewater infrastructure in North America is expected to increase due to population growth, aging infrastructure, water scarcity and increased consumer expectations for reliable power, safe, high quality water and environmentally responsible wastewater treatment. Over the next five years we plan to invest in electricity and water and wastewater treatment assets where appropriate returns are expected, operational excellence can be delivered and the environmental impact is acceptable. We will seek growth opportunities within our existing utility footprint, in addition to the new geographies in which we have made recent acquisitions. This includes exploring opportunities in natural gas distribution through acquisitions and greenfield development. EPCOR also intends to invest in the area of renewable energy generation, including solar and bio gas facilities to enhance our environmental performance. Maintaining our investment grade credit rating to ensure access to capital through existing and new credit facilities and public or private debt financing offerings remains a priority. We recognize that we are not immune to recessionary trends and will remain vigilant to maintain a prudent balance of rate-regulated and contracted operations within our financial capacity. Operational and financial performance is measured through financial and non-financial measures that are approved by the Board of Directors. The measures fall under four broad categories composed of: health, safety and environment; people; growth (financial); and operational excellence, and are applied across the Company. There are specific measures established for each business unit and the corporate shared service group in alignment with the Company's strategy. For example, under the health, safety and environment category, safety performance is based on total recordable injury frequency. Business unit measures under the operational excellence category are focused on customer related measures relevant to the particular business unit, such as customer satisfaction survey results and service reliability. Recordable injury frequency rates for EPCOR overall were better (lower) in 2016 as compared to 2015. We remain committed to building a culture that supports a workplace free of occupational injury and illness with minimized harm to the environment. Segment performance measures are discussed under Segment Results of this MD&A. The Company sold 5,901,850 and 9,141,636 common shares of Capital Power, respectively, for net proceeds of $135 million and $204 million for the three and twelve months ended December 31, 2016, respectively. As a result of the sale of Capital Power shares, for the three months and twelve months ended December 31, 2016, the Company reclassified fair value gains of $30 million and $42 million, respectively, from other comprehensive income to net income. These sales were consistent with the Company's intention to sell the shares over time as market conditions permit. At December 31, 2016, the Company owned 249,364 common shares of Capital Power which were subsequently sold for net proceeds of $6 million in January 2017. Acquisition of the Assets of Blue Water Project 130 L.P. and Cross County Water Supply Corporation On August 19, 2016, the Company completed the acquisition of the assets of Blue Water Project 130 L.P. (Blue Water) and Cross County Water Supply Corporation (CCWSC) through EPCOR 130 Project Inc., a wholly owned U.S. subsidiary, and 130 Regional Water Supply Corporation, a Texas Water Supply Corporation of which EPCOR 130 Project Inc. is the sole member. The total consideration was $82 million (US$64 million). The Blue Water and CCWSC assets include an 85 kilometer water supply pipeline, near Austin, Texas, U.S., with designed capacity of nearly 68 million liters per day, along with groundwater well production systems and long term wholesale water supply agreements (collectively the EPCOR 130 Pipeline). $48 million (US$37 million) of the total consideration was paid at closing with the balance to be paid in the future, the majority of which is contingent on securing new long term contracts for the supply of water. The Company has recorded the full amount of this contingent consideration at fair value based on expected growth in the region. The Company funded the closing payment by issuing US$40 million of private debt notes with a 25-year term. The allocation of the purchase price was determined based on the relative fair values of the acquired assets and liabilities. For further information on the fair value estimates, refer to the audited consolidated financial statements of EPCOR Utilities Inc. for the years ended December 31, 2016 and 2015. During 2016, Water Services reached substantial completion of the wastewater treatment facility for the City of Regina under a public-private partnership. The construction was completed on time and on budget and the Company continued to operate the existing wastewater treatment facility during the construction period. The upgraded facility meets higher effluent standards as established by the Saskatchewan Water Security Agency, in response to the Federal Wastewater Systems Effluent Regulations, in addition to meeting the needs of a growing population. Water Services will continue to operate the wastewater treatment facility for the City of Regina for a total term of 30 years. In February 2015, Suncor gave the Company notice that it would exercise its contractual rights to buy back the leased assets and terminate the related financing and operating agreements including the transfer of assets and operations back to Suncor over an 18-month period. The transfer of assets and operations back to Suncor was completed in August 2016 in accordance with the terms of the notice. This event did not have a material impact on the Company or its operations. Consolidated revenues were lower by $49 million and $64 million for the three and twelve months ended December 31, 2016, respectively, compared with the corresponding periods in 2015 primarily due to the net impact of the following: We use income from core operations to distinguish operating results from the Company's water and electricity businesses from results with respect to its investment in Capital Power and changes in the fair value of financial instruments. In the first quarter of 2016, the definition of income from core operations was revised to exclude changes in the fair value of financial instruments. The change in the fair value of financial instruments is the difference between the opening fair value of the derivative instruments for the period and the closing fair value of the derivative instrument. Income from core operations is a non-IFRS financial measure which does not have any standardized meaning prescribed by IFRS and is unlikely to be comparable to similar measures published by other entities. However, it is presented below as it provides a useful income performance measure of the Company's core operations and may be referred to by debt holders and other interested parties in evaluating the Company's financial performance and in assessing its creditworthiness. Changes in each business segment's operating results compared with the corresponding periods in 2015 are described in Segment Results below. Explanations of the remaining variances in net income for the three and twelve months ended December 31, 2016 are as follows: EPCOR's Water business segment's primary objective is to provide safe and reliable water and wastewater services while meeting or exceeding all environmental requirements and delivering value to customers and the shareholder. Water Services operates in Canada and the U.S. The majority of Water Services' income in Canada is earned through a performance based rate tariff charged to its Edmonton customers. The performance based rate (PBR) tariff is intended to allow Water Services the opportunity to recover its costs and earn a fair rate of return while providing an incentive to manage costs below inflation and other prescribed adjustments built into the tariff. In October 2016, EPCOR's Water Services segment received the decision related to its 2017 - 2021 Edmonton water and wastewater PBR application. The decision reduced the return on equity (ROE) from 10.875% to 10.175%. The decision is not expected to have a material impact on the Company's results. Water Services also operates in the U.S. states of Arizona, New Mexico and Texas. Customer rates in Arizona and New Mexico are subject to approval by the Arizona Corporation Commission and the New Mexico Public Regulation Commission respectively. Customer rates are intended to allow EPCOR the opportunity to recover costs and earn a reasonable rate of return under a historical cost-of-service framework. At December 31, 2016, Water Services owned three and operated 14 other water treatment and / or distribution facilities in Alberta and British Columbia. Additionally, Water Services owned one wastewater treatment facility and operated 18 other wastewater treatment and / or collection facilities in Alberta, British Columbia and Saskatchewan. In Arizona and New Mexico, EPCOR owned operations in 14 water utility districts, each containing one or more water treatment and / or distribution facilities, and six wastewater utility districts, each containing one or more wastewater treatment and / or collection facilities. The EPCOR 130 Pipeline delivers water through a 30 inch pipeline to four municipal customers near Austin, Texas under long-term contracts. While these wholesale water contracts are technically subject to Texas Public Utilities Commission appellate review, they are considered to be effectively unregulated. Water Services' core market is stable as Water Services is the supplier of water and provider of wastewater services within its various operating districts. Operationally, the facilities owned or managed by Water Services generally performed according to plan in 2016. In the third quarter of 2016, persistent rainfall throughout the North Saskatchewan River watershed significantly impacted the river's water quality. Edmonton and region residents were asked to reduce water consumption for a short period of time. EPCOR was able to maintain the required quality of Edmonton's drinking water throughout the period. In addition, Water Services provides competitive contract-based water and wastewater services, including financing, in certain arrangements, to municipal and industrial customers. In August 2016, several agreements with Suncor were terminated and all financing arrangements and leases were settled and repaid to the Company. Work on several significant projects within Edmonton progressed in 2016. These projects include the annual water main renewal program to improve Edmonton's water distribution system, water distribution line relocation as a result of the City's light rail transit expansion, construction of a hydrovac sanitary grit treatment facility at Gold Bar and upgrades to pre-treatment and other infrastructure at the Gold Bar wastewater treatment facility. Water Services' operating income decreased by $4 million for the three months ended December 31, 2016, compared with the corresponding period in 2015 primarily due to lower income related to industrial services contracts, higher chemical and power costs, and higher depreciation, partially offset by higher approved customer rates and growth. Water Services' operating income increased by $13 million for the twelve months ended December 31, 2016, compared with the corresponding period in 2015 primarily due to higher approved customer rates and growth, gains on sale of surplus land, higher income related to industrial services contracts and foreign exchange translation gains, partially offset by higher chemical and power costs, lower municipal service margin, lower water volumes in Canada due to higher precipitation and higher depreciation. Edmonton water sales decreased in 2016 compared with 2015 mainly due to higher precipitation, partially offset by customer growth. Arizona and New Mexico water sales increased in 2016 compared with 2015 primarily due to higher average temperatures and lower precipitation during the summer months. In addition, water sales were higher due to the acquisition of the EPCOR 130 Pipeline which delivers wholesale water to customers in Texas. Distribution and Transmission's priority is to be a trusted provider of safe and reliable electricity, known for operational excellence through innovative and practical solutions. Distribution and Transmission earns income principally by transmitting high-voltage electricity through its facilities that form part of the Alberta Interconnected Electrical System to points of distribution, and from there, distributing lower voltage electricity to end-use customers. The transmission services are provided to the Alberta Electric System Operator (AESO). The distribution services are provided to electricity retailers such as Energy Services and other competitive retailers. Distribution and Transmission's assets are located in and around Edmonton and are rate-regulated by the Alberta Utilities Commission (AUC). Transmission charges a rate-regulated tariff intended to allow recovery of prudent costs and earn a fair rate of return on invested capital. Distribution earns income through a performance based rate tariff charged to its customers. The PBR tariff is intended to allow Distribution the opportunity to recover its costs and earn a fair return on capital while providing an incentive to manage costs below inflation and other prescribed adjustments built into the tariff. This segment also provides competitive contract-based commercial services related to installation, maintenance and repair of street lighting, traffic signals and light rail transit, primarily to the City. The AUC issued its 2016 Generic Cost of Capital decision in October 2016. The AUC directed that the ROE for 2016 remain at 8.3% and increase to 8.5% in 2017 for all Alberta natural gas and electricity distribution and transmission utilities. The AUC also set a deemed equity ratio of 37% for both distribution and transmission utilities targeting the utilities' maintenance of a credit rating in the A category. This decision results in a 3% decrease and a 1% increase in the deemed equity ratios for the EPCOR distribution and transmission utilities, respectively. The various true-ups related to the decision will occur over the next several years. The decision will not have a material impact on the financial results of the Company. Distribution and Transmission's operating income decreased by $13 million for the three months ended December 31, 2016, compared with the corresponding period in 2015 primarily due to lower transmission customer rates resulting from an interim to final rate true-up in 2015 and higher depreciation in 2016. This was partially offset by higher distribution approved customer rates and higher net system access collections. Distribution and Transmission's operating income increased by $11 million for the twelve months ended December 31, 2016, compared with the corresponding period in 2015, primarily due to higher distribution approved customer rates, higher net system access collections and higher transmission customer rates. This was partially offset by higher depreciation. Distribution and Transmission's primary measure of distribution system reliability is the System Average Interruption Duration Index (SAIDI), which it focuses on minimizing. This measure captures the annual average number of hours of interruption experienced by Distribution and Transmission's customers, including scheduled and unscheduled interruptions to its primary distribution circuits. In 2016, the SAIDI was 0.92 hours which is comparable to 0.91 in 2015. Distribution and Transmission will continue with its reliability improvement programs to further address controllable factors and help maintain and improve overall system reliability. Electricity distribution volumes in 2016 were relatively flat year over year. The Energy Services' business focuses on providing cost effective retail electricity service and efficient customer care through a highly skilled, knowledgeable, caring and engaged customer service team. Energy Services earns income from selling electricity to customers under a regulated rate tariff (RRT) and default rate (customers with higher electricity volumes that are not under a competitive contract) in the EPCOR Distribution and Transmission Inc. and FortisAlberta Inc. service areas and several Rural Electrification Association service territories. The RRT is intended to allow Energy Services to recover its prudent costs and earn a return margin. Customers under the RRT are residential, farm and small commercial customers who are not under a competitive contract and receive their electricity under the RRO. Energy Services also provides billing, collection, and contact center services to other EPCOR operations and the City Waste and Drainage Services departments. Energy Services focuses on providing excellent service experiences for its customers and measures call answer performance, billing performance, and customer satisfaction. These results are reported to the AUC on a quarterly basis. Energy Services' allowed electricity revenue is determined in accordance with an energy price setting plan (EPSP) approved by the AUC. Under the EPSP, Energy Services manages its exposure to customer load and fluctuating wholesale electricity spot prices by entering into financial electricity purchase contracts up to 120 days in advance of the month of consumption under a well-defined risk management process. Energy Services received approval of their 2016 - 2018 EPSP in the first quarter of 2016 and the Company implemented the new plan in the third quarter of 2016. The plan will adapt more quickly to changes in wholesale market conditions thereby reducing EPCOR's risk with commensurately lower risk compensation. Energy Services filed the next iteration of the EPSP applicable for 2018 - 2021 in January 2017. In May 2014, Energy Services entered the competitive retail market by offering electricity and natural gas contracts to Alberta consumers under the Encor brand in order to mitigate the impact of RRO customer attrition. The expanded service offering, including green energy options, provides customers wishing to move from the RRO to a competitive contract with an EPCOR offering. Energy Services' operating income, excluding change in the fair value of contracts-for-differences, decreased by $9 million for the three months ended December 31, 2016, compared with the corresponding period in 2015 primarily due to lower billing charge rates and lower EPSP margins. Energy Services' operating income excluding change in the fair value of contracts-for-differences decreased by $8 million for the twelve months ended December 31, 2016, compared with the corresponding period in 2015 primarily due lower billing charge rates, partially offset by higher EPSP margins and growth in competitive business. Energy Services' retail sales volumes were as follows: Energy Services' RRT sales volume decreased in 2016 compared with 2015 primarily due to a decrease in the average consumption per site. The increased default and competitive supply sales volume was primarily due to an increase in the number of competitive supply sites served, partially offset by a decrease in the number of default sites served. In 2016, we continued to invest in our infrastructure assets to improve reliability and meet increasing electricity and treated water and wastewater demands. Total capital spending and investment was higher in 2016 compared with 2015 primarily due to the acquisition of the assets of Blue Water and CCWSC, increased spending in the Distribution and Transmission segment on the installation of advance meter infrastructure for customers in Edmonton and renovations to its major work centre, and increased spending in the Water Services segment on lifecycle projects. This was partially offset by decreased spending in the Distribution and Transmission segment on growth projects and decreased spending in the Water Services segment primarily due to the completion of construction of the new laboratory and office building at the Rossdale location in 2015 as well as decreased spending at Gold Bar and at the Walker and Big Lake booster stations in Edmonton. The Company maintains its financial position through rate-regulated utility and contracted operations which generate stable cash flows. The Company expects to have sufficient liquidity to finance its plans and fund its obligations in 2017 with a combination of cash on hand, cash flow from operating activities, interest and principal payments related to long-term loans receivable from Capital Power, the issuance of commercial paper, public or private debt offerings and draws upon existing credit facilities described below under Financing. Cash flows from operating activities would be impaired by events that cause severe damage to our facilities and would require unplanned cash outlays for system restoration repairs. Under those circumstances, more reliance would be placed on our credit facilities for working capital requirements until a regulatory approved recovery mechanism or insurance proceeds were in place. EPCOR's projected capital requirements for 2017 include $500 million to $650 million for investment in existing businesses and new business development. The following table represents the Company's contractual obligations by year: Under the terms of the lease, the Company's annual lease commitments, net of annual payments to be paid to the Company by Capital Power and another company under the sub-leases receivable are as follows: All of the Company's operating lease obligations for premises, net of subleases receivable, are included in the contractual obligations table above. If Drainage is transferred to EPCOR under the current proposal, as described in more detail in the Outlook section, EPCOR will assume assets and liabilities of approximately $3.3 billion and $0.7 billion, respectively. As well, EPCOR has proposed an increase in the dividend of $20 million subject to Board and Shareholder approval. For the first year of operations, capital spending is expected to be approximately $120 million to $200 million. As a result of the acquisition of the Blue Water and CCWSC assets, the Company is committed to pay Blue Water a fee which is contingent on securing new long term contracts for the supply of water. This fee is capped at US$32 million with no time limit for payment of the fee. The Company is reasonably certain that it will be required to settle this commitment by way of cash payment and has accordingly recognized the liability for contingent consideration in the consolidated statement of financial position. During the year, the Company terminated the long term "pay fixed, receive floating" interest rate swap, related to Regina, by settlement of the outstanding liability of $14 million to the counterparty. Subsequent to the year ended December 31, 2016, the remaining short term interest rate swap was also settled. As at March 3, 2016, there were three common shares of the Company outstanding, all of which are owned by the City. In 2016, the annual dividend was set at $141 million (2015 - $141 million). As a result of EPCOR's consistent and sustainable performance, EPCOR's Board of Directors proposed to EPCOR's shareholder that the EPCOR annual dividend paid to the City be increased by $5 million to $146 million commencing in 2017. EPCOR's Shareholder approved this recommendation, and in accordance with the EPCOR Dividend Policy, this amount will remain in effect until such time as the EPCOR Board recommends that it be changed. In the normal course of business, EPCOR provides financial support and performance assurances, including guarantees, letters of credit and surety bonds, to third parties in respect of its subsidiaries. Generally, our external capital is raised at the corporate level and invested in the operating business units. Our external financing has consisted of commercial paper issuance, borrowings under committed syndicated bank credit facilities, debentures payable to the City, publicly issued medium-term notes, U.S. private debt notes and issuance of preferred shares. In the third quarter of 2016, the Company issued US$40 million private debt notes to fund the acquisition of the Blue Water and CCWSC assets. The U.S. dollar denominated private debt notes were issued with a term-to-maturity of 25 years and three months and an interest rate of 3.63% per annum. The Company has bank credit facilities, which are used principally for the purpose of backing the Company's commercial paper program and providing letters of credit, as outlined below: Letters of credit are issued to meet the credit requirements of energy market participants and conditions of certain service agreements. Letters of credit totaling $73 million (2015 - $48 million) were issued and outstanding at December 31, 2016. The committed syndicated bank credit facilities cannot be withdrawn by the lenders until expiry, provided that the Company operates within the related terms and covenants. The extension feature of EPCOR's committed syndicated bank credit facilities gives the Company the option each year to re-price and extend the terms of the facilities by one or more years subject to agreement with the lending syndicate. The Company regularly monitors market conditions and may elect to enter into negotiations to extend the maturity dates. In November 2016, the $200 million committed syndicated bank credit facility was extended by one year to November 2019. At this time, the covenants attached to both credit facilities were renegotiated. The Company has a Canadian base shelf prospectus under which it may raise up to $1 billion of debt with maturities of not less than one year. At December 31, 2016, the available amount remaining under this base shelf prospectus was $1 billion (December 31, 2015 - $1 billion). The base shelf prospectus expires in December 2017. No commercial paper was issued and outstanding at December 31, 2016 (December 31, 2015 - $98 million). If the economy were to deteriorate in the longer term, particularly in Canada and the U.S., the Company's ability to extend the maturity or revise the terms of bank credit facilities, arrange long-term financing for its capital expenditure programs and acquisitions, or refinance outstanding indebtedness when it matures could be adversely impacted. We believe that these circumstances have a low probability of occurring. We continually monitor our capital programs and operating costs to minimize the risk that the Company becomes short of cash or unable to honor its debt servicing obligations. If required, the Company would look to reduce capital expenditures and operating costs. In August 2016, DBRS confirmed its A (low) / stable senior unsecured debt and R-1 (low) / stable short-term debt ratings for EPCOR and Standard & Poor's Ratings Services confirmed its A- / stable long-term corporate credit and senior unsecured debt ratings for EPCOR. These credit ratings reflect the Company's ability to meet its financial obligations given the stable cash flows generated from the rate-regulated water and electricity businesses. The Company's continued sell-down of its interest in Capital Power in addition to the initial sale of the power generation assets in 2009 served to improve certain creditworthiness measures. The Company will continue to be indirectly exposed to power generation related risks primarily through its remaining long-term loans receivable from Capital Power until they are entirely repaid to EPCOR in 2018. Once the long-term loans receivable are repaid, the Company's creditworthiness is expected to improve even further. Improvement in the Company's creditworthiness may not result in further credit rating upgrades. A credit rating downgrade for EPCOR could result in higher interest costs on new borrowings and reduce the availability of sources and tenor of investment capital. EPCOR is currently in compliance with all of its financial covenants in relation to its syndicated bank credit facilities, Canadian public medium-term notes and U.S. private debt notes. Based on current financial covenant calculations, the Company has sufficient borrowing capacity to fund current and long-term requirements. Although the risk is low, breaching these covenants could potentially result in a revocation of EPCOR's credit facilities causing a significant loss of access to liquidity or result in the Company's publicly issued medium-term notes and private debt notes becoming immediately due and payable causing the Company to find a means of funding which could include the sale of assets. The key financial covenants and their thresholds, as defined in the respective agreements, and EPCOR's actual measures at December 31, 2016 and December 31, 2015 were as follows: In 2017, we will continue to focus on growth in rate-regulated water and electricity infrastructure. We expect this investment to come from new infrastructure to accommodate customer growth and lifecycle replacement of existing infrastructure primarily related to the Edmonton and U.S. based operations. EPCOR intends to expand our water and electricity commercial services activities and to invest in the area of renewable energy generation, including solar and bio gas facilities to enhance our environmental performance. Demand for water is expected to continue to increase and we anticipate escalating requirements for better water management practices including watershed management and conservation. We will pursue expansion of our portfolio of commercial water contracts. In January 2017, Edmonton City Council asked its administration to prepare a Letter of Intent (LOI) for the potential transfer of its Drainage Utility Services (Drainage) to EPCOR. The LOI is intended to outline the terms of a possible transfer, and is to include assurances from EPCOR on matters such as transparency into operations, public consultation, audit rights and the requirement for a public hearing should a divestiture occur in the future. It will be brought back to Council in April 2017 for further consideration. EPCOR currently operates three of the four components of the City's water utility cycle - water treatment, water distribution and wastewater treatment. The City's Drainage department operates the fourth component of the water system, the wastewater and storm water collection system. In November 2016, the Alberta government released several announcements impacting the electricity industry including the details of its Climate Change Plan. Among other things, these announcements included a cap on the RRO, a ban on door-to-door sales, and a shift to a capacity market framework from the existing energy-only market regime. These initiatives may lower the risk of RRO customer attrition in the long term. EPCOR's preliminary view is that these changes will not have a material impact. Energy Services will continue to evaluate these changes and determine any further course of action after consultations with the government and the AUC. Also in November 2016, the Company entered into a definitive asset purchase agreement to acquire substantially all of the assets of Natural Resource Gas Limited (NRGL) for consideration of $21 million, subject to certain adjustments. NRGL is a natural gas distributor in southwestern Ontario near London, providing services to approximately 8,000 residential, commercial and industrial customers in the counties of Elgin, Middlesex, Oxford and Norfolk. The arrangement requires regulatory approval from the Ontario Energy Board, for which an application has been filed. The Company expects to complete the transaction by mid-2017. EPCOR has been awarded franchises by three municipalities in the Southern Bruce region of Ontario near Kincardine to build and operate a natural gas distribution system. In March 2016, EPCOR applied to the Ontario Energy Board (OEB) for the approval of these franchise agreements. In January 2017 the OEB requested indications of interest from any parties interested in servicing these areas. A single company did indicate an interest and the OEB is now developing a process for hearing competing applications. To view an image associated with this release, please visit the following link: http://media3.marketwire.com/docs/1087660_image.jpg Our approach to Enterprise Risk Management (ERM) is to manage the key controllable risks facing the Company and consider appropriate actions to respond to uncontrollable risks. ERM includes the controls and procedures implemented to reduce controllable risks to acceptable levels and the identification of the appropriate management actions in the case of events occurring outside of management's control. Acceptable levels of risk and risk appetite for EPCOR are established by the Board of Directors, representing the shareholder, and are embodied in the decisions and corporate policies associated with risk management. EPCOR's framework for ERM is aligned with the Committee of Sponsoring Organizations 2004 Integrated ERM Framework and the ERM process follows CAN / CSA ISO 31000-10 Risk Management - Principles and Guidelines. EPCOR's ERM program and the risk management framework and process it supports is designed to identify, assess, measure, manage, mitigate and report on EPCOR's significant risks. The goal is to create and sustain business value by helping the Company reach its business objectives and strategies through better management of risk. The program promotes a common framework and language for managing risk across EPCOR. General ERM framework oversight, reviews and recommendations of risk compliance are provided by management and are based upon the objectives, targets and policies approved by the Board of Directors. The Corporate Treasurer is responsible for developing the framework and assessing risk at an enterprise level and in conjunction with the Company's internal audit function, monitoring compliance with risk management policies. The Corporate Treasurer provides the Board of Directors with an enterprise risk assessment quarterly. The business units and shared service units are responsible for carrying out the risk management and mitigation activities associated with the risks in their respective operations. These risk management activities are integral aspects of the business units' and shared service units' operations. EPCOR believes that risk management is a key component of the Company's culture and we have put into place cost-effective risk management practices. At the same time, EPCOR views risk management as an ongoing process and we continually review our risks and look for ways to enhance our risk management processes. Large scale emergencies resulting from various events discussed below may have a significant impact on the Company's ability to provide services that are considered essential services to the public. Maintaining essential services is critical to EPCOR's customers and EPCOR's reputation. The Company manages its ability to continually deliver services with emergency response protocols and business continuity plans which are periodically tested through various exercises and scenarios. These procedures provide assurance that the Company has the coordination, capacity and competence to respond appropriately to emergency situations arising from various forms of risk. The Company's Ethics Policy includes procedures which provide for confidential disclosure of any wrong-doing relating to accounting, reporting and auditing matters. The policy prohibits any retaliation against any person making a complaint. During 2016, no significant substantiated complaints with respect to accounting, financial reporting and auditing matters were received under the Ethics Policy. Our growth strategy is dependent on the development, acquisition and operation of linear infrastructure for municipal, commercial and industrial customers in Canada and the U.S. Opportunities in Canada may be impacted by depressed oil prices and the weak Canadian economy for the foreseeable future. This could slow or delay the Company's growth plans. Such growth is dependent on opportunities in the marketplace which will be impacted by the willingness of parties to sell such assets, political and public sentiment regarding third party ownership and EPCOR's cost competitiveness. These risks could result in delays or curtailment of EPCOR's growth plans. Business development projects, including acquisitions, can take a relatively long period of time to execute, exposing such projects to event and external factor risks that may emerge and thereby alter project economics or completion. For each new business development project, EPCOR seeks to ensure project success by addressing project risks, including events and external factors, as part of its due diligence process and project execution. EPCOR is subject to risks associated with changing political conditions and changes in federal, provincial, state, local or common law, regulations and permitting requirements in Canada and the U.S. It is not always possible to predict changes in laws or regulations that could impact the Company's operations, income tax status or ability to renew permits as required. In December 2016, the Government of Alberta enacted Bill 21: the Modernized Municipal Government Act which could impose restrictions on the ability of a municipally controlled corporation (MCC) to conduct its business. EPCOR, which is a MCC of the City of Edmonton, was previously exempted from the MGA and a similar exemption is not present in the new MGA. EPCOR is working to ensure the previous exemption is re-instated as the related regulations are developed. The risk could materially impact EPCOR's ability to execute on its Long Term Plan. EPCOR is subject to risks associated with the rate regulation of the majority of its operations. Such processes can result in significant lags between the time when customer rates or tariffs are applied for and the time that regulatory decisions are received. Furthermore, the regulator may deny or alter the applied for customer rates or tariffs. EPCOR's water treatment and distribution services to customers within Edmonton are rate regulated by Edmonton City Council pursuant to the 2012 - 2016 PBR Bylaw. In October 2016, EPCOR's Water Services segment received the decision related to its 2017 - 2021 Edmonton water and wastewater performance-based rate application for the five year period commencing April 1, 2017. The renewal also incorporated the costs associated with the provision of wastewater treatment services supplied from the Gold Bar wastewater treatment plant. Our ability to fully recover operating and capital costs and to earn a fair return is dependent upon achieving the performance targets prescribed in the bylaw, maintaining cost increases below inflation, managing operational risks and not exceeding approved capital additions. Rates for water sales to regional water commissions surrounding Edmonton are regulated by the AUC on a complaints-only basis. EPCOR sets the rates it charges to the regional water commissions to recover actual operating and capital costs including a fair rate of return. Water and wastewater services provided by EPCOR's U.S. subsidiaries are subject to state laws and regulation by the state regulatory commissions within Arizona, New Mexico and Texas. Our ability to fully recover operating and capital costs and earn a fair return is dependent upon achieving our capital and operating cost targets built into the rates, and meeting the customer growth and water usage targets built into the rates. Since rates are established on a historical cost basis, any new capital additions for water or wastewater infrastructure must be carefully planned and evaluated before commencement since the addition of such costs to the regulatory rate base for subsequent recovery will only take place after the new infrastructure is built and the regulator approves the rate base additions through the rate application process. The AUC utilizes a PBR structure for electricity and natural gas distribution utilities in Alberta. Under PBR, EPCOR's annual electricity distribution rates are set by a formula that is generally equal to last year's rate plus an inflation factor less a productivity factor plus a provision for additional approved capital additions. Capital projects may be applied for annually in a separate capital application (capital tracker). Our ability to recover the actual costs of providing service and to earn a fair return is dependent upon maintaining cost increases at or below inflation, achieving the productivity factor and not exceeding the approved capital additions, all as defined by the PBR formula or approved in a capital tracker application. The current performance based framework will set rates to December 31, 2017. In December 2016, the AUC issued its 2018-2022 PBR decision (Next Generation PBR) continuing the use of a performance based framework to December 31, 2022. EPCOR's electricity distribution rates for 2018 will be based on approved capital additions to the end of 2017 and actual operating and capital expenditures incurred during the 2013-2017 PBR term. The productivity factor in the Next Generation PBR term will be 0.3%, down from 1.16% currently. In addition, the Next Generation PBR decision also revised the criteria for capital tracker applications which will limit the volume of eligible capital projects. In November 2013, the AUC issued a decision in the Utility Asset Disposition Review proceeding directing that certain gains or losses due to extraordinary retirement of assets be borne by shareholders and not to be reflected in customer rates. In September 2015, the Alberta Court of Appeal (the Court) upheld the AUC's decision. The Company is responsible for ensuring that the potable water it sells to customers is safe to drink. Water Services performs continuous and rigorous quality control testing of water purification consistent with government and industry standards to prevent public health issues due to inadequately treated, stored or distributed drinking water. The ability of the water treatment plants to meet potable water quality standards is dependent on continuous water testing in order that the prescribed requirements under regulation or conventional industry standards are met. Failure to properly maintain fully functioning treatment and measurement systems could result in regulatory fines or the occurrence of public health issues. In Alberta, water quality for EPCOR's operations is regulated under the provincial Environmental Protection and Enhancement Act (EPEA). Regulation under the EPEA takes the form of an "Approval to Operate" which, among other things, specifies the quality of the treated water, the number, frequency and form of water quality testing, as well as mandatory standards for the water treatment process. The drinking water quality requirements in Alberta meet or exceed the National Guidelines for Canadian Drinking Water Quality recommended by Health Canada. Raw water quality is an important factor in the treatment of potable water. In Edmonton, we obtain surface water from the North Saskatchewan River to treat and sell to customers in the greater Edmonton area. The North Saskatchewan Watershed Alliance, among other things, aims to protect and improve North Saskatchewan River water quality by developing and sharing knowledge and facilitating workshops with members and interested parties. Drinking water quality and wastewater standards for EPCOR's U.S. operations are regulated by the U.S. Environmental Protection Agency (U.S. EPA) under the Safe Drinking Water Act and Clean Water Act, respectively. Among other things, the U.S. Environmental Protection Agency sets drinking water standards specifying the treatment, source water protection, operator training and funding for water system improvement and relies on the states and localities to carry out the standards. Oversight of water and wastewater systems is conducted by state and county authorities to the degree that they establish standards at least as stringent as the U.S. EPA. In Arizona, we obtain surface water primarily from the Central Arizona Project canal to treat and sell to customers. The Central Arizona Project conducts water quality testing upstream of the take-off points and has a formal notification process in place to notify our Arizona operations of any water quality issues that may arise. Process and compliance sampling results are stringently analyzed and trended for all groundwater and surface water systems in Arizona and New Mexico to ensure systems continue to meet all regulatory standards. Each system in Arizona and New Mexico has an Emergency Operations Plan which addresses water quality issues and provides further risk mitigation. There are no formal watershed protection groups in the Arizona and New Mexico service areas. The Arizona Department of Environmental Quality and New Mexico Environment Department oversee the water systems in their states, respectively. Water wells in Arizona, New Mexico and Texas are protected from contamination by proper well construction and system operation and management. Our operations have hazardous elements, such as high voltage electricity and hazardous chemicals that could have adverse health and safety consequences to our employees, on-site suppliers and customers. We manage health, safety and environment (HSE) risks through a management system and measure HSE performance against recognized industry and internal performance measures. We conduct external and internal compliance and conformance audits to verify that we meet or exceed all regulatory requirements. We are committed to working with industry partners to share and improve health, safety and environment practices within the industry. In 2016, all of our Edmonton water and wastewater treatment facilities, and electricity distribution and transmission operations remain OHSAS 18001 registered. We use several key information technology systems to support our core operations such as electricity and water distribution network control systems, electricity and water plant control systems and electricity settlement and utility billing systems. These systems and the associated hardware are vulnerable to malfunction and unauthorized access including cyber-attacks, which could lead to loss or unauthorized disclosure of sensitive customer or EPCOR information or extortion or otherwise disrupt operations. We take measures to reduce the risk of malicious corruption or failure of these systems, data and the hardware and network infrastructure on which they operate. EPCOR's security program is based on the ISO 27002 control framework. In applying this framework, EPCOR has implemented a series of complementary defense mechanisms, starting from the external IT perimeter down to the end user. Each layer is designed to prevent, detect and report on malicious activity. We regularly monitor our information technology protection systems and periodically employ third-party security providers to test the effectiveness and to strengthen the system as new cyber threats arise. Financial exposures associated with cyber-attacks are partly mitigated through our insurance programs. EPCOR has controls and strategies in place to mitigate the exposure to the various risks that could result in damage to EPCOR's reputation should an event occur. The company proactively maintains positive and transparent interactions with stakeholders. In addition, EPCOR communicates with stakeholders and the media when issues first arise and actively monitors social media in order to address reputational matters before they escalate. There are a variety of environmental risks associated with EPCOR's water and wastewater operations and its electricity distribution and transmission businesses. EPCOR's power and water operations are subject to laws, regulations, and operating approvals which are designed to reduce the impacts on the environment. An environmental event could materially and adversely impact EPCOR's business, prospects, reputation, financial condition, operations or cash flow. Furthermore, such incidents could result in spills or emissions in excess of those permitted by law, regulations or operating approvals. Environmental risks associated with water and wastewater operations include wastewater discharge, biogas release, and residuals management. EPCOR's wastewater operations are regulated with stringent wastewater treatment standards and controls covering quality of treated wastewater effluent as well as mandatory improvements to the wastewater treatment processes. Water and wastewater technologies and supporting processes are continuing to evolve and are influenced by more stringent regulation and environmental challenges. Failure to identify and deploy viable new technologies to meet these regulations and challenges could undermine the competitiveness of EPCOR's market position and exclude it from some market opportunities. Risks associated with electricity distribution and transmission operations include the unintended environmental release of substances such as oil from its oil-filled pipe-type cable, hydraulic oil and polychlorinated biphenyl transformer fluid. To the best of our knowledge we comply, in all material respects, with the laws, regulations and operating approvals affecting our facilities, and minimize the potential for incidents by incorporating environmental management practices in our strategy, policies, processes and procedures. To achieve this, we require each facility to have an environmental management system (EMS) which is based on the ISO 14001 standard. These systems encompass the identification of the scope, objectives, training and stewardship of our environmental responsibility. Each plant and facility is also subject to third party environmental audits to help ensure conformance with the EMS and compliance with all regulations. The Edmonton waterworks system (including the Rossdale and E.L. Smith water treatment plants) achieved EnviroVista Champion status as of June 2011. In 2016, all of our Edmonton water treatment facilities and reservoirs, the Gold Bar wastewater treatment plan, the Evan-Thomas water and wastewater treatment facility in Kananaskis, Alberta, our electricity distribution and transmission operations and our street lighting, traffic signal, light rail transit, hydrovac and cathodic protection operations remain ISO 14001 registered. The Company is also in the process of obtaining ISO 14001 registration for its Canadian water distribution and transmission operations. Compliance with future environmental legislation may require material capital and operating expenditures. Failure to comply could result in fines and penalties or the regulator could force the curtailment of operations. There can be no assurances that compliance with or changes to environmental legislation will not materially and adversely impact EPCOR's business, prospects, financial conditions, operations or cash flow. A variety of intentional, accidental or natural occurrences could cause interruption of EPCOR's operations and result in lost revenues or additional costs to resume operations including repair costs. Business interruption due to operational failure in Water Services and Distribution and Transmission is managed through inherent redundancy and sound maintenance practices. The quality of raw source water can be affected by such things as hydrocarbons and other inorganic or organic contaminants entering water ways and aquifers. Depending on the type and concentration of the contaminant, their removal may be beyond the capabilities of water treatment plant processes. This could result in the water treatment plants being shut down until the contaminants become diluted to the point where they can be treated within the water treatment plant capabilities. The ability of the water treatment plants to meet potable water quality standards is dependent on continuous water testing in order that the prescribed requirements under regulation or conventional industry standards are met. Failure to properly maintain fully functioning treatment and measurement systems could result in regulatory fines, lost revenue or the occurrence of public health issues. Our maintenance practices are augmented by an inventory of strategic spare parts, which can reduce down-time considerably in the event of power or water system interruptions. Maintenance and capital plans are determined annually based on rigorous assessment of its equipment and by continually monitoring the condition of assets. Although water and power facilities have operated in accordance with expectations, there can be no assurance that they will continue to do so. To the extent we experience insufficient raw water supply or extreme raw water conditions, delivery of water and associated revenues may be negatively affected. To the extent our electricity facilities experience outages due to equipment failure, blackouts or constraints on the transmission system, delivery of power and associated revenues may be negatively affected. The Company's business continuity plans aim to enable EPCOR to continue providing critical services to customers in the event a crisis. The Company's emergency response protocols are designed to ensure EPCOR can expeditiously resume operations following a business interruption. Financial exposures associated with business interruption are partly mitigated through our insurance programs. Our ability to continuously operate and grow the business is dependent upon attracting, retaining and developing sufficient labor and management resources. As with most organizations, the Company is facing the demographic shift where a large number of employees are expected to retire over the next few years. Failure to secure sufficient qualified technical and leadership talent may impact EPCOR's operations or increase expenses. We believe that we employ good human resource practices and in 2016, we were named a top 70 employer in Alberta, by Mediacorp Canada Inc. We continue to monitor developments and review our human resource strategies so that we have an adequate supply of labor and management. EPCOR plans to diversify its utility infrastructure investments across investment types and North American geographies to reduce investment risk. The Company is planning to accomplish this through expansion into natural gas distribution and its pursuit of the Drainage transfer from the City to EPCOR. These types of utility businesses are new to EPCOR which introduces risk to the Company due to unfamiliarity with the associated operational, safety and regulatory risks in addition to the risks associated with integrating these businesses into EPCOR. EPCOR develops comprehensive integration plans and ensures that personnel with appropriate skills are in place to manage all of the various risks when integrating any new businesses into the Company. Water scarcity is the risk of inadequate raw water supply, particularly in the desert region of the Southwestern U.S. This is primarily related to drought conditions which could potentially impact EPCOR's water operations in Arizona, New Mexico and Texas. In Arizona in particular, a number of water management and supply augmentation strategies are employed to mitigate this risk including enacting some very progressive policies to protect groundwater supplies. While EPCOR is not obligated to demonstrate long term water adequacy for new customer growth, EPCOR actively manages its sources of water including replenishing reserves by injecting water into its wells when opportunity arises and working with regulators on rate rebalancing to mitigate the effects of declining consumption should it occur. Despite these efforts, continued drought in the Southwestern U.S. could result in legislated measures to further reduce customer water consumption, potentially impacting financial performance in Arizona and New Mexico. EPCOR sells electricity to RRO customers under a RRT. All electricity for the RRO customers is purchased in real time from the AESO in the spot market. Under the RRT, the amount of electricity to be economically hedged, the hedging method and the electricity selling prices to be charged to these customers is determined by the EPSP. Under the EPSP, the Company uses financial contracts to economically hedge the RRO requirements and incorporate the price into customer rates for the applicable month. Fixed volumes of electricity are economically hedged using financial contracts-for-differences up to 120 days in advance of the month in which the electricity (load) is consumed by the RRO customers. The volume of electricity economically hedged in advance is based on load (usage) forecasts for the consumption month. When consumption varies from forecast consumption patterns, EPCOR is exposed to prevailing market prices when the volume of electricity economically hedged is short of actual load requirements or greater than the actual load requirements (long). Exposure to variances in electricity volume can be exacerbated by other events such as unexpected generation plant outages and unusual weather patterns. Under contracts-for-differences the Company agrees to exchange, with a single creditworthy and adequately secured counterparty, the difference between the AESO electricity spot market price and the fixed contract price for a specified volume of electricity up to 120 days in advance of the consumption date, all in accordance with the EPSP. The contracts-for-differences are referenced to the AESO electricity spot price and any movement in the AESO price results in changes in the contract settlement amount. If the risks of the EPSP were to become untenable, EPCOR could test the market and potentially re-contract the procurement risk under an outsourcing arrangement at a certain cost that would likely increase procurement costs and reduce margins. The Company may enter into additional financial electricity purchase contracts outside the EPSP to further economically hedge the price of electricity. Our construction and development of water and wastewater treatment facilities and electricity transmission and distribution infrastructure and acquisition activities are subject to various engineering, construction, stakeholder, government and environmental risks. These risks can translate into performance issues, delays and cost overruns. Project delays may defer expected revenues and project cost overruns could make projects uneconomic. Many of the water and wastewater growth projects currently pursued by the Company require design and construction capabilities that are provided by third parties. In order to pursue these projects, strategic partnerships have been established with reputable firms that have an established track record of infrastructure design and construction. Should these partnerships dissolve or are not recognized by the market as a viable approach, the Company's growth plans could potentially be curtailed. We attempt to mitigate project risks by performing detailed project analysis and due diligence prior to and during construction or acquisition, and by entering into appropriate contracts for various services to be provided as required. Our ability to complete projects successfully depends upon numerous factors such as weather, civil disobedience, availability of skilled labor, strikes and regulatory matters. Weather can have a significant impact on our operations. Melting snow, freeze / thaw cycles and seasonal precipitation in the North Saskatchewan River watershed affect the quality of water entering our Edmonton water treatment plants and the resulting cost of purification. Weather variability and seasonality also impact the demand and supply of water and electricity in our respective businesses in Canada and the U.S. Extreme weather can cause damage to electricity distribution and transmission equipment and wires, temporarily disrupting the reliable supply of power to customers and can cause unpredictability in the demand for power. Unseasonal temperature changes can cause water main breaks temporarily disrupting the reliable supply of water to customers. Weather that varies significantly from historical norms can result in changes in the quantity of provincial power consumption. EPCOR procures power to service its RRO customers in advance of the consumption month and the quantity procured is based on historical weather and usage patterns. Unseasonal temperatures can cause a mismatch between the power procured in advance of the consumption month and actual customer usage, resulting in unexpected variances in income from the RRO business. Financial exposures associated with extreme weather are partly mitigated through our insurance programs. EPCOR's internally generated cash flows from operating activities do not provide sufficient capital to undertake or complete ongoing or future development, enhancement opportunities or acquisition plans and accordingly, the Company requires additional financing from time to time. The ability of the Company to arrange such financing will depend in part upon prevailing market conditions at the time and the Company's business performance. If the Company's revenues or cash flows decline, it may not have the capital necessary to undertake or complete all the initiatives. There can be no assurance that debt or equity financing will be available or sufficient to meet these requirements or for other corporate purposes. Furthermore, if financing is available, there can be no assurance that it will be on terms acceptable to the Company. The inability of the Company to access sufficient capital for its operations could have a material adverse effect on the Company's business, prospects and financial condition. Further discussion is included in Liquidity and Capital Resources in this MD&A. The Company manages liquidity risk through regular monitoring of cash and currency requirements by preparing short-term and long-term cash flow forecasts and also by matching the maturity profiles of financial assets and liabilities to identify financing requirements. EPCOR's financial risks are governed by a Board-approved financial exposure management policy, which is administered by EPCOR's Treasurer. Counterparty and credit risk is the possible financial loss associated with the ability of counterparties to satisfy their contractual obligations to EPCOR, including payment and performance including the long-term loans receivable from Capital Power. We manage credit risk and limit exposures through our credit policies and procedures. These include an established credit review, rating and monitoring process, specific terms and limits, appropriate allowance provisioning and use of credit mitigation strategies, including collateral arrangements. EPCOR's credit risks are governed by a Board-approved counterparty credit risk management policy, which is administered by EPCOR's treasury function. Significant reliance is placed on the capacity of Capital Power to honor its remaining back-to-back debt obligations with EPCOR. Should Capital Power fail to satisfy these obligations, EPCOR's capacity to satisfy its debt obligations would be reduced and would need to be satisfied by other means. The back-to-back debt obligations may be called for repayment by EPCOR at any time now that the principal outstanding is less than $200 million and the repayment must occur within 180 days of notice. Capital Power has indemnified EPCOR for any losses arising from its inability to discharge its liabilities, including any amounts owing to EPCOR in relation to the long-term loans receivable. Exposure to credit risk for residential RRO customers and commercial customers under default electricity supply rates are generally limited to amounts due from the customers for electricity consumed but not yet paid for. This portfolio is reasonably well diversified with no significant credit concentrations. Historically, credit losses in these customer segments have not been significant and depend in large part on the strength of the economy and the ability of the customers to effectively manage their financial affairs through economic cycles and competitive pressures. While electricity is considered an essential service, EPCOR may experience credit losses in the future should economic conditions deteriorate. EPCOR's exposure to RRO and default customer credit risk, which is primarily the risk of non-payment for electricity consumed by these end-use customers, is summarized below. Exposures represent the accounts receivable value for this portfolio. The year-over-year decrease in exposure relates to lower customer rates and consumption. Exposures to credit risk in our rate-regulated and non-rated-regulated water businesses are generally limited to amounts due from the customers for water consumed and wastewater discharged but not yet paid for, as well as amounts for water management services provided under contracts to municipal and industrial customers. This portfolio is reasonably well diversified with no significant credit concentrations. While water is considered an essential service, EPCOR may experience credit losses in the future should economic conditions deteriorate. EPCOR's exposure to rate-regulated and non-rate-regulated customer credit risk, which is primarily the risk of non-payment for water consumed by these end-use customers, is summarized below. Exposures represent a 60-day potential accounts receivable value for this portfolio. The customer consumption data used to bill utility customers is voluminous plus the sources and types of customer billing data are varied, requiring large, complex systems to process customer billings. In addition, the Company relies on third parties to provide customer meter data in certain circumstances and to produce bills for its U.S. customers. All of this contributes to the potential for billing errors caused by poor customer consumption data quality, billing system computational errors, incorrect customer rates being used or transactions and adjustments being applied incorrectly to customer accounts. The Company applies numerous manual and automated controls to ensure the quality of customer billings including a routine to identify various exceptions in the electricity meter data used to produce bills. The Company is exposed to foreign exchange risk on foreign currency denominated transactions, firm commitments, monetary assets and liabilities denominated in a foreign currency and on its net investments in foreign entities. The Company's financial exposure management policy attempts to minimize economic and material transactional exposures arising from movements in the Canadian dollar relative to the U.S. dollar or other foreign currencies. The Company's direct exposure to foreign exchange risk arises on capital expenditure commitments denominated in U.S. dollars or other foreign currencies and U.S. operations. The Company coordinates and manages foreign exchange risk centrally, by identifying opportunities for naturally occurring opposite movements and then dealing with any material residual foreign exchange risks. The Company's exposure to foreign exchange risk on its investment in foreign entities is partially mitigated by foreign-denominated financing. The Company may use foreign currency forward contracts to fix the functional currency of its non-functional currency cash flows thereby reducing its anticipated U.S. dollar denominated transactional exposure. The Company looks to limit foreign currency exposures as a percentage of estimated future cash flows. Certain conflicts of interest could arise as a result of EPCOR's relationship with the City, EPCOR's sole common shareholder and regulator for water and wastewater utility rates in Edmonton. The following factors could materially adversely impact EPCOR's business, prospects, financial condition, results of operations or cash flows: fluctuations in interest rates, product supply and demand, market competition, risks associated with technology, general economic and business conditions, EPCOR's ability to make capital investments and the amounts of capital investments, risks associated with existing and potential future lawsuits and other regulations, assessments and audits (including income tax) against EPCOR and its subsidiaries, political and economic conditions in the geographic regions in which EPCOR and its subsidiaries operate, difficulty in obtaining necessary regulatory approvals, a significant decline in EPCOR's reputation and such other risks and uncertainties described from time to time in EPCOR's reports and filings with the Canadian Securities authorities. The following table outlines our estimated sensitivity to specific risk factors as at December 31, 2016. Each sensitivity factor provides a range of outcomes assuming all other factors are held constant and current risk management strategies are in place. Under normal circumstances, such sensitivity factors will not be held constant but rather, will change at the same time as other factors are changing. In addition, the degree of sensitivity to each factor will change as the Company's mix of assets and operations subject to these factors changes. The Company is not involved in any material litigation at this time. For purposes of certain Canadian securities regulations, EPCOR is a venture issuer. As such, it is exempt from certain of the requirements of National Instrument 52-109 Certification of Disclosure in Issuers' Annual and Interim Filings. The Chief Executive Officer and Chief Financial Officer have reviewed the annual information form, annual financial statements and annual MD&A, for the year ended December 31, 2016. Based on their knowledge and exercise of reasonable diligence, they have concluded that these materials fairly present in all material respects the financial condition, results of operations and cash flows of the Company for the periods presented. A number of new standards, amendments to standards and interpretations have been issued by the IASB and the International Financial Reporting Interpretations Committee the application of which is effective for periods beginning on or after January 1, 2017. Those which may be relevant to the Company and may impact the accounting policies of the Company are set out below. The Company does not plan to adopt these standards early. The extent of the impact of adoption of the standards has not yet been determined. IFRS 9 - Financial Instruments (IFRS 9), which replaces IAS 39 - Financial Instruments: Recognition and Measurement, eliminates the existing classification of financial assets and requires financial assets to be measured based on the business model in which they are held and the characteristics of their contractual cash flows. Gains and losses on re-measurement of financial assets at fair value will be recognized in profit or loss, except for an investment in an equity instrument which is not held-for-trading. Changes in fair value attributable to changes in credit risk of financial liabilities measured under the fair value option will be recognized in other comprehensive income with the remainder of the change recognized in profit or loss unless an accounting mismatch in profit or loss occurs at which time the entire change in fair value will be recognized in profit or loss. Derivative liabilities that are linked to and must be settled by delivery of an unquoted equity instrument must be measured at fair value. The impairment model has also been amended by introducing a new 'expected credit loss' model for calculating impairment, and new general hedge accounting requirements. The effective date for implementation of IFRS 9 has been set for annual periods beginning on or after January 1, 2018. IFRS 15 - Revenue from Contracts with Customers (IFRS 15), which replaces IAS 11 - Construction Contracts and IAS 18 - Revenue and related interpretations, is effective for annual periods commencing on or after January 1, 2018. IFRS 15 introduces a new single revenue recognition model for contracts with customers and two approaches to recognizing revenue: at a point in time or over time. The model features a contract-based five-step analysis of transactions to determine whether, how much and when revenue is recognized. New estimates and judgmental thresholds have been introduced, which may affect the amount and / or timing of revenue recognized. The requirements of the standard also apply to the recognition and measurement of gains and losses on sale of some non-financial assets that are not part of the entity's ordinary activities. IFRS 16 - Leases (IFRS 16), which replaces IAS 17 - Leases (IAS 17), is effective for annual periods commencing on or after January 1, 2019. IFRS 16 combines the existing dual model of operating and finance leases in IAS 17 into a single lessee model. Under the new single lessee model, a lessee will recognize lease assets and lease liabilities on the statement of financial position initially measured at the present value of unavoidable lease payments. IFRS 16 will also cause expenses to be higher at the beginning and lower towards the end of a lease, even when payments are consistent throughout the term. Leases for duration of twelve months or less and leases of low value assets are exempted from recognition on the statement of financial position. Lessors will continue with a dual lease classification model and the classification will determine how and when a lessor will recognize lease revenue and what assets will be recorded. In preparing the consolidated financial statements, management necessarily made estimates in determining transaction amounts and financial statement balances. The following are the items for which significant estimates were made in the financial statements. Due to the lag time between customer electricity consumption and receipt of final billing consumption information from the load settlement agents, the Company must use estimates for determining the amount of electricity consumed but not yet billed. These estimates affect accrued revenues and accrued electricity costs of the Energy Services segment. There are a number of variables and judgments required in the computation of these significant estimates, and the underlying electricity settlement processes within EPCOR and the Alberta electric systems are complex. Such variables and judgments include the number of unbilled sites, and the amount of and rate classification of the unbilled electricity consumed. Owing to the factors above and the statutory delays in final load settlement determinations and information, adjustments to previous estimates could be material. Estimates for unbilled consumption averaged approximately $51 million at the end of each month in 2016 (2015 - $53 million). These estimates varied from $35 million to $68 million (2015 - $42 million to $67 million). Adjustments of estimated revenues to actual billings were not higher than $5 million per month in 2016 (2015 - $6 million). We are required to estimate the fair value of certain assets or obligations for determining the valuation of certain financial instruments, asset impairments, asset retirement obligations and purchase price allocations for business combinations, and for determining certain disclosures. Significant judgment is applied in the determination of fair values including the choice of discount rates, estimating future cash flows, and determining goodwill. Following are the descriptions of the key fair value methodologies relevant for 2016. Fair values of financial instruments are based on quoted market prices when these instruments are traded in active markets. In illiquid or inactive markets, the Company uses appropriate price modeling to estimate fair value. Fair values determined using valuation models require the use of assumptions concerning the amounts and timing of future cash flows and discount rates. The Company reviews the valuation of long-lived assets subject to amortization when events or changes in circumstances may indicate or cause a long-lived asset's carrying amount to exceed the total undiscounted future cash flows expected from its use and eventual disposition. An impairment loss, if any, will be recorded as the excess of the carrying amount of the asset over its fair value, measured by either market value, if available, or estimated by calculating the present value of expected future cash flows related to the asset. Estimates of fair value for long-lived asset impairments are mainly based on depreciable replacement cost or discounted cash flow techniques employing estimated future cash flows based on a number of assumptions, including the selection of an appropriate discount rate. The cash flow estimates will vary with the circumstances of the particular assets or reporting unit and will primarily be based on the lives of the assets, revenues and expenses, including inflation, and required capital expenditures. EPCOR follows the asset and liability method of accounting for income taxes. Income taxes are determined based on estimates of our current taxes and estimates of deferred taxes resulting from temporary differences between the carrying values of assets and liabilities in the financial statements and their tax values. Deferred tax assets are assessed and significant judgment is applied to determine the probability that they will be recovered from future taxable income. For example, in estimating future taxable income, judgment is applied in determining the Company's most likely course of action and the associated revenues and expenses. To the extent recovery is not probable a deferred tax asset is not recognized. Estimates of the provision for income taxes and deferred tax assets and liabilities might vary from actual amounts incurred. Estimated fair values and useful lives are used in determining potential impairments for each long-lived asset, which will vary with each asset and market conditions at the particular time. Similarly, income taxes will vary with taxable income and, under certain conditions, with fair values of assets and liabilities. Accordingly, it is not possible to provide a reasonable quantification of the range of these estimates that would be meaningful to readers. Although the current condition of the economy has not impacted our methods of estimating accounting values, it has impacted the inputs in those determinations and the resulting values. Future cash flow estimates for assessing long-lived assets (cash generating units or CGUs) for impairment were updated to reflect any increased uncertainties of recoverability. The assessments did not result in any impairment losses because a large portion of the Company's long-lived assets are subject to rate-regulation. Similarly, the assessment of the useful lives of our long-lived assets did not change since many of our distribution and transmission assets and water assets are amortized based on rates approved by the applicable regulator. Our valuation models for estimating the fair value of long-lived asset impairments depend partly on discount rates which were updated to reflect changes in credit spreads and market volatility. Our methods for determining the allowance for doubtful accounts are based on historical rates of bad debts in relation to the aged accounts receivable balances by customer group for RRO and default customer bases. These analyses did not reveal any significant changes in our assessment of the recoverability of accounts receivable at December 31, 2016. For the three and twelve months ended December 31, 2016, the Company's transactions in other comprehensive income included the following: Events for the past eight quarters compared to the same quarter of the prior year that have significantly impacted net income included: The comparative information in the line of business information have been reclassified, where applicable, to conform to current year presentation. Certain information in this MD&A is forward-looking within the meaning of Canadian securities laws as it relates to anticipated financial performance, events or strategies. When used in this context, words such as "will", "anticipate", "believe", "plan", "intend", "target", and "expect" or similar words suggest future outcomes. The purpose of forward-looking information is to provide investors with management's assessment of future plans and possible outcomes and may not be appropriate for other purposes. Material forward-looking information within this MD&A, including related material factors or assumptions and risk factors, are noted in the table below: The following table provides a comparison between actual results and future-oriented-financial information previously disclosed: Whether actual results, performance or achievements will conform to the Company's expectations and predictions is subject to a number of known and unknown risks and uncertainties, which could cause actual results to differ from expectations and are discussed in the Risk Factors and Risk Management section above. Readers are cautioned not to place undue reliance on forward-looking statements as actual results could differ materially from the plans, expectations, estimates or intentions expressed in the forward-looking statements. Except as required by law, EPCOR disclaims any intention and assumes no obligation to update any forward-looking statement even if new information becomes available, as a result of future events or for any other reason. Additional information relating to EPCOR, including the Company's 2016 Annual Information Form, is available on SEDAR at www.sedar.com.


News Article | February 23, 2017
Site: www.marketwired.com

CALGARY, ALBERTA--(Marketwired - Feb. 23, 2017) - The Alberta Energy Regulator (AER) has released new requirements for heavy oil and bitumen operators in the Peace River area to control emissions of gas that contribute to offensive odours. The requirements are set out in Directive 084: Requirements for Hydrocarbon Emission Controls and Gas Conservation in the Peace River area. Directive 084 bans routine venting during the production of heavy oil, places strict limits on flaring, ensures that gas leaks are detected and repaired quickly, and prevents odours and emissions when heavy oil is transferred from tanks to trucks. Directive 084 was developed in response to the Report of Recommendations on Odours and Emissions in the Peace River Area, which followed a three-week inquiry in early 2014 that examined odours and emissions from heavy oil operations in the Peace River area. This inquiry resulted in 20 recommendations to the energy regulator and Government of Alberta. Over the past two years, the AER has made significant changes in the Peace River area, with more frequent inspections and more interaction with the community. The Alberta Energy Regulator ensures the safe, efficient, orderly, and environmentally responsible development of hydrocarbon resources over their entire life cycle. This includes allocating and conserving water resources, managing public lands, and protecting the environment while providing economic benefits for all Albertans. The Alberta Energy Regulator has brought in strict requirements for heavy oil producers in the Peace River area. The new directive was developed in response to a 2014 inquiry held in the community to address odours and emissions. The new rules give the AER enforcement tools to ensure that operators conserve at least 95 per cent of gas that would normally be vented, flared, or incinerated.


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

VANCOUVER, BC--(Marketwired - February 13, 2017) - Zadar Ventures Ltd. (TSX VENTURE: ZAD) (FRANKFURT: ZAV) (OTCQB: ZADDF) (the "Company") is pleased to announce that it has entered into negotiations with a private Alberta Company to evaluate the purchase of a portfolio of Canadian PetroBrine Projects. PetroBrines are considered to be saline formational waters associated with petroleum production which could potentially be utilized as feedstock for mineral extraction, including Li (lithium). The Company intends to explore this new opportunity in an ever growing Lithium market. Canadian Oil and Gas well operators have long reported Lithium values ranging from 80 mg/l to 140 mg/l as referenced by the geoScout Oil & Gas Industry database as reported by well operators and monitored by the Government of Alberta. There are other Provincial Geological Survey reports throughout Canada that reference brines, within these same lithium concentration ranges, in areas associated with oil production. Company President Paul D. Gray, P.Geo. Commented "We are excited to get involved in a relatively new area of Lithium exploration. The demand for low cost Lithium production is going to be the key in the ever growing energy storage space, and Zadar intends to stay out front of this rapidly developing space." The Company intends to complete its Due Diligence and enter into a definitive agreement within the next 45 days. Zadar also announces it has set 500,000 incentive stock options at a price of $0.10 cents for a period of two years. Zadar Ventures Ltd. is a Resource Company focused on the acquisition and exploration of economically viable green energy resources in jurisdictions favorable to mining and industry. For more information we invite you to visit the company's website at www.zadarventures.com This news release has been reviewed and approved by Mr. Paul D. Gray, P.Geo., who is the Company's qualified person as defined by National Instrument 43-101. ON BEHALF OF THE BOARD OF DIRECTORS Neither the TSX Venture Exchange nor its Regulation Service Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this release. This press release may contain certain forward-looking information. All statements included herein, other than statements of historical fact, forward-looking information and such information involves various risks and uncertainties. There can be no assurance that such information will prove to be accurate, and actual results and future events could differ materially from those anticipated in such information. A description of assumptions used to develop such forward-looking information and a description of risk factors that may cause actual results to differ materially from forward-looking information can be found in the company's disclosure documents on the SEDAR website at www.sedar.com. The company does not undertake to update any forward-looking information except in accordance with applicable securities laws.


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

TORONTO, ONTARIO--(Marketwired - Feb. 28, 2017) - Capstone Infrastructure Corporation (TSX:CSE.PR.A) (the "Corporation") today reported audited results for the fiscal year and fourth quarter ended December 31, 2016. The Corporation's 2016 Management's Discussion and Analysis and audited consolidated financial statements are available at www.capstoneinfrastructure.com and on SEDAR at www.sedar.com. All amounts are in Canadian dollars. Capstone had an eventful 2016, repositioning itself as a pure play independent power producer. This was marked by significant changes to the senior management team, along with the sale of Bristol Water and taking steps that ultimately led to a binding agreement to sell Capstone's investment in Värmevärden. Capstone successfully completed four wind facilities, on time and on budget, adding 37 MW net installed capacity to the power portfolio. The legal process with the OEFC was concluded with Capstone receiving retroactive payment for amounts owing. In addition, Capstone completed several financings during the year which supported the ongoing development of the power portfolio. Adjusted EBITDA was $10.6 million, or 9%, higher in 2016. The power segment was the main driver behind these results which were attributable to the net OEFC proceeds awarded for retroactive payments to Cardinal and the Ontario hydro facilities, contributions from four new wind facilities, the full year impact of two facilities built partway through 2015 as well as favourable hydrology conditions. Adjusted Funds from Operations (AFFO) was $12.3 million, or 110%, higher in 2016. The increase was primarily due to higher Adjusted EBITDA and lower corporate interest paid resulting from the settlement of the convertible debentures and corporate credit facility on April 29, 2016, partially offset by higher debt service payments at the power segment for new debt at Cardinal and CPC, as well as lower dividends from Bristol Water. Excluding discontinued operations, and large one-time items in 2016 for: a) costs related to the iCON Infrastructure Partners III, L.P. ("ICON III") acquisition and related staff costs, and b) the net OEFC proceeds awarded to Cardinal and the Ontario hydro facilities, Adjusted EBITDA from continuing operations was $19.4 million, or 34%, higher in 2016. Adjusted Funds from Operations (AFFO) from continuing operations excluding one-time items was $10.3 million, or 322%, higher in 2016. The strong results demonstrate the year-on-year growth of Capstone's power segment and improved hydrology, wind and solar resource across the portfolio. Consolidated revenue for the year increased by $54.9 million, or 47%, due to higher power segment revenue primarily due to the net OEFC proceeds awarded for retroactive payments to Cardinal and the Ontario hydro facilities, contributions from new wind facilities and higher production from more favourable resource conditions from the hydro facilities. This was partially offset by lower revenue at Whitecourt due to lower merchant power rates in Alberta. Total expenses increased by $32.7 million, or 55%, primarily due to higher power segment operating expenses due to a one time increase in fuel expenses directly related to contractual obligations from the OEFC settlement, expenses from new wind facilities, higher non-recurring staff costs associated with the iCON III acquisition and higher corporate development costs also related to the iCON III acquisition. During the fourth quarter of 2016, revenue increased by $7.3 million, or 22%, due to higher power segment revenue, primarily because of contributions from the new wind facilities. Expenses decreased by $1.2 million, or 7%, primarily due to lower costs related to the strategic review conducted in 2015 and lower staff costs, partially offset by higher power segment operating expenses mainly due to the new wind facilities and professional fees. Adjusted EBITDA in the quarter increased by $1.1 million, or 4%, reflecting the factors noted above. Fourth quarter AFFO increased by $3.3 million, or 174%, related to Adjusted EBITDA factors and lower corporate interest paid due to the settlement of the convertible debentures and corporate credit facility on April 29, 2016. As at December 31, 2016, the Corporation had unrestricted cash and cash equivalents of $62.2 million, including $56.0 million at the power segment which is accessible to Capstone through distributions and $6.2 million in total cash and cash equivalents available for general corporate purposes. On February 8, 2017, Whitecourt, Capstone's biomass facility, was notified that the Government of Alberta approved its application to the Bioenergy Producer Program ("BPP"). Whitecourt expects to receive grants of up to $4.8 million for contributing to Alberta's bioenergy production capacity over the 18 month program, ending September 30, 2017. On February 21, 2017, Capstone announced that, alongside its co-shareholder Macquarie European Infrastructure Fund 2 ("MEIF 2"), it has agreed to sell 100% of the Värmevärden group ("Värmevärden). Capstone expects to receive approximately $140 million in net proceeds for its 33.3% indirect interest in Värmevärden. A portion of the proceeds from the sale will be used to eliminate the remaining outstanding balance of the promissory note issued by Capstone to Irving Infrastructure Corp. on April 29, 2016. On February 28, 2017, Capstone's electricity purchase agreement for the Sechelt Creek facility with BC Hydro was extended from its original expiry on an interim basis. The interim arrangement, and any new or amended electricity purchase agreement that may be entered, is expected to provide a lower price for electricity supplied than was paid under the expiring contract and would generate lower revenues than in 2016. The Board of Directors today declared a quarterly dividend on the Corporation's Cumulative Five-Year Rate Reset Preferred Shares, Series A (the "Preferred Shares") of $0.2044 per Preferred Share to be paid on or about April 28, 2017 to shareholders of record at the close of business on April 14, 2017. The dividend on the Preferred Shares covers the period from January 31, 2017 to April 29, 2017. The dividends paid by the Corporation on its Preferred Shares are designated "eligible" dividends for the purposes of the Income Tax Act (Canada). An enhanced dividend tax credit applies to eligible dividends paid to Canadian residents. Capstone's mission is to provide investors with an attractive total return from responsibly managed long-term investments in power generation in North America. The Corporation's strategy is to develop, acquire and manage a portfolio of high quality power businesses that operate in a contractually-defined environment and generate stable cash flow. Capstone currently owns, operates and develops thermal and renewable power generation facilities in North America with a total installed capacity of net 505 megawatts. Please visit www.capstoneinfrastructure.com for more information. Certain of the statements contained within this document are forward-looking and reflect management's expectations regarding the future growth, results of operations, performance and business of Capstone Infrastructure Corporation (the "Corporation") based on information currently available to the Corporation. Forward-looking statements are provided for the purpose of presenting information about management's current expectations and plans relating to the future and readers are cautioned that such statements may not be appropriate for other purposes. These statements use forward-looking words, such as "anticipate", "continue", "could", "expect", "may", "will", "intend", "estimate", "plan", "believe" or other similar words, and include, among other things, statements found in "Results of Operations" and "Financial Position Review". These statements are subject to known and unknown risks and uncertainties that may cause actual results or events to differ materially from those expressed or implied by such statements and, accordingly, should not be read as guarantees of future performance or results. The forward-looking statements within this document are based on information currently available and what the Corporation currently believes are reasonable assumptions, including the material assumptions set out in the management's discussion and analysis of the results of operations and the financial condition of the Corporation ("MD&A") for the year ended December 31, 2016 under the headings "Changes in the Business", "Results of Operations" and "Financial Position Review", as updated in subsequently filed MD&A of the Corporation (such documents are available under the Corporation's SEDAR profile at www.sedar.com). Other potential material factors or assumptions that were applied in formulating the forward-looking statements contained herein include or relate to the following: that the business and economic conditions affecting the Corporation's operations will continue substantially in their current state, including, with respect to industry conditions, general levels of economic activity, regulations, weather, taxes and interest rates; that the preferred shares will remain outstanding and that dividends will continue to be paid on the preferred shares; that there will be no further material delays in the Corporation's wind development projects achieving commercial operation; that the Corporation's power infrastructure facilities will experience normal wind, hydrological and solar irradiation conditions, and ambient temperature and humidity levels; that there will be no material changes to the Corporation's facilities, equipment or contractual arrangements; that there will be no material changes in the legislative, regulatory and operating framework for the Corporation's businesses; that there will be no material delays in obtaining required approvals for the Corporation's power infrastructure facilities or Värmevärden; that there will be no material changes in environmental regulations for the power infrastructure facilities or Värmevärden; that there will be no significant event occurring outside the ordinary course of the Corporation's businesses; the refinancing on similar terms of the Corporation's and its subsidiaries' various outstanding credit facilities and debt instruments which mature during the period in which the forward-looking statements relate; market prices for electricity in Ontario and the amount of hours that Cardinal is dispatched; the price that Whitecourt will receive for its electricity production considering the market price for electricity in Alberta, the impact of renewable energy credits, and Whitecourt's agreement with Millar Western, which includes sharing mechanisms regarding the price received for electricity sold by the facility; the re-contracting of the power purchase agreement ("PPA") for Sechelt; and that there will be no material changes to the Swedish krona to Canadian dollar exchange rate. Although the Corporation believes that it has a reasonable basis for the expectations reflected in these forward-looking statements, actual results may differ from those suggested by the forward-looking statements for various reasons, including: risks related to the Corporation's securities (dividends on preferred shares are not guaranteed; volatile market price for the Corporation's preferred shares; and subordination and absence of covenant protection); risks related to the Corporation and its businesses (availability of debt and equity financing; default under credit agreements and debt instruments; geographic concentration; foreign currency exchange rates; acquisitions, development and integration; environmental, health and safety; changes in legislation and administrative policy; and reliance on key personnel); risks related to the Corporation's power infrastructure facilities (market price for electricity; power purchase agreements; completion of the Corporation's wind development projects; operational performance; contract performance and reliance on suppliers; land tenure and related rights; environmental; and regulatory environment); and risks related to Värmevärden (operational performance; fuel costs and availability; industrial and residential contracts; environmental; regulatory environment; and labour relations). For a comprehensive description of these risk factors, please refer to the "Risk Factors" section of the Corporation's Annual Information Form dated March 29, 2016, as supplemented by disclosure of risk factors contained in any subsequent annual information form, material change reports (except confidential material change reports), business acquisition reports, interim financial statements, interim management's discussion and analysis and information circulars filed by the Corporation with the securities commissions or similar authorities in Canada (which are available under the Corporation's SEDAR profile at www.sedar.com). The assumptions, risks and uncertainties described above are not exhaustive and other events and risk factors could cause actual results to differ materially from the results and events discussed in the forward-looking statements. The forward-looking statements within this document reflect current expectations of the Corporation as at the date of this document and speak only as at the date of this document. Except as may be required by applicable law, the Corporation does not undertake any obligation to publicly update or revise any forward-looking statements. This document is not an offer or invitation for the subscription or purchase of or a recommendation of securities. It does not take into account the investment objectives, financial situation and particular needs of any investors. Before making an investment in the Corporation, an investor or prospective investor should consider whether such an investment is appropriate to their particular investment needs, objectives and financial circumstances and consult an investment adviser if necessary.


News Article | February 17, 2017
Site: www.accesswire.com

VANCOUVER, BC / ACCESSWIRE / February 17, 2017 / Victory Ventures Inc. (TSXV: "VVN") ("Victory" or the "Company") announces it has changed its name to "Power Americas Minerals Corp." Management feels the new name will better reflect the Company's current exploration focus on cobalt, lithium, and other energy metals. The Company has received TSX Venture Exchange approval to its proposed name change. Effective February 17, 2017, the Company's common shares will commence trading under the new name Power Americas Minerals Corp. and under its new trading symbol PAM. The new CUSIP number is 739193100 and the new ISIN number is CA739931002. There is no consolidation of share capital. The Company believes that the demand profile for Cobalt, Lithium and other essential power related materials will be fundamentally led by the growing adaptation of electric vehicles, renewable energy and increased production of super alloys. With a focus on identifying and developing ethically sourced materials within the Americas, the Company intends to address the growing demand for energy metals that are being driven by innovation and the introduction of new technologies. In other news, the Company's Exploration Program (see news release 01-11-17) is underway on its 100% owned Spirit River Lithium Project, located northwest of the Fox Creek-Swan Hills area in the Peace River District of Alberta Canada. The Spirit River Lithium Project totals approximately 36,800 hectares (91,000 acres), or about 400 square kilometers (144 square miles). The Project hosts more than 800 oil and gas well sites within the Spirit River property area, some of which contain known elevated lithium values as documented historically in publicly available Government of Alberta reports. APEX Geoscience Ltd. of Edmonton AB., is supervising and conducting the brine sampling program in conjunction with several oil and gas producers in the region. Finally, initial compilation and planning has begun on the Company's Kittson Colbalt Property's (see news release 01-23-17) upcoming exploration and drill program. The Kittson Cobalt Property is located within the prolific Cobalt mining camp, which has produced over 420 million ounces of silver. The Property includes two former mines, the Shakt Davies and Cobalt Kittson. These two mines saw limited production and differed from the typical Cobalt camp in that they possessed low silver grades, but were enriched in cobalt and gold. The technical content of this news release has been reviewed and approved by James Place, P. Geo., a director of the Company, and a qualified person as defined by National Instrument 43-101. On behalf of the Board of Directors: For more information please contact: Howard Milne V.P. Business Development Tel: (604) 377-8994 Email: [email protected] Website: www.victoryventures.ca Victory Ventures Inc. is a Canadian-based junior mining exploration company focused on the procurement, exploration and development of cobalt, lithium, and other energy metals in North and South America. The Company's shares are listed and posted for trading on the TSX Venture Exchange under the symbol "VVN" and on the Frankfurt Exchange under the symbol "VV0". Neither TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this release. NOT FOR DISSEMINATION IN THE UNITED STATES

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